ROWAN COMPANIES PLC (Form: 10-K, Received: 03/02/2015 18:03:50)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K



þ	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2014

OR

¨	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

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 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 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 $3.9 billion as of June 30, 2014, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange Composite Tape of $31.93 per share.

The number of Class A ordinary shares, $0.125 par value, outstanding at January 31, 2015 , excluding shares held by the Company's employee benefit trust, was 124,569,727.

DOCUMENTS INCORPORATED BY REFERENCE



Document	Part of Form 10-K
Portions of the Proxy Statement for the 2015 Annual General Meeting of Shareholders	Part III, Items 10-14

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TABLE OF CONTENTS



	Page
PART I
Item 1. Business	3
Item 1A. Risk Factors	8
Item 1B. Unresolved Staff Comments	19
Item 2. Properties	20
Item 3. Legal Proceedings	21
Item 4. Mine Safety Disclosures	21
Executive Officers of the Registrant	21

PART II
Item 5. Market for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities	21
Item 6. Selected Financial Data	25
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	26
Item 7A. Quantitative and Qualitative Disclosures about Market Risks	39
Item 8. Financial Statements and Supplementary Data	40
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	83
Item 9A.Controls and Procedures	83
Item 9B. Other Information	84

PART III
Item 10. Directors, Executive Officers and Corporate Governance	84
Item 11. Executive Compensation	84
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	84
Item 13. Certain Relationships and Related Transactions, and Director Independence	85
Item 14. Principal Accounting Fees and Services	85

PART IV
Item 15. Exhibits and Financial Statement Schedules	86

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FORWARD-LOOKING STATEMENTS

Statements contained in this report 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 performance; dividend and share repurchases; growth strategies; expected utilization, day rates, revenues, operating expenses, contract terms, contract backlog, capital expenditures, tax rates and positions, insurance coverages, access to financing and funding sources; the availability, delivery, mobilization, contract commencement, relocation or other movement of rigs and the timing thereof; future rig construction (including construction in progress and completion thereof), 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; future operations; the impact of increasing regulatory requirements and complexity; expected contributions from our new rigs and our entry into the ultra-deepwater market; divestiture of selected assets; expense management; the likely outcome of legal proceedings or insurance or other claims and the timing thereof; activity levels in the offshore drilling market; customer drilling programs; 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;


•	changes in worldwide rig supply and demand, competition or technology, including as a result of delivery of newbuild drilling rigs and reactivation of rigs;


•	variable levels of drilling activity and expenditures, whether as a result of actions by OPEC, global capital markets and liquidity, prices of oil and natural gas or otherwise, which may cause us to idle or stack additional rigs;

•

drilling permit and operations delays, moratoria or suspensions, new and future regulatory, legislative or permitting requirements (including requirements related to certification and testing of blowout preventers and other equipment or otherwise impacting operations), future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill contingency plan requirements and other governmental actions that may result in claims of force majeure or otherwise adversely affect our existing drilling contracts;


•	governmental regulatory, legislative and permitting requirements affecting drilling operations or compliance obligations in the areas in which our rigs operate;


•	tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;

•

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 limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to weather conditions or otherwise, and the limited availability or high cost of insurance coverage for certain offshore perils or associated removal of wreckage or debris and other losses;


•	access to spare parts, equipment and personnel to maintain, upgrade and service our fleet;


•	possible cancellation or suspension of drilling contracts as a result of economic conditions in the industry, force majeure, mechanical difficulties, delays, performance or other reasons;


•	potential cost overruns and other risks inherent to shipyard rig construction, repair or enhancement, unexpected delays in rig and equipment delivery and engineering or design issues following shipyard delivery, or delays in the dates our rigs will enter a shipyard, be transported and delivered, enter service or return to service;


•	changes or delays in actual contract commencement dates; contract terminations, contract extensions, contract option exercises, contract revenues, contract awards; the termination of contracts or renegotiation of contract terms by customers or payment or operational delays by our customers;


•	potential cost overruns or delays in delivery of our remaining drillships under construction, including delays in leaving the shipyard, delays or other issues relating to customer acceptance or readiness to drill;

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•	operating hazards, including environmental or other liabilities, risks, expenses or losses, whether related to well-control issues, or storm or hurricane damage, losses or liabilities (including wreckage or debris removal), collisions, or otherwise;


•	our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to competition from other contract drillers, labor regulations 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, political demonstrations, strikes, or outbreak or escalation of armed hostilities or other crises in oil or natural gas producing areas in which we operate, which may result in extended business interruptions, suspended operations, or claims by our customers of a force majeure situation and payment disputes;


•	terrorism, piracy, cyber-breaches, outbreaks of any disease or epidemic and other related travel restrictions, political instability, hostilities, acts of war, nationalization, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in any of our areas of operations;

•

the outcome of legal proceedings, or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, any purported renegotiation, nullification, cancellation or breach of contracts with customers or other parties, and any failure to negotiate or complete definitive contracts following announcements of receipt of letters of intent;


•	potential for additional long-lived asset impairments;


•	impacts of any global financial or economic downturn;


•	effects of accounting changes and adoption of accounting policies;


•	potential return to shareholders in the form of dividends and share repurchases;


•	costs and uncertainties associated with our redomestication, or changes in laws that could reduce or eliminate the anticipated benefits of the transaction;


•	potential unplanned expenditures and funding requirements, including investments in pension plans and other benefit plans; and


•	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.

PART I

ITEM 1. BUSINESS

On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (Rowan plc), became the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies and our place of incorporation was effectively changed from Delaware to the United Kingdom. We remain subject to the Securities and Exchange Commission (SEC) reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable listing standards of the New York Stock Exchange (NYSE), and we continue to report our consolidated financial results in U.S. dollars and in accordance with United States generally accepted accounting principles (US GAAP). We must also comply with additional reporting requirements under English law. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values

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of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the terms “Rowan,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) are made available free of charge on our website at www.rowancompanies.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. 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.

Overview

We are a global provider of offshore oil and gas contract drilling services utilizing a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, one of which is currently under construction. Prior to 2009, our primary focus had been on high-specification and premium jack-up rigs, which our customers use for exploratory and development drilling and associated drilling services. In 2009 we embarked on a new strategic plan that included divesting non-core assets and investing in ultra-deepwater assets with a goal of balancing earnings from jack-ups and deepwater rigs over the long term. In 2011 we completed the sales of our manufacturing and land drilling businesses, and in 2011 and 2012 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction of four ultra-deepwater drillships. In January 2014 we took delivery of the first of these drillships, the Rowan Renaissance, which commenced drilling operations in April 2014. The Rowan Resolute was delivered in July 2014 and commenced operations in October 2014. The Rowan Reliance was delivered in November 2014 and commenced operations in February 2015. The Rowan Relentless is scheduled for delivery in late March 2015 and expected to commence operations in the third quarter of 2015. All four drillships are under contract.

We conduct offshore drilling operations in various markets throughout the world including the United States Gulf of Mexico (US GOM), United Kingdom (U.K.) and Norwegian sectors of the North Sea, the Middle East, West and North Africa, Southeast Asia and Trinidad. Our revenues and assets by geographic area are presented in Note 12 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.

For the year ended December 31, 2014 , we generated revenues of $1.8 billion and an operating loss of $167 million , compared to revenues of $1.6 billion and operating income of $332 million in 2013 . Operating loss for 2014 includes noncash asset impairment charges totaling $574 million. Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

Drilling Fleet

Our jack-ups are capable of drilling wells to maximum depths ranging from 25,000 to 40,000 feet and in maximum water depths ranging from 250 to 550 feet, depending on rig size and location. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean floor, and the hull is jacked up to the elevation required to drill the well. Our ultra-deepwater drillships are capable of drilling wells to maximum depths of 40,000 feet and in maximum water depths of 12,000 feet.

We have aggressively grown our jack-up fleet in recent years to better serve the needs of the industry and are particularly well positioned to serve the niche market for high-pressure/high-temperature (HPHT) wells. All of our rigs feature top-drive drilling systems, solids-control equipment, AC power and mud pumps that accelerate the drilling process. Our drilling fleet consists of the following:


•	Three ultra-deepwater drillships delivered in 2014 and currently operating under contract plus one ultra-deepwater drillship that is currently under construction and scheduled for delivery in late March 2015;


•	Nineteen high-specification cantilever jack-up rigs, including one Gorilla class rig, three N-Class rigs, four enhanced Super Gorilla class rigs, four Tarzan Class rigs, three 240C class rigs, and four EXL class rigs, as described below. We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds.


•	Eight premium cantilever jack-up rigs, including two Gorilla class rigs and six 116-C class rigs. We use the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments.


•	Three conventional or slot jack-up rigs with skid-off capability, all of which are cold-stacked.

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Our ultra-deepwater drillships are self-propelled vessels equipped with computer-controlled dynamic-positioning thruster systems, which allow them to maintain position without anchors through the use of their onboard propulsion and station-keeping systems. Drillships have greater variable deck loading capacity than semisubmersible rigs, enabling them to carry more supplies on board 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 some parts of the well, 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 and are capable of drilling to 40,000-foot well 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.

Cantilever jack-ups can extend a portion of the sub-structure containing the drilling equipment over fixed production platforms to perform drilling operations with a minimum of interruption to production. Our conventional jack-ups use “skid-off” technology, which allows the rig floor drilling equipment to be “skidded” out over the top of a fixed platform, enabling these slot type jack-up rigs to be used on drilling assignments that would otherwise require a cantilever jack-up or platform rig.

Our three Gorilla class rigs, designed in the early 1980s as a heavier-duty class of jack-up rig, are capable of operating in water depths up to 328 feet in extreme hostile environments (winds up to 100 miles per hour and seas up to 90 feet) such as the North Sea. The Rowan Gorilla II and III can drill to 30,000 feet, and the Rowan Gorilla IV is equipped to drill to 35,000 feet.

Three of our four Super Gorilla class rigs were delivered during the period from 1998 to 2002 and are enhanced versions of our Gorilla class rigs that can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water south of the 61 ^st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents. The Bob Palmer, which was delivered in 2003, is the fourth Super Gorilla class rig, 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 three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet with 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 2011.

Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet with 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 N-Class rigs are capable of drilling up to 35,000 feet in harsh environments such as the North Sea and in maximum water depths of approximately 450 feet depending on location. The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously. Our first N-Class rig, the Rowan Viking , was delivered in 2010, and the Rowan Stavanger and Rowan Norway were delivered in 2011.

See Item 2, “Properties,” for additional information regarding our fleet.

Our operations are subject to many uncertainties and hazards. See Item 1A, “Risk Factors,” for additional information.

Contracts

Our drilling contracts generally provide for a fixed amount of compensation per day (day rate), and are either “well-to-well,” “multiple-well” or "fixed-term" generally ranging from one month to several years. Well-to-well contracts are typically cancellable by either party upon completion of drilling. Fixed-term contracts usually 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

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at the time they are incurred. Our contracts for work in foreign countries generally provide for payment in United States (U.S.) dollars except for amounts required by applicable law to be paid in the local currency or amounts required to meet local expenses.

A number of factors affect our ability to obtain contracts at profitable rates within a given area. Such factors, which are discussed further under “Competition” and in "Risk Factors" include, among other things, the price of oil and gas which can affect our customers' drilling budgets, 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 an attempt to keep our rigs working. At times, however, market conditions have forced us to "cold-stack" rigs rather than make the substantial improvements required to secure ongoing work. As of February 19, 2015 , we had three cold-stacked rigs in the US GOM.

Our contract backlog was estimated to be approximately $5.1 billion at February 19, 2015 , up slightly from approximately $5.0 billion at February 20, 2014 . See “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K for further information with respect to 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 545 jack-up rigs available worldwide as of February 16, 2015. We estimate that 69 or 13 percent of the world’s existing jack-up fleet are high-specification, including our 19 high-specification rigs. Newbuild deliveries of jack-ups in recent years have increased the pool of rigs competing for contracts in many areas in which we operate, putting significant downward pressure on utilization and day rates. As of February 16, 2015, there were approximately 132 jack-up rigs under construction worldwide for delivery through 2017 (24 percent of the current jack-up fleet), including 53 that are considered high-specification (77 percent of the current high-specification fleet). Approximately 22 of these jack-up rigs, which are not contracted, are scheduled for delivery in 2015. Utilization and day rates in certain regions are expected to come under additional pressure as these rigs enter the worldwide fleet.

At February 16, 2015, there were 119 drillships operating worldwide plus another 57 under construction or on order for delivery through 2020, including our fourth drillship under construction. We estimate that 84, or approximately 71 percent of the world’s existing drillship fleet, are capable of drilling in water depths of 10,000 feet or more, and nearly all of those under construction will have 10,000-foot water depth capabilities. Drillship utilization and day rates are expected to come under additional pressure as newly constructed drillships enter the market.

Based on the number of rigs as tabulated by IHS-Petrodata, we are the ninth largest offshore drilling contractor in the world and the sixth largest jack-up rig operator. Based on the most recent publicly available information, we are the sixth largest publicly traded offshore drilling contractor ranked by revenues. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.

We market our drilling services to present and potential customers, including large international energy companies, smaller independent energy companies and foreign government-owned or government-controlled energy companies. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K for a discussion of current and anticipated industry conditions and their impact on our operations.

Governmental Regulation

Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. In addition, the U.K., the U.S. and other countries in which we operate have regulations relating to environmental protection and pollution control. We could become liable for damages resulting from pollution of offshore waters in some circumstances, and in certain jurisdictions we must document financial responsibility.

Generally, we are indemnified under our drilling contracts for pollution, well damage and environmental damage, except in certain cases of pollution emanating above the surface of water from spills of pollutants emanating from our drilling rigs. This indemnity includes all costs associated with regaining control of a wild well, removal and disposal of pollutants, environmental remediation

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and claims by third parties for damages. Such contractual indemnification provisions may not, however, adequately protect us for several reasons including: (a) the contractual indemnity provisions may require us to assume a portion of the liability; (b) our customers may not have financial resources necessary to honor the contractual indemnity provisions; and (c) the contractual indemnity provisions may be unenforceable under applicable law.

Our customers often require us to assume responsibility for pollution damages where we are at fault. We seek to limit our liability exposure to a non-material amount, or an amount within the limits of our available insurance coverage. For example, a contract may provide that we will assume the first $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 for all of our contracts or that such indemnification and/or limitation of liability provisions can be enforced or will be sufficient. Our customers may challenge the validity or enforceability of the indemnity provision for several reasons, including but not limited to applicable law, judicial decisions, the language of the indemnity provision, reasons of public policy, degree of fault and/or the circumstances resulting in the pollution.

In the event of an incident resulting in wellbore pollution and a customer who is unable or unwilling to honor its indemnity obligation, the impact on our financial position, operations and liquidity would depend on the scope of the incident. In this instance, we would seek to enforce our legal rights, including the enforcement of the indemnity obligation and redress from all parties at fault. In addition, we maintain limited insurance for liability related to negative environmental impacts of a sudden and accidental pollution event, as described below. If both insurance and indemnity protection were unavailable or insufficient and the incident was significant, there could be a material adverse effect on our results of operations, financial position and cash flows.

Pursuant to the Clean Water Act, a National Pollutant Discharge Elimination Permit (NPDES permit) is required for discharges into the US GOM. As a contract driller in the US GOM, we operate in accordance with the NPDES permit regardless of the holder. According to the NPDES permit, the permit holder is the designated responsible party and is thus responsible for any environmental impacts that would occur in the event of the discharge of any unpermitted substance, including a fuel spill or oil leak from an offshore installation such as a mobile drilling unit.

Pursuant to the UK Offshore Directive, which comes into force July 19, 2015, we will be required to have an Oil Pollution Emergency Plan (OPEP) for each of our drilling units operating in UK waters. The UK Offshore Directive also specifies additional regulations related to safety, licensing, environmental protection, emergency response and liability.

Additionally, pursuant to the International Maritime Organization (IMO), we are required to have a Shipboard Oil Pollution Emergency Plan (SOPEP) for each of our drilling units. Our SOPEP establishes detailed procedures for rapid and effective response to spill events that may occur as a result of our operations or those of the operator. This plan is reviewed annually and updated as necessary. Onboard drills are conducted periodically to maintain effectiveness of the plan, and each rig is outfitted with equipment to respond to minor spills. The drills include participation of key personnel, spill response contractors and representatives of governmental agencies. For operations in the United States, our SOPEPs are subject to review and approval by various organizations including the United States Coast Guard, the EPA and the Bureau of Safety and Environmental Enforcement (BSEE), and are recertified every five years by the American Bureau of Shipping, a Recognized Organization under the IMO.

As the designated responsible party, the operator has the primary responsibility for spill response, including having contractual arrangements in place with emergency spill response organizations to supplement any onboard spill response equipment. Pursuant to our SOPEPs, we have certain resources and supplies onboard our rigs which would be used to mitigate the impact of an incident until an emergency spill response organization could deploy its resources. However, we also have an agreement with an emergency spill response organization should we have an incident that exceeds the scope of our onboard spill response equipment.

Our primary spill response provider has been in business since 1994 and specializes in helping industries prevent and clean up oil and other hydrocarbon spills throughout the Gulf Coast, with response centers in Texas and Louisiana with 24-hour response capabilities and equipment. Our provider 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 organization outside the US GOM. Our provider has significant spill response resources to meet the needs of its customers.

We believe we have adequate equipment and resources available to us to respond to an emergency spill; however, we can provide no assurance that adequate resources will be available should multiple concurrent spills occur. Other foreign jurisdictions in which we operate have similar regulations and requirements to which we comply.

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 protect the environment.

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Except as discussed above, we do not believe regulatory compliance has materially affected our capital expenditures, earnings or competitive position to date, although such measures increase drilling costs and may adversely affect drilling operations. Further regulations may reasonably be anticipated, but any effects on our drilling operations cannot be accurately predicted at this time.

We operate in areas where regulatory requirements govern the protection of employee occupational health and working environments.

In addition to regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect our customers and thereby could potentially impact demand for our services.

Insurance

We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution and other types of loss or damage. Our insurance coverage is subject to deductibles and self-insured retentions which must be met prior to any recovery. Additionally, our insurance is subject to exclusions and limitations, and we can provide no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.

Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence. This coverage does not include damage to our rigs arising from a US GOM named windstorm, for which we are self-insured.

We maintain insurance policies providing limited coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability) 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, 2014 , we had 4,051 employees worldwide, compared to 3,499 and 3,119 at December 31, 2013 and 2012 , respectively. Certain of our employees and contractors in international markets, such as Trinidad, Norway and Angola, are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. We consider relations with our employees to be satisfactory.

Customers

One customer, Saudi Aramco, accounted for 10% or more of our consolidated revenues, contributing approximately 24% of consolidated revenues in 2014 .

ITEM 1A. RISK FACTORS

You should consider carefully the following risk factors, in addition to the other information contained and incorporated by reference in this Form 10-K, before deciding to invest in our equity or debt securities.

Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by volatile oil and gas prices and other factors beyond our control.

Our business depends heavily on the level of oil and gas exploration, development and production and demand for drilling services in offshore areas worldwide. Demand for our drilling services is vulnerable to declines that are typically associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices may cause oil and gas companies to reduce their spending, in which case demand for our drilling services could decrease and our drilling revenues may be adversely affected by lower rig utilization and/or day rates. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions. As a result of the significant decline in oil

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and gas prices over the last half of 2014, many oil and gas operators have announced significant reductions in their capital expenditure budgets for 2015 and beyond, which we expect will, in turn, reduce the demand and day rates for offshore drilling units worldwide.

Demand for our drilling services also depends on additional factors that are beyond our control, including:


•	worldwide demand for and prices of oil and natural gas;


•	the supply of drilling units in the worldwide fleet versus demand;


•	the level of exploration and development expenditures by energy companies;


•	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;


•	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;


•	expectations regarding future energy prices;


•	environmental and other laws and regulations;


•	policies of various governments regarding exploration and development of oil and natural gas reserves;


•	nationalization and/or confiscation;


•	worldwide tax policies;


•	political and military conflicts in oil-producing areas and the effects of terrorism;


•	advances in exploration and development technology such as unconventional drilling and the development of shale resources;


•	the development and exploitation of alternative fuels and energy sources;


•	consolidation of our customer base, and


•	consolidation of our competitors.

The success of our business is dependent upon our ability to secure contracts for our drilling units at sufficient day rates. In addition to depressed oil and gas prices, an oversupply of drilling units may lead to a reduction in rig utilization and day rates and, therefore, may materially impact our profitability.

Our ability to meet our cash flow obligations will depend on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 19, 2015 , we had 12 drilling units with contract terms ending in 2015, and 4 drilling units with contract terms ending in 2016. We cannot predict the future level of demand or day rates for our drilling units or future conditions in the oil and gas industry. 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.

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The supply of existing and future drilling units has increased significantly due to heightened construction of new offshore drilling units during the last few years. According to industry sources, there were 545 jack-ups and 119 drillships in the worldwide fleets as of February 16, 2015, and an additional 132 jack-ups and 57 drillships were under construction or on order. This significant increase in construction activity has resulted in an oversupply of drilling units, which in turn, has caused a subsequent decline in utilization and day rates, which decline is expected to continue for an extended period of time. This overcapacity, combined with the decline in oil and gas prices and reductions in capital expenditure budgets by oil and gas operators, is expected to intensify competition and result in lower day rates and/or inability to contract our drilling units. Lower utilization and day rates could adversely affect our revenues and profitability.

A further decline in the market for contract drilling services could result in additional asset impairment charges.

In 2014, we recognized asset impairment charges aggregating $566 million (or approximately 7% of our total assets) on our twelve oldest jack-up rigs. Prolonged periods of low utilization and day rates 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 Item 8 of this Form 10-K for information regarding impairment charges recognized in 2013 and 2014.

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;


•	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 high-pressure drilling accidents resulting in lost or damaged formations and punch-throughs and towing accidents resulting in lost or damaged equipment. Any future such events could result in operating losses and have a significant impact on our business.

The global nature of our operations involves additional risks, particularly in certain foreign jurisdictions.

In recent years, we have significantly diversified our operations internationally. Foreign operations are often subject to additional political, economic and other uncertainties, such as with respect to taxation policies, customs restrictions, local content requirements, currency exchange and repatriation risk, security threats including terrorism, piracy and the risk of asset expropriation. Political unrest and regulatory restrictions in our areas of operations could potentially delay current or planned projects or could impact us in other unforeseen ways.

Many countries have regulations or policies currently in effect 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

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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 ownership of our drilling units, in whole or in part, by domestic companies or citizens and /or require reflagging of our drilling units under the flag of the 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, are highly regulated and have higher compliance and operating costs in general.

In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and try to limit non-U.S. currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive payment in the local currency. In such instances, we may be exposed to devaluation and other risk of exchange loss. In the event we terminate operations in such countries we may not be able to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where we hold approximately $15.2 million in Egyptian pounds, based on exchange rates in effect at January 31, 2015. We can provide no assurance we will be able to convert, utilize or repatriate such funds in the future.

The offshore drilling industry is highly competitive and cyclical, with intense price competition.

Our drilling markets are highly competitive with numerous participants, none of which has a dominant market share. Some of our competitors may have greater financial or other resources than we do. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition is frequently the primary factor determining which qualified contractor is awarded the job. In addition, historically there have been periods of high demand and short supply of rigs and high day rates, followed by periods of low demand, excess rig supply and low day rates. The current worldwide fleet overcapacity and anticipated delivery of a significant number of newbuilds over the next five years will further increase the supply of rigs and intensify competition and pressure day rates. We may be unable to secure profitable contracts for our drilling units, have to reduce our day rates, or enter into nontraditional fee arrangements, which could adversely affect our operating results and cash flows.

We will experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of contracts may not be ultimately realized.

Most of our term drilling contracts are cancelable by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the rig, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, and require the customer to pay a termination fee in the event of a cancelation without cause. Not all of our contracts require the customer to make an early termination payment upon cancellation. Early termination payments may not fully compensate us for the loss of the contract, and could result in the rig becoming idle for an extended period of time. During periods of depressed market conditions, we are subject to the increased risk of our customers seeking to terminate their contracts, including through claims of non-performance, or to renegotiate the terms, including day rates and payment options, of existing contracts.

In addition, our drilling contracts subject us to counterparty risks. The ability of our counterparties to perform their obligations under a contract depend on a number of factors beyond our control, including among other things, general economic conditions, the condition of the offshore drilling industry, market prices for oil and gas, the overall financial condition of the counterparty, the day rates received and the level of profitability necessary to maintain drilling activities. In addition, in a depressed market, our customers may no longer need a drilling rig that is currently under contract or may be able to obtain a comparable drilling unit at a lower day rate. If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts under less favorable terms, our backlog of estimated revenues from drilling contracts would decline and may have a material adverse effect on our financial results.

We must make substantial capital and operating expenditures to build, maintain, and upgrade our drilling fleet.

Our business is capital intensive and dependent on having sufficient cash flow and or available sources of financing in order to fund our capital expenditure requirements. We can provide no assurance that we will have access to adequate or economical sources of capital to fund our capital expenditures.

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Construction upgrades, enhancements, conversions, mobilizations and repairs of rigs and drillships are subject to risks, including delays and cost overruns, which could have an adverse impact on our financial position, results of operations and cash flows.

We have one remaining ultra-deepwater drillship under construction at Hyundai Heavy Industries Co. Ltd.'s shipyard in Ulsan, South Korea scheduled for delivery in late March 2015. Although there is certain insurance coverage and financial and bank guarantees associated with the drillship construction contract, in the event Hyundai is, for any reason, unable to perform under its agreement, there may be a material adverse effect on our results of operations, financial condition and cash flows.

From time to time in the future, we may also undertake additional new construction projects. In addition, we may make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly as our drilling units age.

Initial operations of new drilling units and mobilization of existing units often result in delays and other complications that could result in significant unexpected costs, uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts.

Some of the costs associated with construction projects, upgrades, enhancements, conversions, mobilizations and repairs of drilling units could be unplanned and are subject to risks of cost overruns or delays as a result of numerous factors, including the following:


•	shipyard unavailability;


•	shortages of equipment, materials or skilled labor for completion of repairs or upgrades to our equipment; unscheduled delays in the delivery or cost increases of materials and equipment or in shipyard construction;


•	failure of equipment to meet, design, quality or performance standards;


•	loss of or damage to essential equipment while in transit;


•	financial or operating difficulties experienced by equipment vendors or the shipyard;


•	unanticipated actual or purported change orders;


•	local customs strikes or related work slowdowns that could delay importation of equipment or materials;


•	engineering problems, including those relating to the commissioning of newly designed equipment;


•	design or engineering changes;


•	latent damages or deterioration to the hull, equipment and machinery in excess of engineering estimates and assumptions;


•	work stoppages;


•	client acceptance delays;


•	weather interference, storm damage or other events of force majeure;


•	disputes with shipyards and suppliers;


•	inability or unwillingness of shipyards and suppliers to honor warranty obligations;


•	long lead-times for replacement of equipment;


•	shipyard failures and difficulties;


•	failure of third-party equipment vendors or service providers;


•	unanticipated cost increases, including relating to raw materials used in construction of our drilling units; and


•	difficulty in obtaining necessary permits or approvals or in meeting permit or approval conditions.

These factors may contribute to cost variations and delays in the delivery of our ultra-deepwater newbuild drillship or upgrade projects. Delays in the delivery of the drillship or other drilling units or the inability to complete construction in accordance with their design specifications may, in some circumstances, result in a delay in contract commencement, resulting in a loss of revenue

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to us, and may also cause customers to renegotiate, terminate or shorten the term of a drilling contract pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms or at all. Additionally, capital expenditures for upgrades, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our drilling units that may undergo upgrade, refurbishment or repair may not earn a day rate during the periods they are out of service. In addition, in the event of a shipyard failure or other difficulty, we may be unable to enforce certain provisions under our newbuild contracts such as our contractual rights to recover amounts paid as installments under such contracts. Furthermore, the inability or unwillingness of shipyards and suppliers to honor warranty obligations may result in additional costs to us. The occurrence of any of these events may have a material adverse effect on our results of operations, financial position or cash flows.

We have and will likely continue to have certain customer concentrations, and the loss of a significant customer could have a material adverse impact on our financial results.

One customer, Saudi Aramco, accounted for 24% of our 2014 consolidated revenues. The loss or material reduction of business from a significant customer could have a material adverse impact on our results of operations and cash flows. Moreover, to the extent that we may be heavily dependent on any single customer, we could be subject to the risks faced by that customer to the extent that such risks impede the customer's ability to continue operating and make timely payments to us. In addition, due to the high day rate and long-term of our drillship contracts, a loss of any of our drillship customers may have a material adverse impact on our results of operations and cash flows.

If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our 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 (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM. These regulations have 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.

Increases in regulatory requirements could significantly increase our costs or delay our operations.

Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. Operations in certain areas, such as the US GOM and the North Sea, are highly regulated and have higher compliance and operating costs in general. We may be required to make significant expenditures in order to comply with existing or new governmental laws and regulations. It is also possible that such laws and regulations may in the future add significantly to our operating costs or result in a reduction of revenues associated with downtime required to implement regulatory requirements.

In the aftermath of the Macondo well blowout in 2010 and the subsequent investigation into the causes of the event, new rules were implemented for oil and gas operations in the US GOM and in many of the international locations in which we operate, including new standards for well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations continue to be implemented, including rules regarding drilling systems and equipment, such as blowout preventer and well-control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third-party audits of SEMS programs. Such new regulations may require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase our operating costs and cause downtime for our units if we are required to take any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled surveys or inspections to meet any such new requirements. Additional

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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.

Governments around the world are beginning to adopt laws and regulations regarding climate change. Lawmakers and regulators in the U.S., the U.K. and other jurisdictions where we operate have focused increasingly on restricting and reporting the emission of carbon dioxide, methane and other “greenhouse” gases that may contribute to warming of the Earth’s atmosphere and other climatic changes. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business, and could adversely affect our operations by limiting drilling opportunities.

In addition, the offshore drilling industry is highly dependent on demand for services from the oil and gas industry and accordingly, regulations of the production and transportation of oil and gas generally could impact demand for our services.

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 choose not 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.

We are currently self-insured with respect to physical damage due to named windstorms in the US GOM.

Hurricanes (or named windstorms) have caused tremendous damage to drilling and production equipment and facilities throughout the US GOM in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of available coverage for named windstorms in the US GOM and have dramatically increased the price of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with these named windstorm losses, has also been limited.

As a result of the increased cost and reduced availability, we do not maintain named windstorm physical damage coverage on any of our rigs located in the US GOM. Our coverage for liabilities (including removal of wreck) arising out of a US GOM named windstorm are subject to a self-insured retention of $200 million per occurrence. Losses due to future US GOM named windstorms not covered by insurance could adversely affect our financial position, results of operations and cash flows.

Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.

Our tax positions are subject to audit by 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.

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In 2012, we changed our legal domicile to the U.K. There are frequently legislative proposals in the U.S. that attempt to treat companies that have undertaken similar transactions as U.S. corporations subject to U.S. taxes or to limit the tax deductions or tax credits available to U.S. subsidiaries of these corporations. The realization of the expected tax benefits of our redomestication could be impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof or differing interpretation or enforcement of applicable law by the IRS or other tax authorities. Changes in our effective tax rates as determined from time to time, the inability to realize anticipated tax benefits, or the imposition of additional taxes could have a material impact on our results of operations, financial position and cash flows. Our future effective tax rates could be adversely affected by changes in the valuation of our deferred tax assets and liabilities, the ultimate repatriation of earnings from RCI’s non-U.S. subsidiaries 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 our non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is 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 U.S. 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.

Most of our contracts are fixed-price contracts, and changes in customer requirements, increased regulatory requirements and increases in our operating costs or price levels in general could have an adverse effect on the profitability of those contracts.

Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation and reduced day rates during periods of other activities. Our long-term contracts may be at day rates lower than current prevailing rates, and therefore unable to benefit from the higher prevailing rates. Long-term contracts may also be at day rates higher than prevailing rates, and our revenues may decline at the end of such favorable contracts. Many of our operating costs are unpredictable and can vary based on events beyond our control, including increased customer and regulatory requirements, and increased labor and other costs. Operators and regulators are requiring higher standards than in the past, including more robust back-up redundancy systems. Our margins will therefore vary over the terms of our contracts as a result of applicable day rates and operating costs. If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.

Our rig operating and maintenance costs include fixed costs that will not decline in proportion to decreases in rig utilization and day rates.

We do not expect our rig operating and maintenance costs to decline proportionately when rigs are not in service or when day rates decline. Fixed costs continue to accrue during out-of-service periods (such as shipyard stays and rig mobilizations preceding a contract), which represented approximately 10% of our available rig days in 2014 and 2013. Operating revenue may fluctuate as a function of changes in day rates, but costs for operating a rig are generally fixed or only slightly variable regardless of the day rate being earned. Additionally, if our rigs are idle between contracts, we typically continue to incur operating and personnel costs because the crew is used to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking. Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.

Shortages of significant parts or equipment, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.

Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our drilling operations exposes us to volatility in the quality, prices and availability of such items, as well as poor customer service in general. Certain high specification parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production

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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.

Some of our operating risks may not be covered by insurance.

We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution, reservoir damage and other damages and losses. Our insurance coverage is subject to deductibles and self-insured retentions which must be met prior to any recovery. Additionally, our insurance is subject to exclusions and limitations, and we can provide no assurance that such coverage will adequately protect us against liability from potential consequences and damages. A significant event which is not adequately covered by insurance and /or the failure of one or more of our insurance providers to meet claim obligations or losses or liabilities resulting from uninsured or underinsured events could have a material adverse effect on our financial position, results of operations and cash flows.

Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence. This coverage does not include damage arising from a US GOM named windstorm, for which we are self-insured.

We maintain insurance policies providing coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability), automobile liability and aviation liability, and these policies are subject to various deductibles and underlying limits. In addition, we maintain excess liability coverage with an annual aggregate limit of $700 million subject to a self-insured retention of $10 million except in cases of liabilities (including removal of wreck) arising out of US GOM named windstorms, which are subject to a self-insured retention of $200 million per occurrence.

Our rig physical damage and liability insurance renews each June. We can provide no assurance we will be able to secure coverage of a similar nature with similar limits at comparable costs.

Our contractual indemnification provisions may not be sufficient to cover our liabilities.

Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and us with respect to liabilities resulting from various hazards associated with the drilling industry, such as loss of well control, well-bore pollution and damage to subsurface reservoirs and injury or death to personnel. The degree of indemnification we receive from operators against liabilities varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated. 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. For example, in 2012 a U.S. District Court in the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties in a drilling contract governed by U.S. maritime law as a matter of public policy. We could therefore be liable for certain liabilities even in cases where we have contractual indemnification rights. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from or unenforceable under contractual indemnification obligations could have a material adverse effect on our financial position, results of operations and cash flows.

Failure to obtain and retain highly skilled personnel could hurt our operations.

We require highly skilled personnel to operate our rigs and provide technical services and support for our business in each of the areas of our operations. To the extent that demand for drilling services and the size of the worldwide industry fleet increase (including due to the impact of newly constructed rigs), shortages of qualified personnel could arise, creating upward pressure on wages and difficulty in staffing and servicing our rigs, which could, in turn, adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seek to hire personnel with expertise in the offshore drilling industry. The heightened competition for skilled personnel could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.

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We are involved in litigation and legal proceedings from time to time that could have a negative effect on us if determined adversely.

We are, from time to time, involved in various legal proceedings, which may include, among other things, contract dispute, personal injury, environmental, toxic tort, employment, tax and securities litigation, governmental investigations or proceedings, and litigation that arises in the ordinary course of our business. Although we intend to defend any of these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter. Our profitability may be adversely affected by the outcome of claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any purported nullification, cancellation or breach of contracts with customers or other parties. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of resources, reputational damage, and other factors.

A downgrade in the ratings of our debt could restrict our ability to access the debt capital markets and increase our interest costs.

We currently have investment grade credit ratings, which are subject to review and change by the rating agencies from time to time. There can be no assurance that any particular rating assigned to us will remain in effect for any given period of time or that a rating will not be changed or withdrawn by a rating agency. If ratings for our debt fall below investment grade, our access to the debt capital markets could become restricted. Tightening in the credit markets and the reduced level of liquidity in many financial markets due to turmoil in the financial and banking industries could also affect our access to the debt capital markets or the price we pay to issue debt. Our revolving credit facility includes an increase in interest rates if the ratings for our debt are downgraded. Further, an increase in the level of our indebtedness may increase our vulnerability to adverse general economic and industry conditions and may affect our ability to obtain additional financing.

We have entered into intercompany loan agreements that could affect our business, financial position, and ability to enter into financial transactions, including the payment of dividends.

In connection with our restructuring, Rowan plc and its subsidiaries have entered into intercompany debt arrangements which contain negative covenants that limit our ability to, among other things:


•	Create liens


•	Incur other indebtedness or guarantee other indebtedness


•	Make dividends or other distributions of cash or property


•	Repurchase or redeem shares


•	Make investments


•	Change the nature of our business or operations


•	Redeem indebtedness


•	Merge or consolidate or enter into transactions with affiliates


•	Sell assets including capital shares of subsidiaries


•	Enter into agreements that restrict dividends from subsidiaries

The agreements also contain affirmative covenants such as mandatory prepayments upon consolidated excess cash balances or material dispositions and other customary events of default, including a cross-default upon the acceleration due to default of any other debt in a principal amount in excess of one million dollars. In addition, debtor subsidiaries are required to maintain adequate total equity and adequate debt-to-equity ratios as identified in each such agreement.

If an event of default has occurred and is continuing and has not been cured or waived by the lending subsidiary, then the payment of any intercompany indebtedness could be accelerated, and such payment could have an adverse impact on our ability to pay dividends or make other capital allocations.

We depend heavily upon the security and reliability of our technology systems and those of our service providers, and such 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, to conduct our business and operations. Cybersecurity risks and threats to such systems continue to grow in sophisticated ways that avoid detection and may be difficult to anticipate, prevent or mitigate. If any of our or our service or equipment providers’ security systems for protecting against cybersecurity breaches or failures 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

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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.

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.

Transocean holds U.S. and other patents for dual activity drilling equipment and has pursued litigation against several other offshore drilling contractors. Transocean could choose to sue us or our customers for infringing its patents if it believes that we are using technology covered by its patent on our drillships, and we could be forced to modify our drillships and/or pay royalties to Transocean in the event that a Court were to find that any Transocean patents are infringed.

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 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 could have a material adverse effect on our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participation in or curtailment of business operations in those jurisdictions and the seizure of drilling units or other assets.

Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.

Certain of our employees and contractors in international markets, such as Trinidad, Norway and Angola, 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.

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, except with the consent of our Board or the prior approval of the shareholders, a Rowan plc shareholder, together with persons acting in concert, would be at risk of certain Board sanctions if they acquired 30 percent or more of our issued shares without

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making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative. The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association. The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the consent of our Board before effecting any additional purchases. In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.

As a result of increased shareholder approval requirements, we may have less flexibility as a U.K. public limited company than as a Delaware corporation with respect to certain aspects of capital management.

Under Delaware law, directors may issue, without further stockholder approval, any shares authorized in a company’s certificate of incorporation that are not already issued or reserved. Delaware law also provides substantial flexibility in establishing the terms of preferred shares. However, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders; such authorization must state the maximum amount of shares that may be allotted and may only be for a maximum period of five years.

English law also generally provides shareholders with preemptive rights when new shares are issued for cash while Delaware law does not. However, it is possible for the articles of association, or shareholders in a general meeting, to exclude preemptive rights for a maximum period of up to five years from the date of adoption of the exclusion.

English law also generally prohibits 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 by special resolution (i.e., 75 percent of votes cast), which approval lasts for a maximum period of five years.

Prior to the redomestication, resolutions were adopted to authorize the allotment of a certain amount of shares, exclude certain preemptive rights and permit off market purchases, in each case without further shareholder approval, but these authorizations will expire in 2017 unless further approved by our shareholders prior to the expiration date.

We cannot assure you that situations will not arise where U.K. shareholder approval requirements for the extension or expansion of any of these actions would deprive our shareholders of substantial capital management benefits.

We have incurred higher costs as a result of the redomestication and we expect to continue to do so.

The redomestication has resulted in an increase in some of our ongoing expenses and increased compliance costs with regulatory requirements. Some costs, including those related to financial reporting requirements and governance, such as holding management, board and shareholder meetings in the U.K., are higher than would be the case if we had remained a U.S. company. Additionally, we have incurred and expect to continue to incur higher professional fees and other costs to comply with U.K. corporate securities and tax laws.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The Company has no unresolved SEC staff comments.

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ITEM 2. PROPERTIES

Our primary U.S. offices are located in 140,314 square feet of leased space in two office towers in Houston, Texas. Additionally, we lease other office, maintenance and warehouse facilities in Texas, Scotland, Saudi Arabia, Qatar, Trinidad, Norway, South Korea, Indonesia, and Malaysia.

Drilling Rigs

Following are the principal drilling equipment owned by us and their location at February 19, 2015 . Water depths are the "rated" water depths; actual water depths may vary depending on operating location:



		Depth (feet) ⁽¹⁾
Rig Name	Class Name/Type	Water	Drilling	Year in service/ significant refurbishment	Location

Ultra-Deepwater Drillships:
Rowan Renaissance	Gusto MSC P10,000	12,000	40,000	2014	West Africa
Rowan Resolute	Gusto MSC P10,000	12,000	40,000	2014	US GOM
Rowan Reliance	Gusto MSC P10,000	12,000	40,000	2015	US GOM
Rowan Relentless (under construction)	Gusto MSC P10,000	12,000	40,000	2015 (est.)	Shipyard

High-Specification Jack-ups: ⁽²⁾
Rowan Norway ⁽³⁾	N-Class	400	35,000	2011	Norway
Rowan Stavanger ⁽³⁾	N-Class	400	35,000	2011	U.K. North Sea
Rowan Viking ⁽³⁾	N-Class	400	35,000	2011	Norway
Rowan EXL IV ⁽³⁾	EXL	350	40,000	2011	Malaysia
Rowan EXL III ⁽³⁾	EXL	350	40,000	2011	US GOM
Rowan EXL II ⁽³⁾	EXL	350	35,000	2011	Trinidad
Rowan EXL I ⁽³⁾	EXL	350	35,000	2010	Malaysia
Joe Douglas ⁽³⁾	240C	375	35,000	2012	US GOM
Ralph Coffman ⁽³⁾	240C	375	35,000	2009	Tunisia
Rowan Mississippi ⁽³⁾	240C	375	35,000	2008	Middle East
J.P. Bussell ⁽³⁾	Tarzan	300	35,000	2008	Malaysia
Hank Boswell ⁽³⁾	Tarzan	300	35,000	2006	Middle East
Bob Keller ⁽³⁾	Tarzan	300	35,000	2005	Middle East
Scooter Yeargain ⁽³⁾	Tarzan	300	35,000	2004	Middle East
Bob Palmer ⁽³⁾	Super Gorilla XL	490	35,000	2003	Middle East
Rowan Gorilla VII ⁽⁴⁾	Super Gorilla	450	35,000	2002	U.K. North Sea
Rowan Gorilla VI ⁽⁴⁾	Super Gorilla	450	35,000	2000	Norway
Rowan Gorilla V ⁽⁴⁾	Super Gorilla	400	35,000	1998	U.K. North Sea
Rowan Gorilla IV ⁽³⁾	Gorilla	450	35,000	1986	US GOM

Premium Jack-ups: ⁽⁵⁾
Rowan Gorilla III ⁽³⁾	Gorilla	450	30,000	1984	Trinidad
Rowan Gorilla II ⁽³⁾	Gorilla	480	30,000	1984	Indonesia
Rowan California ⁽³⁾	116C	300	25,000	1983	Middle East
Cecil Provine ⁽³⁾	116C	300	30,000	1982	US GOM
Gilbert Rowe ⁽³⁾	116C	300	30,000	1981/2013	Middle East
Arch Rowan ⁽³⁾	116C	350	30,000	1981	Middle East
Charles Rowan ⁽³⁾	116C	350	30,000	1981	Middle East
Rowan Middletown ⁽³⁾	116C	300	30,000	1980	Middle East

Conventional Jack-ups: ⁽⁶⁾
Rowan Juneau	Slot	250	30,000	1977	US GOM
Rowan Alaska	Slot	350	25,000	1975	US GOM
Rowan Louisiana ⁽³⁾	Slot	350	30,000	1975/2006	US GOM

______________________________

(1) Indicates rated water and drilling depths.

(2) High-specification rigs are those that have hook-load capacity of at least two million pounds.

(3) Unit is equipped with three mud pumps.

(4) Unit is equipped with four mud pumps.

(5) Premium jack-ups are cantilevered rigs capable of operating in water depths of 300 feet or more.

(6) Units are equipped with skid-off capability, which is described under “Drilling Fleet” in Item 1, Business. The Rowan Juneau, Rowan Alaska and Rowan Louisiana are currently cold-stacked.

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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 March 2, 2015 , 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

W. Matt Ralls	Executive Chairman	65
Thomas P. Burke	President and Chief Executive Officer	47
Stephen M. Butz	Executive Vice President, Chief Financial Officer and Treasurer	43
Mark A. Keller	Executive Vice President, Business Development	62
Melanie M. Trent	Executive Vice President, General Counsel, Chief Administrative Officer and Company Secretary	50
Gregory M. Hatfield	Vice President and Controller	45

Mr. Ralls was appointed Executive Chairman of the Board in April 2014. Prior to that time, Mr. Ralls served as President and Chief Executive Officer and a director since January 2009 until his retirement as Chief Executive Officer in April 2014. Mr. Ralls currently serves as a director of Cabot Oil & Gas Corporation and Superior Energy Services.

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.

Mr. Butz became Executive Vice President, Chief Financial Officer and Treasurer upon joining the Company in December 2014. Prior to that time, Mr. Butz served as Executive Vice President and Chief Financial Officer at Hercules Offshore, Inc. He was Senior Vice President and Chief Financial Officer from 2010 to 2013 and held a number of other key positions since joining Hercules Offshore in 2005, including Director of Corporate Development and Vice President, Finance and Treasurer.

Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development.

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. Hatfield has served as Vice President and Controller since March 2010. From May 2005 to March 2010, he served as Controller.

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.

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	2014				2013
Quarter	High		Low		High		Low
First	$	35.17	$	31.13	$	36.85	$	31.55
Second	33.78		29.50		36.51		30.21
Third	32.16		24.96		38.65		33.86
Fourth	25.63		19.50		37.81		32.75

On January 31, 2015 , there were 75 shareholders of record.

The following table sets forth the per share quarterly cash dividends declared during the two most recent fiscal years. No dividends were declared in 2013.



Quarter	2014
First	$	—
Second	0.10
Third	0.10
Fourth	0.10

On January 29, 2015, the Board of Directors approved a quarterly cash dividend of $0.10 per share payable on March 3, 2015, to shareholders of record at the close of business on February 9, 2015.

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, 2014 , assuming reinvestment of dividends.

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	12/31/2009	12/31/2010	12/31/2011	12/31/2012	12/31/2013	12/31/2014
Rowan	100.00	154.20	133.97	138.12	156.18	104.13
S&P 500 Index	100.00	115.06	117.49	136.30	180.44	205.14
Dow Jones US Oil Equipment & Services Index	100.00	127.34	111.51	111.88	143.66	118.91

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Issuer Purchases of Equity Securities

The following table summarizes acquisitions of our shares for the fourth quarter of 2014 :



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 programs ²	Approximate dollar value of shares that may yet be purchased under the plans or programs ²
Balance forward					$	—
October 31, 2014	4,642	$	22.57	—	—
November 30, 2014	1,678	$	23.84	—	—
December 31, 2014	1,792	$	22.16	—	—
Total	8,112	$	22.74	—


¹ The total number of shares acquired includes shares acquired from employees by an affiliated employee benefit trust 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 par 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. There were no shares repurchased under any share repurchase program during the fourth quarter of 2014.
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 prior to that time. U.K. law prohibits the Company from purchasing its shares in the open market because they are 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 Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.

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ITEM 6. SELECTED FINANCIAL DATA

Selected financial data for each of the last five years is presented below:



	2014			2013			2012			2011			2010
	(Dollars in thousands, except per share amounts)
Operations
Revenues	$	1,824,383		$	1,579,284		$	1,392,607		$	939,229		$	1,017,705
Costs and expenses:
Direct operating costs (excluding items shown below)	991,340			860,893			752,173			508,066			416,832
Depreciation and amortization	322,641			271,008			247,900			183,903			138,301
Selling, general and administrative	125,834			131,373			99,712			88,278			78,658
(Gain) loss on disposals of property and equipment	(1,778		)	(20,119		)	(2,502		)	(1,577		)	402
Litigation settlement ⁽¹⁾	(20,875		)	—			(4,700		)	6,100			—
Material charges and other operating expenses ⁽²⁾	573,950			4,453			44,972			4,876			5,250
Total costs and expenses	1,991,112			1,247,608			1,137,555			789,646			639,443
Income (loss) from operations	(166,729		)	331,676			255,052			149,583			378,262
Other income (expense) — net	(102,878		)	(70,437		)	(71,582		)	(19,503		)	(18,727		)
Income (loss) from continuing operations, before income taxes	(269,607		)	261,239			183,470			130,080			359,535
Provision (benefit) for income taxes	(150,732		)	8,663			(19,829		)	(5,659		)	91,934
Income (loss) from continuing operations	(118,875		)	252,576			203,299			135,739			267,601
Discontinued operations, net of taxes ⁽³⁾	4,023			—			(22,697		)	601,102			12,394
Net income (loss)	$	(114,852	)	$	252,576		$	180,602		$	736,841		$	279,995
Basic income (loss) per common share:
Income (loss) from continuing operations	$	(0.96	)	$	2.04		$	1.65		$	1.09		$	2.29
Income (loss) from discontinued operations	0.03			—			(0.18		)	4.80			0.10
Net income (loss)	$	(0.93	)	$	2.04		$	1.47		$	5.89		$	2.39
Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(0.96	)	$	2.03		$	1.64		$	1.07		$	2.25
Income (loss) from discontinued operations	0.03			—			(0.18		)	4.76			0.11
Net income (loss)	$	(0.93	)	$	2.03		$	1.46		$	5.83		$	2.36

Financial Position
Cash and cash equivalents	$	339,154		$	1,092,844		$	1,024,008		$	438,853		$	437,479
Property, plant and equipment — net	$	7,432,212		$	6,385,755		$	6,071,729		$	5,678,713		$	4,344,522
Total assets	$	8,411,192		$	7,975,761		$	7,699,487		$	6,597,845		$	6,217,457
Long-term debt, less current portion	$	2,807,324		$	2,008,700		$	2,009,598		$	1,089,335		$	1,133,745
Shareholders’ equity	$	4,691,399		$	4,893,761		$	4,531,724		$	4,325,987		$	3,752,310

Statistical Information
Current ratio ⁽⁴⁾	2.82			4.50			5.61			2.46			2.88
Debt to capitalization ratio	37		%	29		%	31		%	20		%	23		%
Book value per share of common stock outstanding	37.66			39.39			36.48			35.01			29.71
Price range of common stock:
High	35.17			38.65			39.40			44.83			35.39
Low	19.50			30.21			28.62			28.13			20.44

Cash dividends declared per share	$	0.30		$	—		$	—		$	—		$	—

___________________

(1)

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; 2012 – a $4.7 million gain for cash received in connection with a legal settlement; 2011 – a $6.1 million payment to settle a lawsuit in connection with the Company’s obligation under a charter agreement for the Rowan Halifax.

(2)

Material charges and other operating expenses consisted of the following: 2014 – $574.0 million of noncash asset impairment charges; 2013 – $4.5 million of noncash asset impairment charges; 2012 – $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the 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 noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee; 2011 – $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee; and 2010 – the cost of terminating the Company’s agency agreement in Mexico.


(3)	In 2011, the Company sold its manufacturing and land drilling operations. Operating results for manufacturing and land drilling have been reclassified to discontinued operations for each year presented.


(4)	Current ratio excludes assets and liabilities of discontinued operations.

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ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

OVERVIEW

Rowan Companies plc is a global provider of offshore oil and gas contract drilling services with a focus on high-specification and premium jack-up rigs and high-specification ultra-deepwater drillships, which our customers use for both exploratory and development drilling.

During 2014, we took delivery of three newly constructed drillships: the Rowan Renaissance, which commenced drilling operations offshore West Africa in April 2014; the Rowan Resolute, which commenced operations in the US GOM in October 2014; and the Rowan Reliance, which commenced operations in the US GOM in February 2015. Our fourth drillship, the Rowan Relentless, is scheduled for delivery in late March 2015 and is expected to commence operations in the US GOM in the third quarter of 2015.

As of February 19, 2015 , the date of our most recent Fleet Status Report, we had six jack-ups in the North Sea, ten in the Middle East, seven in the US GOM (including three cold-stacked rigs), two in Trinidad, three in Malaysia, and one in each of Tunisia and Indonesia. At February 19, 2015 , our backlog totaled $5.1 billion compared to $5.0 billion at this time last year.

Revenues for 2014 increased by 16% to $1.824 billion from $1.579 billion in 2013 primarily due to the addition of the Rowan Renaissance and Rowan Resolute. Fleet utilization improved to 82% in 2014 from 81% and 77% in 2013 and 2012, respectively, and fleet average day rates improved to $190,629 in 2014 from $170,912 and $156,306 in 2013 and 2012. Out-of-service days totaled approximately 10% of available rig days in 2014 and 2013, down from 12% in 2012 as a result of decreased shipyard time and fewer rig mobilizations in 2014 and 2013 compared to 2012. We define out-of-service days as those days when a rig is (or planned to be) out of service and is not able to earn revenue. Operational downtime, which is the unbillable time attributable to equipment breakdowns or procedural failures, was approximately 1% of in-service days in 2014 and 2013, down from 2% in 2012.

RESULTS OF OPERATIONS

Our profitability is primarily a function of our ability to keep our rigs under contract earning operating day rates, offset by any downtime while a rig is under contract. The Company typically receives a reduced day rate or no day rate during periods of downtime. Our ability to obtain contracts for our rigs and the day rates received are primarily determined by the level of oil and gas exploration and development expenditures, which are heavily influenced by trends in oil and natural gas prices and the availability of competitive equipment. When drilling markets are strengthening, day rates generally lag the upward trend in rig utilization, and day rate increases can be more significant as fleet utilization approaches 90% or more. When drilling markets are weakening, contractors often reduce day rates in an effort to maintain fleet utilization. Both rig utilization and day rates have historically declined much faster than they have risen.

As a result of the dramatic decline in oil and gas prices over the last half of 2014, many oil and gas operators have significantly reduced their capital expenditure budgets for 2015. In addition, the offshore drilling market is currently experiencing an oversupply of drilling units as newbuilds enter the market. In the current environment, we may have difficulty securing new drilling contracts; we may be forced to enter into contracts at unattractive day rates; customers may seek to renegotiate or terminate existing contracts; and we may have difficulty selling older rigs. We currently have a mix of short- and long-term contracts and are unable to predict the duration of the current market condition or its financial effects on the Company.

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Current Operations and Markets

Worldwide demand for offshore drilling services is inherently volatile and has historically varied among geographic markets, as has the supply of competitive equipment. Exploration and development expenditures can be impacted by many local factors, such as political and regulatory policies, seasonal weather patterns, lease expirations, new oil and gas discoveries and reservoir depletion. Over time, the level and expected direction of oil and natural gas prices are the principal determinants of drilling activity, and oil and gas prices are ultimately a function of the supply of and demand for those commodities.

We currently operate in the U.K. and Norwegian sectors of the North Sea, the Middle East, US GOM, West and North Africa, Southeast Asia and Trinidad. As demand shifts among geographic areas, the Company may from time to time relocate rigs from one major geographic area to another. The relocation of rigs is a significant undertaking, and often interrupts revenues and cash flows for several months, particularly when equipment upgrades are involved. Thus, major relocations are typically carried out only when the likelihood of higher long-term returns outweighs the short-term costs.

The North Sea is a mature, harsh-environment offshore drilling market that has long been dominated by major oil and gas companies operating within a highly regulated environment. Project lead times are often lengthy, and drilling assignments, which typically require ultra-premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years. Drilling activity and day rates in the North Sea move slowly in response to market conditions, and generally follow trends in oil prices. As of February 16, 2015, industry utilization for jack-up rigs in the North Sea was 98%, and we had six rigs in the U.K. and Norwegian sectors with expected contract completion dates ranging from 2015 through 2018.

The Middle East is a market in which we have had a significant presence in recent years. As of February 16, 2015, industry utilization in the Middle East for jack-up rigs was 85%, and we had nine rigs under contract in Saudi Arabia and one under contract in Qatar. Four of our ten rigs working there have contracts estimated to complete in 2015, five have contracts estimated to complete from 2016 through 2018, and one has a contract estimated to complete in 2024.

The US GOM jack-up drilling market is highly fragmented among many participants, many of which are independent operators whose drilling activities may be highly dependent on near-term operating cash flows. A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options. Long-term contracts for jack-up rigs have been relatively rare, and generally are available only from the major integrated oil companies and a few of the larger independent operators. Jack-up drilling demand and day rates in the US GOM have tended to move quickly and generally follow trends in natural gas prices. Demand in the shallower waters of the US GOM has been weak over the last few years and at almost record lows currently as a result of the availability of natural gas and low prices. As of February 16, 2015, industry utilization for jack-up rigs in the US GOM was 27%, and we had seven jack-up rigs there – two under contracts estimated to complete in 2015, one under contract estimated to complete in 2016, one that was idle, and three that were cold-stacked.

A number of newbuild rigs have entered the Southeast Asia market recently due to its proximity to construction shipyards. We currently have one rig operating in Malaysia through the end of 2015 and one rig operating in Indonesia that is contracted for work in Malaysia from approximately April through July 2015. In addition, we have two idle rigs in Malaysia. Industry utilization for jack-up rigs in Southeast Asia was 81% at February 16, 2015. We expect the Southeast Asia market to weaken through 2015 due to an oversupply of rigs in the area.

The ultra-deepwater drilling market consists of semisubmersibles and drillships with a rated water depth of 7,500 feet or greater (“ultra-deepwater rigs”). As of February 24, 2015, there were a total of 162 units in this category, including Rowan’s three ultra-deepwater drillships, with a worldwide utilization rate of 89%. There were an additional 68 ultra-deepwater rigs under construction, including Rowan’s fourth drillship, scheduled for delivery over the next five years. The major ultra-deepwater drilling markets in the world are the US GOM, South America and West Africa. The highest specification deepwater rigs, such as those owned by Rowan, can obtain work at better rates than lower specification rigs, as drilling requirements have become more stringent, particularly in the post-Macondo environment. In down markets, the highest specification rigs typically displace lower specification rigs, although at reduced rates. Most ultra-deepwater rigs are committed many months in advance given the extensive planning and high costs associated with ultra-deepwater projects. Contracts are usually long term, but sublets are common within a company’s contract window. Three of our drillships are contracted into 2017, and one is contracted into early 2018.

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Key Performance Measures

The following table presents certain key performance measures by rig classification:



	2014			2013			2012

Revenues (in thousands):
Ultra-deepwater drillships	$	170,502		$	—		$	—
High specification jack-ups ⁽¹⁾	1,244,289			1,251,641			1,134,795
Premium jack-ups ⁽²⁾	319,812			261,937			194,942
Conventional jack-ups	34,668			29,241			26,531
Subtotal - Day rate revenues	$	1,769,271		$	1,542,819		$	1,356,268
Other revenues ⁽³⁾	55,113			36,465			36,339
Total revenues	$	1,824,384		$	1,579,284		$	1,392,607

Revenue-producing days:
Ultra-deepwater drillships	262			—			—
High specification jack-ups	5,980			6,297			6,253
Premium jack-ups	2,728			2,442			2,059
Conventional jack-ups	311			288			365
Total revenue-producing days	9,281			9,027			8,677

Average day rate: ⁽⁴⁾
Ultra-deepwater drillships	$	650,356		$	—		$	—
High specification jack-ups	$	208,071		$	198,781		$	181,480
Premium jack-ups	$	117,245		$	107,245		$	94,678
Conventional jack-ups	$	111,398		$	101,662		$	72,688
Total fleet	$	190,629		$	170,912		$	156,306

Utilization: ⁽⁵⁾
Ultra-deepwater drillships	80		%	—		%	—		%
High specification jack-ups	86		%	91		%	91		%
Premium jack-ups	93		%	79		%	63		%
Conventional jack-ups	28		%	26		%	33		%
Total fleet	82		%	81		%	77		%

(1) We define high-specification jack-ups as those that have hook-load capacity of at least two million pounds.
(2) We define premium jack-ups as those cantilevered rigs capable of operating in water depths of 300 feet or more.
(3) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate.
(4) 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. Total revenue-producing days may not sum due to rounding.
(5) Utilization is the number of revenue-producing days, including fractional days, divided by the aggregate number of calendar days 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.

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The following information is presented by geographic area:



	2014			2013			2012
Revenues (in thousands):
North Sea	$	483,389		$	480,442		$	491,459
Middle East ⁽¹⁾	496,504			432,739			400,359
US GOM	274,983			236,712			206,348
Southeast Asia	211,667			208,702			135,943
West Africa	137,277			—			—
Other international ⁽²⁾	165,451			184,224			122,159
Subtotal - Day rate revenues	1,769,271			1,542,819			1,356,268
Other revenues ⁽³⁾	55,113			36,465			36,339
Total revenues	$	1,824,384		$	1,579,284		$	1,392,607

Revenue-producing days:
North Sea	1,668			1,777			2,074
Middle East	3,516			3,171			3,010
US GOM	1,651			1,708			1,706
Southeast Asia	1,352			1,291			994
West Africa	213			—			—
Other international	881			1,080			893
Total revenue-producing days	9,281			9,027			8,677

Average day rate: ⁽⁴⁾
North Sea	$	289,760		$	270,378		$	236,962
Middle East	$	141,198		$	136,481		$	133,010
US GOM	$	166,587		$	138,550		$	120,954
Southeast Asia	$	156,572		$	161,694		$	136,764
West Africa	$	645,757		$	—		$	—
Other international	$	187,706		$	170,627		$	136,796
Total fleet	$	190,629		$	170,912		$	156,306

Utilization: ⁽⁵⁾
North Sea	76		%	81		%	94		%
Middle East	96		%	83		%	75		%
US GOM	63		%	67		%	59		%
Southeast Asia	93		%	88		%	79		%
West Africa	84		%	—		%	—		%
Other international	75		%	99		%	94		%
Total fleet	82		%	81		%	77		%

(1) Our rigs operating in the Middle East are located in Saudi Arabia and Qatar.
(2) "Other international" includes revenues from Trinidad and Egypt in 2012 through 2014 and Morocco and Tunisia in 2014.
(3) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate.
(4) 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. Total revenue-producing days may not sum due to rounding.
(5) Utilization is the number of revenue-producing days, including fractional days, divided by the aggregate number of calendar days 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.

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2014 Compared to 2013

Our operating results for the years ended December 31, 2014 and 2013 are highlighted below (dollars in millions):



	2014					2013
	Amount			% of Revenues		Amount			% of Revenues
Revenues	$	1,824.4		100	%	$	1,579.3		100	%
Direct operating costs (excluding items below)	(991.4		)	-54	%	(860.9		)	-55	%
Depreciation expense	(322.6		)	-18	%	(271.0		)	-17	%
Selling, general and administrative expenses	(125.8		)	-7	%	(131.3		)	-8	%
Net gain on property disposals	1.8			0	%	20.1			1	%
Litigation settlement	20.9			-2	%	—			—	%
Material charges and other operating expenses	(574.0		)	-31	%	(4.5		)	—	%
Operating income (loss)	$	(166.7	)	-9	%	$	331.7		21	%

Revenues for 2014 increased by $245.1 million or 16% compared to 2013 as a result of the following (in millions):



	Increase (decrease)

Addition of the Rowan Renaissance and Rowan Resolute	$	170.5
Higher average day rates for existing rigs	57.3
Revenues for reimbursable costs	17.6
Other, net	(0.3		)
Net increase	$	245.1

Operating costs other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses for 2014 increased by $130.4 million or 15% over the prior year, as a result of the following (in millions):



	Increase

Addition of the Rowan Renaissance and Rowan Resolute	$	62.0
Higher costs due to rigs in shipyard	29.7
Expansion of foreign shorebases	15.8
Reimbursable costs	17.6
Other, net	5.3
Net increase	$	130.4

For purposes of this discussion, we define our operating margin as revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses, gains or losses on asset disposals, litigation settlement, and material charges and other operating expenses. Operating margin as we have defined it is a non-GAAP financial measure. The impact on operating margin of those excluded items are discussed separately below and have been excluded solely to simplify the discussion. Operating margin, as defined, increased to approximately 46% in 2014 from 45% in 2013. Depreciation increased by $51.6 million or 19% over 2013 primarily due to the addition of the drillships.

Selling, general and administrative expenses decreased by $5.5 million or 4% primarily due to fewer professional services and fees for corporate restructuring, initiatives related to the Company's internationalization and entry into the ultra-deepwater market; and to lower equity compensation expense resulting from fair market adjustments to certain share-based awards recorded under the liability method of accounting.

Net gain on property disposals in 2013 included a $19.1 million gain resulting from the sale of the Rowan Paris , one of the Company's older rigs, for approximately $40.0 million in cash.

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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. Such amount was recognized in operating income in 2014.

Long-lived assets are required to be reviewed for impairment whenever circumstances indicate their carrying values may not be recoverable. Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling rigs over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up drilling units were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized a noncash asset impairment charge of $565.7 million in the fourth quarter of 2014. Material charges for 2014 also included an $8.3 million noncash impairment charge on a Company aircraft, which we sold later in 2014 at an immaterial loss. Material charges and other operating expenses for 2013 consisted of a $4.5 million noncash asset impairment charge on a dock and maintenance facility.

In 2014 , we recognized an income tax benefit of $150.7 million on a $269.6 million pretax loss from continuing operations, as compared to a provision of $8.7 million on $261.2 million of pretax income from continuing operations in 2013 . The benefit in 2014 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 (see Note 7 of Notes to Consolidated Financial Statements). The low effective tax rate of 3.3% in 2013 was due in part to 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; a significant proportion of income earned in low-tax foreign jurisdictions; the implementation of our international restructuring plan, which resulted in the utilization of non-U.S. subsidiaries’ foreign taxes paid as credits against U.S. taxable income; additional tax basis in fixed assets due to the application of a ruling in a third-party tax case to the Company's situation; and the continued recognition of tax benefits related to the application of certain tax planning strategies implemented in 2012 related to interest capitalization.

2013 Compared to 2012

Our operating results for the years ended December 31, 2013 and 2012 are highlighted below (dollars in millions):



	2013					2012
	Amount			% of Revenues		Amount			% of Revenues
Revenues	$	1,579.3		100	%	$	1,392.6		100	%
Operating costs (excluding items below)	(860.9		)	-55	%	(752.2		)	-54	%
Depreciation expense	(271.0		)	-17	%	(247.9		)	-18	%
Selling, general and administrative expenses	(131.3		)	-8	%	(99.7		)	-7	%
Net gain on property disposals	20.1			1	%	2.5			0	%
Litigation settlement	—			—	%	4.7			—	%
Material charges and other operating expenses	(4.5		)	—	%	(44.9		)	-3	%
Operating income	$	331.7		21	%	$	255.1		18	%

Revenues for 2013 increased by $186.7 million or 13% compared to 2012 as a result of the following (in millions):



	Increase

Higher average day rates for existing rigs	$	125.2
Higher utilization of existing rigs	48.1
Other, net	13.4
Net increase	$	186.7

Operating costs other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses for 2013 increased by $108.7 million or 14% over the prior year, as a result of the following (in millions):

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	Increase

Increase due to rigs operating in higher-cost locations	$	55.6
Expansion of foreign shorebases	14.6
Operations support	12.7
Repair costs for the Rowan Gorilla VII	12.4
Other, net	13.4
Net increase	$	108.7

Our operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses) was approximately 45% in 2013 and 46% in 2012. Depreciation increased by $23.1 million or 9% over 2012 due to capital improvements to the fleet.

In July 2013, while the Rowan Gorilla VII was changing locations, the legs were severely damaged as the hull was being lowered into the water. Extended poor weather conditions in the North Sea hampered the rig's ability to return to its operating location following repairs. As a result of the incident, the rig was out of service for 174 days in 2013, resulting in a loss of revenue of approximately $43 million. In 2013, we incurred $12.4 million in incremental repair costs to the rig, which are included in direct operating costs. The rig returned to service in February 2014.

Selling, general and administrative expenses increased by $31.7 million or 32% primarily due to professional services and fees for corporate restructuring, initiatives related to the Company's internationalization and entry into the ultra-deepwater market; the noncash impact of a new retirement policy on the vesting period for share-based compensation; incremental incentive-based compensation based on the Company's projected performance; and fair market adjustments to certain share-based awards based on changes in the share price.

In 2013, the Company sold the Rowan Paris , one of the Company's older rigs, for approximately $40.0 million in cash and recognized a gain of $19.1 million.

Material charges and other operating expenses for 2013 consisted of a $4.5 million noncash asset impairment charge on a maintenance and storage facility.

Litigation settlement for 2012 includes a $4.7 million gain for cash received in connection with a legal settlement.

Material charges and other operating expenses for 2012 consisted of $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the 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 noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee.

In 2013, we recognized income tax expense of $8.7 million on $261.2 million of pretax income from continuing operations, as compared to a benefit of $19.8 million on $183.5 million of pretax income from continuing operations in 2012. The low effective tax rate of 3.3% in 2013 was due in part to the amortization of deferred intercompany gains and losses related to outbounding certain U.S.-owned rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; the implementation of our international restructuring plan, which resulted in the utilization of non-U.S. subsidiaries’ foreign taxes paid as credits against U.S. taxable income; additional tax basis in fixed assets due to the application of a ruling in a third-party tax case to the Company's situation; and the continued recognition of tax benefits related to the application of certain tax planning strategies implemented in 2012 related to interest capitalization. The recognition of an income tax benefit in 2012 was due in part to the amortization of deferred intercompany gains and losses related to outbounding certain rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; and the implementation of tax planning strategies with regard to capitalized interest.

Outlook

Our backlog by geographic area as of the date of our most recent Fleet Status Report is presented below (in millions):

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	February 19, 2015
	Jack-ups		Drillships		Total

US GOM	$	14	$	1,892	$	1,906
Middle East	1,666		—		1,666
North Sea	942		—		942
West Africa	—		274		274
Southeast Asia	61		—		61
Other international	241		—		241
Total backlog	$	2,924	$	2,166	$	5,090

For purposes of computing backlog, we have assumed the Rowan Renaissance, which is currently operating in West Africa, will relocate to the US GOM for the third year of its three-year contract based on discussions with the customer, where it would earn a contract day rate of $630,000. Alternatively, if the rig continues to operate in West Africa during year three, the contract day rate would be $660,000.

We estimate our backlog will be realized as follows (in millions):



	February 19, 2015
	Jack-ups		Drillships		Total

2015	$	1,038	$	670	$	1,708
2016	793		889		1,682
2017	489		589		1,078
2018	256		18		274
2019 and later years	348		—		348
Total backlog	$	2,924	$	2,166	$	5,090

For comparative purposes, our backlog by geographic area as reported in our 2013 Form 10-K, is set forth below (in millions):



	February 20, 2014
	Jack-ups		Drillships		Total

US GOM	$	84	$	1,777	$	1,861
North Sea	1,405		—		1,405
Middle East	1,029		—		1,029
West Africa	—		226		226
Southeast Asia	160		—		160
Other international	297		—		297
Total backlog	$	2,975	$	2,003	$	4,978

As a result of the dramatic decline in oil and gas prices over the last half of 2014, many oil and gas operators have significantly reduced their capital expenditure budgets for 2015. In addition, the offshore drilling market is currently experiencing an oversupply of drilling units as newbuilds enter the market. In the current environment, we may have difficulty securing new drilling contracts; we may be forced to enter into contracts at unattractive day rates; customers may seek to renegotiate or terminate existing contracts; and we may have difficulty selling older rigs. We currently have a mix of short- and long-term contracts, which we expect will help to mitigate the effect of a prolonged downturn. Nevertheless, we are unable to predict the duration of the current market condition or its financial effects on the Company.

Newbuild deliveries in recent years have increased the pool of rigs competing for contracts in many areas in which we operate, putting significant downward pressure on utilization and day rates. As of February 16, 2015, there were approximately 132 jack-up rigs under construction worldwide for delivery through 2017 (24% of the current jack-up fleet), including 53 that are considered

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high-specification (77% of the current high-specification fleet). Approximately 22 of these jack-up rigs, which are not contracted, are scheduled for delivery in 2015. Utilization and day rates in certain regions are expected to come under additional pressure as these rigs enter the worldwide fleet.

About 63% of our remaining available rig days in 2015 (excluding our three cold-stacked rigs) and 43% of available rig days in 2016 were under contract or commitment as of February 19, 2015 . As of that date, we had three rigs without contracts (excluding the three cold-stacked rigs). Failure to obtain or renew contracts would significantly impact the Company's results of operations and cash flow.

Out-of-Service Days – We define out-of-service days as those days when a rig is (or 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 period of drilling operations.

Our out-of-service days totaled approximately 10% of available rig days in 2014 and 2013, down from 12% in 2012. We estimate planned out-of-service time for 2015 to range from 3% to 6%.

Operational Downtime – We define operational downtime as the unbillable time a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures. Our operational downtime, which is in addition to out-of-service days, was approximately 1% of in-service days for both 2014 and 2013, down from 2% in 2012. We estimate operational downtime for our jack-up fleet will typically approximate 2.5% of operating days on a go-forward basis.

Following its January 2014 delivery from the shipyard and commencement of operations in April, the Rowan Renaissance ultra-deepwater drillship experienced 41 off-rate days, which included 23 out-of-service days for commissioning of late-arriving equipment and 18 days of operational downtime in 2014. Our second ultra-deepwater drillship, the Rowan Resolute, began operating in the US GOM in mid October 2014 and experienced 27 out-of-service days for commissioning and no operational downtime days in 2014.

We estimate that operational downtime for our newly constructed ultra-deepwater drillships will be less than 5% of operating days following an initial break-in period of operations, which could range from approximately six months to one year, during which time the actual rate could be somewhat higher.

Other Matters – During the fourth quarter of 2014, we engaged a broker to assist in the potential sale of certain of our older jack-up rigs.

LIQUIDITY AND CAPITAL RESOURCES

Key balance sheet amounts and ratios at December 31 were as follows (dollars in millions):



	2014			2013
Cash and cash equivalents	$	339.2		$	1,092.8
Current assets (excluding assets of discontinued operations)	$	941.1		$	1,505.1
Current liabilities (excluding liabilities of discontinued operations)	$	333.2		$	334.5
Current ratio (excluding assets and liabilities of discontinued operations)	2.82			4.50
Long-term debt	$	2,807.3		$	2,008.7
Shareholders' equity	$	4,691.4		$	4,893.8
Debt to capitalization ratio	37		%	29		%

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Sources and uses of cash and cash equivalents were as follows:



	2014			2013			2012
Net operating cash flows	$	423.0		$	623.2		$	393.7
Borrowings, net of issue costs	792.7			—			1,102.9
Payment of cash dividends	(37.7		)	—			—
Capital expenditures	(1,958.2		)	(607.3		)	(685.2		)
Debt repayments	—			—			(238.5		)
Proceeds from asset disposals	22.0			44.5			10.5
Proceeds from equity compensation plans	4.7			2.9			0.6
All other, net	(0.1		)	5.5			1.2
Total net (use) sources	$	(753.6	)	$	68.8		$	585.2

Operating Cash Flows

Cash flows from operations decreased to approximately $423 million in 2014 from $623 million in 2013 . Operating cash flows for 2014 compared to 2013 were negatively impacted by an increase in trade and other receivables, receipt of an approximately $53 million U.S. federal income tax refund in 2013, and higher pension contributions in 2014. Operating cash flows for 2013 increased by $229 million over 2012 primarily due to higher day rates and rig utilization, receipt of an approximately $53 million U.S. federal income tax refund, improved timing of collections of accounts receivables and a reduction in the required minimum pension contribution as a result of U.S. legislation.

The Company has not provided deferred income taxes on undistributed earnings of its non-U.K. subsidiaries, including RCI's non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Generally, earnings of non-U.K. subsidiaries in which RCI does not have a direct or indirect ownership interest can be distributed to the Company without imposition of either U.K. or local country tax.

As of December 31, 2014 , RCI's portion of the unremitted earnings of its non-U.S. subsidiaries was approximately $205 million . Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. It is not practicable to estimate the amount of deferred tax liability related to the undistributed earnings, and RCI's non-U.S. subsidiaries have no plan to distribute earnings in a manner that would cause them to be subject to U.S., U.K. or other local country taxation.

At December 31, 2014 , RCI’s non-U.S. subsidiaries held approximately $125 million of the $339 million 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 its operational and capital investment requirements and otherwise allow us to continue to maintain its policy of reinvesting such undistributed earnings outside the U.K. and U.S. indefinitely.

Investing Activities

During 2014, we took delivery of three of our four newly constructed ultra-deepwater drillships, with the fourth expected to be delivered in late March 2015.

Capital expenditures in 2014 totaled $1.958 billion and included the following:


•	$1.560 billion for construction of the ultra-deepwater drillships Rowan Renaissance, Rowan Resolute, Rowan Reliance and Rowan Relentless;


•	$345 million for improvements to the existing fleet, including contractually required modifications; and


•	$53 million for rig equipment inventory and other.

We currently estimate our 2015 capital expenditures to be approximately $850-$875 million, including $660-$685 million in connection with our two newbuild drillships, including costs for mobilization, commissioning, riser gas-handling equipment, software certifications and drillship fleet spares to support our deepwater operations. The remaining amount is related to existing fleet maintenance capital and worldwide spares.

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We expect to fund our 2015 capital expenditures using available cash, cash flows from operations and our revolving credit facility.

The capital budget reflects an appropriation of money that we may or may not spend, and the timing of such expenditures may change. We will periodically review and adjust the capital budget as necessary based upon current and forecast cash flows and liquidity, anticipated market conditions in our business, the availability of financial resources, and alternative uses of capital to enhance shareholder value.

Capital expenditures for 2013 totaled $607 million and included $229 million towards construction of the Rowan Renaissance, Rowan Resolute, Rowan Reliance and Rowan Relentless; $323 million for improvements to the existing fleet, including contractually required modifications; and $55 million for rig equipment, inventory and other.

Capital expenditures for 2012 totaled $685 million and included $287 million towards construction of the Rowan Renaissance, Rowan Resolute, Rowan Reliance and Rowan Relentless; $350 million for improvements to the existing fleet, including contractually required modifications; and $48 million for rig equipment, inventory and other.

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, and $400 million aggregate principal amount of 5.85% Senior Notes due 2044. Net proceeds of the offering were approximately $792 million, which the Company used for its rig construction program and for general corporate purposes. Additionally, the Company amended and restated its credit agreement to increase the borrowing capacity under the revolving credit facility from $750 million to $1.0 billion, among other things. There were no amounts drawn under the revolving credit facility at December 31, 2014 .

As of December 31, 2014 , we had $2.8 billion of outstanding long-term debt consisting of $400 million principal amount of 5% Senior Notes due 2017; $500 million principal amount of 7.875% Senior Notes due 2019; $700 million principal amount of 4.875% Senior Notes due 2022; $400 million aggregate principal amount of 4.75% Senior Notes due 2024; $400 million principal amount of 5.4% Senior Notes due 2042; and $400 million aggregate principal amount of 5.85% Senior Notes due 2044 (together, the “Senior Notes”). The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 15 of Notes to Financial Statements in Item 8 of this Form 10-K).

Annual interest payments on the Senior Notes total $160 million . 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. The Company expects to utilize its revolving credit facility in the first or second quarter of 2015 to fund the final shipyard payment for the Rowan Relentless.

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, 2014 , was 37%.

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. Additionally, our credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2014 , and expects to remain in compliance throughout 2015 .

Cash Dividends

Prior to 2014, the Company had not paid a quarterly cash dividend since 2008. On April 25, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on May 20, 2014, to shareholders of record at the close of business on May 5, 2014. On July 31, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on August 26, 2014, to shareholders of record at the close of business on August 11, 2014. On October 30, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on November 25, 2014, to shareholders of record at the close of business on November 11, 2014. On January 29, 2015, the Board of Directors approved a quarterly cash dividend of $0.10 per share payable on March 3, 2015, to shareholders of record at the close of business on February 9, 2015.

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The capital reduction was authorized by our Board of Directors and approved by our shareholders at a general meeting in August 2014. The capital reduction was achieved through the issuance and cancellation of $2.0 billion of newly created Class C shares pursuant to a customary, court approved process in the U.K.

The capital reduction shares had no substantive economic rights, provided no voting rights and otherwise provided extremely limited rights ( e.g. , no right to receive any dividends or other distributions). The capital reduction shares were cancelled in September 2014, and $2.0 billion of shareholders’ equity of Rowan plc that was not previously available for distribution under U.K. law became available for dividends, future distributions or share repurchases, as may be determined by our Board of Directors, subject to compliance with applicable rules and limitations under U.K. law.

The capital reduction did not involve any distribution or repayment of capital, nor did it have an impact on the underlying net assets of the Company. There was no net impact on our shareholders’ equity as a result of the capital reduction.

Off-balance Sheet Arrangements and Contractual Obligations

The Company had no off-balance sheet arrangements as of December 31, 2014 or 2013 , 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, 2014, 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, including interest	$	4,392	$	160	$	720	$	779	$	2,733
Newbuild construction contracts	527		527		—		—		—
Purchase obligations	210		210		—		—		—
Operating leases	46		7		12		11		16
Total	$	5,175	$	904	$	732	$	790	$	2,749

As of December 31, 2014 , our liability for unrecognized tax benefits related to uncertain tax positions totaled $62.8 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 or other bank-issued guarantees in the normal course of our businesses, and had outstanding letters of credit of approximately $22.3 million at December 31, 2014 .

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, 2014 , our financial statements reflected an aggregate unfunded pension liability of $216 million . We expect to make minimum contributions to our defined benefit pension plans of approximately $22 million in 2015 , 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.

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

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Our significant accounting policies are presented in Note 2 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K. These policies and management judgments, assumptions and estimates made in their application underlie reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenues and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve carrying values of long-lived assets, pension and other postretirement benefit liabilities and costs (specifically assumptions used in actuarial calculations), and income taxes (particularly our estimated reserves for uncertain tax positions), as changes in such policies and/or estimates would produce significantly different amounts from those reported herein.

Impairment of long-lived assets and Depreciation

We evaluate the carrying value of our property and equipment, primarily our drilling rigs, whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Potential impairment indicators include rapid declines in commodity prices, stock prices, day rates and utilization, among others. The offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Similarly, during periods of excess supply, rigs may be contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.

Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.

Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling rigs over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized a noncash asset impairment charge of $565.7 million (approximately 7% of total assets) in the fourth quarter of 2014. Also in 2014, we recognized an $8.3 million noncash impairment charge on a Company aircraft, which we sold later in 2014 at an immaterial loss. (See Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.)

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 carrying values that differ from recorded amounts. In connection with the completion of the asset impairment test in 2014, we evaluated 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.

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, 2014 , included weighted average discount rates of 4.12% and 4.83% used to determine pension benefit obligations and net cost, respectively, an expected long-term rate of return on pension plan assets of 7.45% and annual healthcare cost increases ranging from 7.0% in 2015 to 4.5% in 2026 and beyond. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $121.2 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $5.2 million. A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2015 other postretirement benefit cost by $0.3 million . To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the

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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 7.45% at December 31, 2014 , from 8% at December 31, 2013 .

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 $55 million at December 31, 2014 , is properly recorded in accordance with the accounting guidelines.

Recent Accounting Pronouncements

In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity ("ASU 2014-08"), which limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results. Under current guidelines prior to the effective date of ASU 2014-08, many disposals that were routine in nature and not a change in an entity's strategy were reported in discontinued operations. The provisions of the new standard will apply to disposals (or classifications as held for sale) of components of an entity occurring in annual and interim periods beginning in 2015. We do not expect adoption of the standard will have a material effect on our financial statements or the notes thereto.

In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which sets forth a global standard for revenue recognition and which replaces most existing industry-specific guidance. We will be required to adopt the new standard in annual and interim reports for periods beginning January 1, 2017. We are currently evaluating the potential effect of the new guidance.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS

Our outstanding debt at December 31, 2014 , consisted entirely of fixed-rate debt with a carrying value of $2.807 billion and a weighted-average annual interest rate of 5.6%. 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.

In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and try to limit local currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive payment in the local currency. In such instances, we may be exposed to devaluation and other risk of exchange loss. In the event we terminate operations in such countries we may not be able to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where we hold approximately $15.2 million in Egyptian pounds, based on exchange rates in effect at January 31, 2015. We can provide no assurance we will be able to convert, utilize or repatriate such funds in the future.

Fluctuating commodity prices affect our future earnings materially to the extent that they influence demand for our products and services. As a general practice, we do not hold or issue derivative financial instruments and had no derivatives outstanding during the periods covered by this report.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA



INDEX	Page

Report of Independent Registered Public Accounting Firm	41
Management’s Report On Internal Control Over Financial Reporting	42
Report of Independent Registered Public Accounting Firm	43
Consolidated Balance Sheets, December 31, 2014 and 2013	44
Consolidated Statements of Income for the Years Ended December 31, 2014, 2013 and 2012	45
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012	46
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2014, 2013 and 2012	47
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012	48
Notes to Consolidated Financial Statements	49
Selected Quarterly Financial Data (Unaudited)	83

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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, 2014 and 2013, and the related consolidated statements of income, comprehensive income, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Rowan Companies plc and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2014, 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 March 2, 2015 expressed an unqualified opinion on the Company’s internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2015

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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, 2014 .

The registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements included in our 2014 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
Chief Executive Officer	Executive Vice President, Chief Financial Officer and Treasurer


March 2, 2015	March 2, 2015

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

Rowan Companies plc

Houston, Texas

We have audited the internal control over financial reporting of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014, of the Company and our report dated March 2, 2015 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

March 2, 2015

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ROWAN COMPANIES PLC

CONSOLIDATED BALANCE SHEETS



	December 31,
	2014			2013
	(In thousands, except shares)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	339,154		$	1,092,844
Receivables - trade and other	545,204			344,546
Prepaid expenses and other current assets	29,253			45,538
Deferred income taxes - net	27,485			22,137
Assets of discontinued operations	—			23,813
Total current assets	941,096			1,528,878

PROPERTY, PLANT AND EQUIPMENT:
Drilling equipment	7,639,171			7,040,451
Construction in progress	1,023,646			1,009,380
Other property and equipment	137,365			147,884
Property, plant and equipment - gross	8,800,182			8,197,715
Less accumulated depreciation and amortization	1,367,970			1,811,960
Property, plant and equipment - net	7,432,212			6,385,755

Other assets	37,884			61,128

TOTAL ASSETS	$	8,411,192		$	7,975,761

LIABILITIES AND SHAREHOLDERS' EQUITY
CURRENT LIABILITIES:
Accounts payable - trade	$	102,773		$	123,976
Deferred revenues	36,189			54,515
Accrued liabilities	194,259			155,971
Liabilities of discontinued operations	—			20,122
Total current liabilities	333,221			354,584

Long-term debt	2,807,324			2,008,700
Other liabilities	368,266			289,061
Deferred income taxes - net	210,982			429,655
Commitments and contingent liabilities (Note 7)	—			—

SHAREHOLDERS' EQUITY:
Class A Ordinary Shares, $0.125 par value, 124,828,807 and 124,778,407 shares issued at December 31, 2014 and 2013, respectively	15,604			15,597
Additional paid-in capital	1,436,910			1,407,031
Retained earnings	3,466,993			3,619,540
Cost of 264,903 and 542,475 treasury shares at December 31, 2014 and 2013, respectively	(7,990		)	(5,962		)
Accumulated other comprehensive loss	(220,118		)	(142,445		)
Total shareholders' equity	4,691,399			4,893,761

TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY	$	8,411,192		$	7,975,761

See Notes to Consolidated Financial Statements.

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ROWAN COMPANIES PLC

CONSOLIDATED STATEMENTS OF INCOME



	Years ended December 31,
	2014			2013			2012
	(In thousands, except per share amounts)
REVENUES	$	1,824,383		$	1,579,284		$	1,392,607

COSTS AND EXPENSES:
Direct operating costs (excluding items below)	991,340			860,893			752,173
Depreciation and amortization	322,641			271,008			247,900
Selling, general and administrative	125,834			131,373			99,712
Gain on disposals of property and equipment	(1,778		)	(20,119		)	(2,502		)
Litigation settlement	(20,875		)	—			(4,700		)
Material charges and other operating expenses	573,950			4,453			44,972
Total costs and expenses	1,991,112			1,247,608			1,137,555

INCOME (LOSS) FROM OPERATIONS	(166,729		)	331,676			255,052

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	(103,934		)	(69,794		)	(50,717		)
Interest income	1,861			1,578			745
Loss on debt extinguishment	—			—			(22,223		)
Other - net	(805		)	(2,221		)	613
Total other income (expense) - net	(102,878		)	(70,437		)	(71,582		)

INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES	(269,607		)	261,239			183,470
Provision (benefit) for income taxes	(150,732		)	8,663			(19,829		)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(118,875		)	252,576			203,299

DISCONTINUED OPERATIONS:
Income (loss) from discontinued operations, net of tax	4,023			—			(22,697		)
Discontinued operations, net of tax	4,023			—			(22,697		)

NET INCOME (LOSS)	$	(114,852	)	$	252,576		$	180,602

INCOME (LOSS) PER SHARE - BASIC:
Income (loss) from continuing operations	$	(0.96	)	$	2.04		$	1.65
Discontinued operations	$	0.03		$	—		$	(0.18	)
Net income (loss)	$	(0.93	)	$	2.04		$	1.47

INCOME (LOSS) PER SHARE - DILUTED:
Income (loss) from continuing operations	$	(0.96	)	$	2.03		$	1.64
Discontinued operations	$	0.03		$	—		$	(0.18	)
Net income (loss)	$	(0.93	)	$	2.03		$	1.46

See Notes to Consolidated Financial Statements.

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ROWAN COMPANIES PLC

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME



	Years ended December 31,
	2014			2013		2012
	(In thousands)
NET INCOME (LOSS)	$	(114,852	)	$	252,576	$	180,602

OTHER COMPREHENSIVE INCOME (LOSS)
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income tax (benefit) expense of ($46,944), $34,092, and ($8,003), respectively	(87,293		)	63,315		(14,862		)
Net reclassification adjustments for amounts recognized in net income as a component of net periodic benefit cost, net of income tax expense of $5,261, $8,250, and $10,474, respectively	9,824			15,322		19,451

	(77,469		)	78,637		4,589

COMPREHENSIVE INCOME (LOSS)	$	(192,321	)	$	331,213	$	185,191

See Notes to Consolidated Financial Statements.

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ROWAN COMPANIES PLC

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY



	Shares outstanding	Class A Ordinary Shares/ Common stock			Additional paid-in capital			Retained earnings			Treasury shares			Accumulated other comprehensive income (loss)			Total shareholders' equity
	(In thousands)
Balance, January 1, 2012	123,581	$	15,947		$	1,478,233		$	3,186,362		$	(128,884	)	$	(225,671	)	$	4,325,987
Net shares issued (acquired) under share-based compensation plans	578	65			(21,212		)	—			17,511			—			(3,636		)
Share-based compensation	—	—			23,018			—			—			—			23,018
Excess tax benefit from share-based compensation plans	—	—			1,164			—			—			—			1,164
Retirement benefit adjustments, net of taxes of $2,472	—	—			—			—			—			4,589			4,589
Cancelation of treasury shares	—	(419		)	(109,068		)	—			109,487			—			—
Other	52	—			—			—			—			—			—
Net income	—	—			—			180,602			—			—			180,602
Balance, December 31, 2012	124,211	15,593			1,372,135			3,366,964			(1,886		)	(221,082		)	4,531,724
Net shares issued (acquired) under share-based compensation plans	26	4			2,330			—			(4,076		)	—			(1,742		)
Share-based compensation	—	—			27,056			—			—			—			27,056
Excess tax benefit from share-based compensation plans	—	—			3,690			—			—			—			3,690
Retirement benefit adjustments, net of taxes of $42,342	—	—			—			—			—			78,637			78,637
Other	—	—			1,820			—			—			—			1,820
Net income	—	—			—			252,576			—			—			252,576
Balance, December 31, 2013	124,237	15,597			1,407,031			3,619,540			(5,962		)	(142,445		)	4,893,761
Net shares issued (acquired) under share-based compensation plans	327	7			1,566			—			(2,028		)	—			(455		)
Share-based compensation	—	—			28,445			—			—			—			28,445
Excess tax benefit from share-based compensation plans	—	—			(132		)	—			—			—			(132		)
Retirement benefit adjustments, net of tax benefit of $41,683	—	—			—			—			—			(77,469		)	(77,469		)
Dividends	—	—			—			(37,695		)	—			—			(37,695		)
Other	—	—			—			—			—			(204		)	(204		)
Net loss	—	—			—			(114,852		)	—			—			(114,852		)
Balance, December 31, 2014	124,564	$	15,604		$	1,436,910		$	3,466,993		$	(7,990	)	$	(220,118	)	$	4,691,399

See Notes to Consolidated Financial Statements.

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ROWAN COMPANIES PLC

CONSOLIDATED STATEMENTS OF CASH FLOWS



	Years ended Years ended December 31,
	2014			2013			2012
	(In thousands)
CASH PROVIDED BY OPERATIONS:
Net income (loss)	$	(114,852	)	$	252,576		$	180,602
Adjustments to reconcile net income (loss) to net cash provided by operations:
Depreciation and amortization	322,641			271,008			247,900
Provision for pension and postretirement benefits	25,117			32,010			39,484
Share-based compensation expense	34,547			33,931			24,808
Other postretirement benefit claims paid	(4,125		)	(3,470		)	(3,811		)
Gain on disposals of property, plant and equipment	(3,691		)	(20,119		)	(2,502		)
Deferred income taxes	(182,544		)	(33,559		)	(4,649		)
Contributions to pension plans	(54,834		)	(18,860		)	(42,055		)
Write-off of deferred debt issuance costs	—			—			690
Asset impairment charges	573,950			4,453			12,038
Changes in current assets and liabilities:
Receivables - trade and other	(200,658		)	30,784			(105,762		)
Prepaid expenses and other current assets	16,328			9,583			(9,879		)
Accounts payable	(20,629		)	32,373			(8,608		)
Accrued income taxes	4,891			(17,714		)	16,210
Deferred revenues	(18,326		)	2,175			16,120
Other current liabilities	72,897			(12,441		)	17,873
Net changes in other noncurrent assets and liabilities	(27,753		)	60,446			15,250
Net cash provided by operations	422,959			623,176			393,709

CASH USED IN INVESTING ACTIVITIES:
Capital expenditures	(1,958,227		)	(607,311		)	(685,256		)
Proceeds from disposals of property, plant and equipment	21,987			44,550			10,500
Net cash used in investing activities	(1,936,240		)	(562,761		)	(674,756		)

CASH PROVIDED BY FINANCING ACTIVITIES:
Proceeds from borrowings	793,380			—			1,104,929
Dividends paid	(37,695		)	—			—
Debt issue costs	(687		)	—			(2,026		)
Repayments of borrowings	—			—			(238,453		)
Proceeds from exercise of share options	4,725			2,911			588
Excess tax benefits from share-based compensation	(132		)	3,690			1,164
Other	—			1,820			—
Net cash provided by financing activities	759,591			8,421			866,202

(DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS	(753,690		)	68,836			585,155
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	1,092,844			1,024,008			438,853
CASH AND CASH EQUIVALENTS, END OF PERIOD	$	339,154		$	1,092,844		$	1,024,008

See Notes to Consolidated Financial Statements.

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NOTE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION

On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (Rowan plc), became the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies, and our place of incorporation was effectively changed from Delaware to the United Kingdom. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the terms “Rowan,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.

We are a global provider of offshore oil and gas contract drilling services utilizing a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, including one which is currently under construction. Historically, our primary focus has been on high-specification and premium jack-up rigs, which our customers use for exploratory and development drilling and associated drilling services. In 2009, we began executing a new strategic plan that included divesting non-core assets and investing in ultra-deepwater assets, with a goal of balancing earnings from jack-ups and deepwater rigs over the long term. In 2011 and 2012 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction of four ultra-deepwater drillships. During 2014, we took delivery of the first three drillships: the Rowan Renaissance, which commenced drilling operations offshore West Africa in April 2014; the Rowan Resolute, which commenced operations in the United States Gulf of Mexico (US GOM) in October 2014; and the Rowan Reliance, which commenced operations in the US GOM in February 2015. Our fourth drillship, the Rowan Relentless, is scheduled for delivery in late March 2015 and is expected to commence operations in the US GOM in the third quarter of 2015.

The Company conducts offshore drilling operations in various markets throughout the world including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East, West and North Africa, Southeast Asia and Trinidad.

The consolidated financial statements included herein include the accounts of Rowan plc and its subsidiaries, all of which are wholly owned. Intercompany balances and transactions have been eliminated in consolidation.

The financial information presented in this report does not constitute the Company's statutory accounts within the meaning of the U.K. Companies Act 2006 for the years ended December 31, 2014 or 2013 . The audit of the statutory accounts for the year ended December 31, 2014 , was not complete as of March 2, 2015 . These accounts will be finalized by the directors on the basis of the financial information presented herein and will be delivered to the Registrar of Companies in the U.K.

NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Revenue and Expense Recognition

Our drilling contracts generally provide for payment on a daily rate basis, and revenues are recognized as the work progresses with the passage of time. We occasionally receive lump-sum payments at the outset of a drilling assignment for equipment moves or modifications. Lump-sum fees received for equipment moves (and related costs) and fees received for equipment modifications or upgrades are initially deferred and amortized on a straight-line basis over the primary term of the drilling contract. The costs of contractual equipment modifications or upgrades and the costs of the initial move of newly acquired rigs are capitalized and depreciated in accordance with the Company’s fixed asset capitalization policy. The costs of moving equipment while not under contract are expensed as incurred. Revenues received but unearned are included in current and long-term liabilities and totaled $60.2 million and $81.8 million at December 31, 2014 and 2013 , respectively. Deferred contract costs are included in prepaid expenses and other assets and totaled $5.4 million and $19.8 million at December 31, 2014 and 2013 , respectively.

We recognize revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in the Company’s contract with the customer, and such items and amounts frequently vary between contracts. We recognize reimbursable costs on the gross

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basis, as both revenues and expenses, because we are the primary obligor in the arrangement, have discretion in supplier selection, are involved in determining product or service specifications and assume full credit risk related to the reimbursable costs.

Cash Equivalents

Cash equivalents consist of highly liquid temporary cash investments with maturities no greater than three months at the time of purchase.

Accounts Receivable and Allowance for Doubtful Accounts

The Company assesses the collectability of receivables and records adjustments to an allowance for doubtful accounts, which is recorded as an offset to accounts receivable, to cover the risk of credit losses. The allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the monitoring of credit quality. No allowance for doubtful accounts was required at December 31, 2014 or 2013.

The following table sets forth the components of Receivables - trade and other at December 31 (in thousands):



	2014		2013
Trade	$	524,712	$	323,679
Income tax	6,315		6,759
Other	14,177		14,108
Total receivables - trade and other	$	545,204	$	344,546

Property and Depreciation

We provide depreciation for financial reporting purposes under the straight-line method over the asset’s estimated useful life from the date the asset is placed into service until it is sold or becomes fully depreciated. In connection with the completion of the asset impairment test in 2014, we reduced salvage values for our jack-up rigs from 20 percent to 10 percent of historical cost effective December 31, 2014. Estimated useful lives and salvage values are presented below:



	Life (in years)	Salvage Value
Jack-up drilling rigs:
Hulls	35	10	%
Legs	30	10	%
Quarters	25	10	%
Drilling equipment	5 to 25	0% to 10%

Drillships:
Hull	35	10	%
Drilling equipment	5 to 25	0% to 10%

Drill pipe and tubular equipment	4	10	%
Other property and equipment	3 to 30	various

Expenditures for new property or enhancements to existing property are capitalized and depreciated over the asset’s estimated useful life. As assets are sold or retired, property cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in results of operations. The Company capitalizes a portion of interest cost incurred during the construction period. We capitalized interest in the amount of $57.6 million in 2014 , $48.7 million in 2013 and $33.4 million in 2012 .

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Expenditures for maintenance and repairs are charged to operations as incurred and totaled $161 million in 2014 , $152 million in 2013 and $132 million in 2012 .

Impairment of Long-lived Assets

We review the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate their carrying amounts may not be recoverable. For assets held and used, we determine recoverability by evaluating the undiscounted estimated future net cash flows based on projected day rates, operating costs and utilization of the asset under review. When the impairment of an asset is indicated, we measure the amount of impairment as the amount by which the asset’s carrying amount exceeds its estimated fair value. We measure fair value by estimating discounted future net cash flows under various operating scenarios (an income approach) and by assigning probabilities to each scenario in order to determine an expected value. The lowest level of inputs we use to value assets held and used in the business are categorized as “significant unobservable inputs,” which are Level 3 inputs in the fair value hierarchy. For assets held for sale, we measure fair value based on equipment broker quotes, less anticipated selling costs, which are considered Level 3 inputs in the fair value hierarchy.

Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling units over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up drilling units aggregating $840.8 million were not recoverable from their undiscounted cash flows and exceeded the rigs' estimated fair values. As a result, we recognized a noncash impairment charge of $565.7 million in the fourth quarter of 2014. We measured fair value using the income approach described above. Our estimate of fair value required us to use significant unobservable inputs including assumptions related to future demand for drilling services, supply of available rigs and day rates, among others.

Also in 2014, we recognized an $8.3 million impairment charge for the carrying value of a Company aircraft, which was used to support operations. We sold the aircraft later in 2014 and recognized an immaterial loss on sale. The asset had a carrying value of $12.7 million prior to the write-down. The amount of the impairment was based on actual sales prices for similar equipment obtained from a third-party dealer of such equipment. Quoted prices in active markets for similar equipment are considered a Level 2 input in the fair value hierarchy.

In 2013 we recognized a $4.5 million impairment charge for a dock and storage facility, which had a carrying value of $23.5 million prior to the write-down.

In 2012 we recognized a $5.2 million impairment charge for the Rowan Juneau, which had a carrying value of $18.7 million prior to the write-down.

Impairment charges are included in material charges and other operating expenses on the Consolidated Statements of Income.

Share-based Compensation

We recognize compensation cost for share-based awards on a straight-line basis over the requisite service period of the award. Compensation cost of awards granted beginning March 2013 that have retirement-eligibility provisions is recognized over the lessor of six months or the period from the grant date to the date the employee meets the retirement eligibility and certain other requirements.

Fair value of restricted shares and restricted share units awarded to employees is based on the market price of the stock on the date of grant. Compensation cost is recognized for awards that are expected to vest and is adjusted in subsequent periods if actual forfeitures differ from estimates.

Restricted share units granted to non-employee directors ("Director RSUs") vest one year following the grant date but may not be settled until the director terminates service from the board. Compensation cost is recognized over the one-year service period. Director RSUs may be settled in cash and/or shares of stock and are accounted for under the liability method of accounting. Fair value is based on the market price of the underlying stock on the grant date and compensation expense is adjusted for changes in fair value at each report date through the settlement date.

Performance-based awards consist of Performance Units, in which the payment is contingent on the Company's total shareholder return relative to an industry peer group. Fair value of Performance Units is determined using a Monte-Carlo simulation model. Performance Units are settled in cash and accounted for under the liability method of accounting. Compensation cost is recognized on a straight-line basis over the service period and is adjusted for changes in fair value at each report date through the vest date.

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Fair value of share appreciation rights ("SARs") is determined using the Black-Scholes option pricing model. The Company uses the simplified method for determining the expected life of SARs, because it does not have sufficient historical exercise data to provide a reasonable basis on which to estimate expected term, as permitted under US GAAP. The Company intends to share-settle SARs that are exercised and has therefore accounted for them as equity awards.

Foreign Currency Transactions

The U.S. dollar is the functional currency for all of our operations. Non-U.S. dollar transaction gains and losses are recognized in “other income” on the Consolidated Statements of Income. In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and try to limit local currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive payment in the local currency. In such instances, we may be exposed to devaluation and other risk of exchange loss. In the event we terminate operations in such countries we may not be able to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where we held approximately $16.3 million in Egyptian pounds, based on exchange rates in effect at December 31, 2014. Such amount was reclassified to noncurrent assets as of that date. We can provide no assurance we will be able to utilize or repatriate such funds in the future.

The Company recognized a net currency exchange gain of $0.05 million in 2014 , a net exchange loss of $2.3 million in 2013 and a net exchange gain of $0.5 million in 2012 .

Income Taxes

Rowan recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. Interest and penalties related to income taxes are included in income tax expense.

The Company does not provide deferred income taxes on undistributed earnings of its non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. Generally, earnings of non-U.K. subsidiaries in which RCI does not have a direct or indirect ownership interest can be distributed to the Company without the imposition of either U.K. or local country tax. See Note 11 for further information regarding the Company’s income taxes.

Income Per Common Share

Basic income per share is computed by dividing income available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional effect of all potentially dilutive securities, which includes nonvested restricted stock and units and dilutive share options and appreciation rights granted under share-based compensation plans. Dilutive securities are not included in the computation of loss per share when the Company reports a net loss from continuing operations as the impact would be antidilutive.

A reconciliation of shares for basic and diluted income per share is set forth below. There were no income adjustments to the numerators of the basic or diluted computations for the periods presented (in thousands):



	2014	2013	2012
Average common shares outstanding	124,067	123,517	122,998
Add dilutive securities:
Nonvested restricted shares and restricted share units	—	542	457
Share options and appreciation rights	—	409	417
Average shares for diluted computations	124,067	124,468	123,872

Share options and appreciation rights are antidilutive and excluded from diluted earnings per share when their exercise or strike price exceeds the average market price during the period, or when the Company reports a net loss from continuing operations. The following table sets forth antidilutive shares excluded from diluted earnings per share. Such securities could potentially dilute earnings per share in the future (in thousands):

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	2014	2013	2012
Share options and appreciation rights	2,234	1,065	658
Nonvested restricted shares and restricted share units	619	—	—
Total potentially dilutive shares	2,853	1,065	658

Recent Accounting Pronouncements

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which sets forth a global standard for revenue recognition and replaces most existing industry-specific guidance. We will be required to adopt the new standard in annual and interim reports for periods beginning January 1, 2017. We are currently evaluating the potential effect of the new guidance.

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NOTE 3 – DISCONTINUED OPERATIONS

In 2011, the Company completed the sale of its manufacturing and land drilling businesses. In 2012 we recognized a $3.9 million impairment charge relating to a land rig that was retained in connection with the sale of the manufacturing business. The rig had a carrying value of $26.9 million prior to the write-down. In 2014 we sold the rig, which had a net carrying value at the time of sale of $4.1 million , consisting of a $24.2 million asset and a $20.1 million liability previously included in assets and liabilities of discontinued operations. The Company received $6.0 million in cash resulting in a $4.0 million gain, net of tax effects. The impairment charge and gain on sale were classified as discontinued operations in 2012 and 2014, respectively.

Discontinued operations for 2012 also included write-offs of receivables assumed, a working capital adjustment to the sale price of the land drilling business, and a prior year return-to-provision tax adjustment, among other items. The following table sets forth the components of “Discontinued operations, net of tax” (in thousands):



				2014
	Manufacturing			Drilling			Total

Pretax income (loss)	$	1,882		$	—		$	1,882
Provision (benefit) for taxes on income	(2,141		)	—			(2,141		)
Discontinued operations, net of tax	$	4,023		$	—		$	4,023

				2012
	Manufacturing			Drilling			Total

Pretax income (loss)	$	(7,599	)	$	(3,603	)	$	(11,202	)
Provision (benefit) for taxes on income	15,751			(4,256		)	11,495
Discontinued operations, net of tax	$	(23,350	)	$	653		$	(22,697	)

NOTE 4 – ACCRUED LIABILITIES

Accrued liabilities at December 31 consisted of the following (in thousands):



	2014		2013
Pension and other postretirement benefits	$	26,219	$	49,659
Compensation and related employee costs	88,186		59,096
Interest	47,414		27,841
Income taxes	13,265		8,374
Other	19,175		11,001
Total accrued liabilities	$	194,259	$	155,971

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NOTE 5 – LONG-TERM DEBT

Long-term debt at December 31 consisted of the following (in thousands):



	2014		2013
5% Senior Notes, due September 2017 ($400 million principal amount; 5.1% effective rate)	$	399,244	$	398,961
7.875% Senior Notes, due August 2019 ($500 million principal amount; 8.0% effective rate)	498,500		498,171
4.875% Senior Notes, due June 2022 ($700 million principal amount; 4.6% effective rate)	711,640		713,208
4.75% Senior Notes, due January 2024 ($400 million principal amount; 4.8% effective rate)	399,631		—
5.4% Senior Notes, due December 2042 ($400 million principal amount; 5.4% effective rate)	398,417		398,360
5.85% Senior Notes, due January 2044 ($400 million principal amount; 5.9% effective rate)	399,892		—
Total long-term debt	$	2,807,324	$	2,008,700

As of December 31, 2014 , no principal payments are required with respect to our outstanding debt through 2016; $400 million becomes due in September 2017 , and $500 million becomes due in August 2019 .

On January 15, 2014, Rowan plc, as guarantor, and its 100% owned subsidiary, RCI, as issuer, completed the issuance and sale in a public offering of $400 million aggregate principal amount of its 4.75% Senior Notes due 2024 at a price to the public of 99.898% of the principal amount and $400 million aggregate principal amount of its 5.85% Senior Notes due 2044 at a price to the public of 99.972% of the principal amount. Net proceeds of the offering were approximately $792 million , which the Company used in its rig construction program and for general corporate purposes. Also in January, the Company amended and restated its credit agreement to increase the borrowing capacity under the revolving credit facility from $750 million to $1.0 billion , among other things. There were no amounts drawn under the revolving credit facility at December 31, 2014 .

The 5% Senior Notes due 2017, 7.875% Senior Notes due 2019, 4.875% Senior Notes due 2022, 4.75% Senior Notes due 2024, 5.4% Senior Notes due 2042, and 5.85% Senior Notes due 2044 (together, the "Senior Notes") are RCI’s senior unsecured obligations and rank senior in right of payment to all of its subordinated indebtedness and pari passu in right of payment with any of RCI’s future senior indebtedness, including any indebtedness under RCI’s senior revolving credit facility. The Senior Notes rank effectively junior to RCI’s future secured indebtedness, if any, to the extent of the value of its assets constituting collateral securing that indebtedness and to all existing and future indebtedness of its subsidiaries (other than indebtedness and liabilities owed to RCI).

All or part of the Senior Notes may be redeemed at any time for an amount equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date plus the applicable make-whole premium, if any.

The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 15).

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. Additionally, the revolving credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2014 .

NOTE 6 – FAIR VALUE MEASUREMENTS

Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by US GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of inputs that may be used to measure fair value are:


•	Level 1 – Quoted prices for identical instruments in active markets;

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•	Level 2 – Quoted market prices for similar instruments in active markets; quoted prices for identical instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and


•	Level 3 – Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable, such as those used in pricing models or discounted cash flow methodologies, for example.

The applicable level within the fair value hierarchy is the lowest level of any input that is significant to the fair value measurement.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Assets and liabilities measured at fair value on a recurring basis at December 31 are presented below (in thousands):



			Estimated fair value measurements
	Carrying value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)
December 31, 2014:
Assets - cash equivalents	$	314,570	$	314,570	$	—	$	—
Other assets	16,304		16,304		—		—

December 31, 2013:
Assets - cash equivalents	$	1,063,500	$	1,063,500	$	—	$	—

Trade receivables and trade payables, which are also required to be measured at fair value, have carrying values that approximate their fair values due to their short maturities.

In 2014 we terminated operations in Egypt, where we held approximately $16.3 million in Egyptian pounds, valued at the exchange rate in effect at December 31, 2014. We may be unable to convert, utilize or repatriate such funds in the future. As a result, we have reclassified such amount to a noncurrent asset as of December 31, 2014.

Assets Measured at Fair Value on a Nonrecurring Basis

Assets measured at fair value on a nonrecurring basis at December 31 are set forth below (in thousands):



			Estimated fair value measurements
	Carrying value		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Significant unobservable inputs (Level 3)		Total gains (losses)
December 31, 2014:
Property and equipment, net	$	275,148	$	—	$	—	$	275,148	$	(565,650	)

In 2014 we recognized a noncash asset impairment charge of $565.7 million on twelve of the Company's oldest jack-up drilling units with a net carrying value aggregating $840.8 million prior to the write-down. See Note 2, "Impairment of Long-lived Assets."

Other Fair Value Measurements

Those financial instruments not required to be measured at fair value consist of the Company’s publicly traded debt securities. Fair values of the Company’s debt securities were provided by one to two brokers who make a market in our debt securities and were measured using a market-approach valuation technique. Fair value was determined by adding a spread based on actual trades for that security (or a trader quote where actual trades were unavailable) to the applicable benchmark Treasury security with a

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comparable maturity in order to derive a current yield. The yield is then used to determine a price given the individual security’s coupon rate and maturity. Such inputs are considered “significant other observable inputs,” which are categorized as Level 2 inputs in the fair value hierarchy. Estimated fair values and related carrying values of our long-term debt securities at December 31 are presented below (in thousands):



	2014				2013
	Fair value		Carrying value		Fair value		Carrying value
5% Senior Notes, due 2017	$	414,552	$	399,244	$	433,879	$	398,961
7.875% Senior Notes, due 2019	570,626		498,500		603,177		498,171
4.875% Senior Notes, due 2022	680,165		711,640		711,816		713,208
4.75% Senior Notes, due 2024	377,703		399,631		—		—
5.4% Senior Notes, due 2042	345,835		398,417		368,602		398,360
5.85% Senior Notes, due 2044	366,132		399,892		—		—
	$	2,755,013	$	2,807,324	$	2,117,474	$	2,008,700

Concentrations of Credit Risk

We invest our excess cash primarily in time deposits and high-quality money market accounts at several large commercial banks with strong credit ratings, and therefore believe that our risk of loss is minimal.

The Company’s customers largely consist of international oil and gas exploration companies and national oil companies. We routinely evaluate the credit quality of potential customers. One customer, Saudi Aramco, accounted for 24% of consolidated revenues in 2014 and 29% of the consolidated trade receivable balance at December 31, 2014. In 2013 one customer accounted for 26% and another accounted for 11% of consolidated revenues. In 2012 one customer accounted for 29% and another accounted for 11% of consolidated revenues. The Company maintains reserves for credit losses when necessary and actual losses have been within management’s expectations.

NOTE 7 – COMMITMENTS AND CONTINGENT LIABILITIES

The Company has operating leases covering office space and equipment. Certain of the leases are subject to escalations based on increases in building operating costs. Rental expense attributable to continuing operations was $13.8 million in 2014 , $9.3 million in 2013 and $8.0 million in 2012 .

At December 31, 2014 , future minimum payments to be made under noncancelable operating leases were as follows (in thousands):



2015	$	7,045
2016	5,765
2017	5,655
2018	5,615
2019	5,573
Later years	16,138
	$	45,791

The following table presents the status of the Company’s rigs under construction as of December 31, 2014 . Project costs include capitalized interest (in millions):



	Actual/scheduled delivery date	Total estimated project costs		Total costs incurred through Dec. 31, 2014		Projected costs in 2015		Total future costs
Rowan Reliance	November 2014	$	722	$	687	$	35	$	35
Rowan Relentless	March 2015	750		258		492		492
		$	1,472	$	945	$	527	$	527

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In addition, the Company expects to incur approximately $120 million of capital expenditures in 2015 for mobilization, commissioning, riser gas-handling equipment, software certifications and drillship fleet spares to support its deepwater operations, and approximately $10 million for late-arriving equipment for the first two drillships delivered in 2014.

We have commitments for other purchase obligations totaling $210 million at December 31, 2014 .

We periodically employ letters of credit in the normal course of our business, and had outstanding letters of credit of approximately $22.3 million at December 31, 2014 .

Uncertain tax positions – In 2009, the Company recognized certain tax benefits as a result of applying the facts of a third-party tax case to the Company’s situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. Our position was challenged by the U.S. Internal Revenue Service ("IRS"). We appealed their findings and reached a settlement agreement in September 2014 with respect to three of the four years under review in the amount of approximately $36 million , including interest, which we collected in October 2014. A remaining year continues to be under examination. We plan to vigorously defend our position.

NOTE 8 – SHARE-BASED COMPENSATION PLANS

Under the 2013 Rowan Companies plc Incentive Plan (the Plan), the Compensation Committee of the Company’s Board of Directors is authorized to grant employees and nonemployee directors incentive awards covering up to 7,500,000 of our ordinary shares. The awards may be in the form of restricted share awards, restricted share units, options and share appreciation rights. In addition, the Compensation Committee may grant performance-based awards under the Plan, in which the amount earned is dependent on the achievement of certain long-term market or performance conditions over a specified period. As of December 31, 2014 , there were 5,619,212 shares available for future grant under the Plan.

Compensation cost charged to expense under all share-based incentive awards is presented below (in thousands):



	2014		2013		2012
Restricted shares and restricted share units	$	23,577	$	23,786	$	18,557
Share appreciation rights	3,724		6,412		5,358
Share options	—		23		152
Performance-based awards	7,246		3,710		741
Total compensation cost	$	34,547	$	33,931	$	24,808

As of December 31, 2014 , unrecognized compensation cost related to nonvested share-based compensation arrangements totaled $33.2 million , which is expected to be recognized over a weighted-average period of 1.8 years.

Restricted Shares – A restricted share represents an ordinary share subject to a vesting period that restricts its sale or transfer until the vesting period ends. In general, the restricted shares vest and the restrictions lapse in one-third increments each year over a three -year service period, or in some cases, cliff vest at the end of a three -year service period. Restricted share activity for the year ended December 31, 2014 , is summarized below:



	Number of Shares		Weighted-average grant-date fair value per share
Nonvested at January 1, 2014	553,441		$	36.50
Granted	—		—
Vested	(340,633	)	37.35
Forfeited	(2,254	)	36.10
Nonvested at December 31, 2014	210,554		$	35.13

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The aggregate fair value of restricted shares that vested in 2014 , 2013 and 2012 was $10.9 million , $16.2 million and $17.8 million , respectively, based on share prices on the vesting dates.

Employee Restricted Share Units – Restricted share units (RSUs) are rights to receive a specified number of ordinary shares upon vesting. RSUs granted to employees typically vest in one-third increments over a three -year service period or in some cases cliff vest at the end of three years. Employee RSU activity for the year ended December 31, 2014 , follows:



	Number of Shares		Weighted-average grant-date fair value per share
Nonvested at January 1, 2014	603,665		$	34.44
Granted	842,836		32.45
Vested	(279,191	)	34.17
Forfeited	(35,157	)	33.65
Nonvested at December 31, 2014	1,132,153		$	33.05

The aggregate fair value of employee RSUs that vested in 2014 and 2013 was $8.5 million and $0.5 million , respectively. The aggregate fair value of employee RSUs that vested in 2012 was not material.

Non-employee Director Restricted Share Units – RSUs granted to nonemployee directors generally cliff vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date and are settled in either cash or shares or a combination thereof at the discretion of the Compensation Committee determined at the time the director terminates service to the Board. Non-employee director RSU activity for the year ended December 31, 2014 , follows:



	Number of shares		Weighted-average grant-date fair value per share
Outstanding at January 1, 2014	250,648		$	32.42
Granted	54,041		31.10
Settled	(37,251	)	33.25
Outstanding at December 31, 2014	267,438		$	32.04

Vested at December 31, 2014	216,254		$	32.22

The number and aggregate settlement-date fair value of non-employee director RSUs settled during the year were as follows: 2014 – 37,251 RSUs at $1.2 million ; 2013 – 23,928 RSUs at $0.8 million ; 2012 – 43,072 RSUs at $1.4 million .

Other long-term liabilities at December 31, 2014 and 2013, included liabilities for non-employee director RSUs in the amount of $5.8 million and $8.1 million , respectively.

Performance-based Awards – The Committee may grant awards in which payment is contingent upon the achievement of certain market or performance-based conditions over a period of time specified by the Committee. Payment of such awards may be in ordinary shares or in cash as determined by the Committee.

In March 2014 the Company granted to certain members of management performance units (P-Units) that have a target value of $100 per unit. The amount ultimately earned with respect to the P-Units will depend on the Company’s total shareholder return (TSR) ranking compared to a group of peer companies over a three -year period ending December 31, 2016, and could range from zero to $200 per unit depending on performance. Twenty-five percent of the P-Units’ value is determined by the Company’s relative TSR ranking for each one-year period ended December 31, 2014 , 2015 , and 2016 , respectively, and 25% of the P-Units’ value is determined by the relative TSR ranking for the three -year period ended December 31, 2016 . Vesting of awards and any payment with respect to the P-Units would not occur until the third anniversary following the grant date. Any employee who terminates employment with the Company prior to the third anniversary for any reason other than retirement will not receive any payment with respect to P-Units unless approved by the Compensation Committee. The Compensation Committee has determined that any amount earned with respect to P-Units granted in 2014 would be settled in cash.

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The grant-date fair value of P-Units granted in 2014 was estimated to be $9.1 million . Fair value was estimated using the Monte Carlo simulation model, which considers the probabilities of the Company’s TSR ranking at the end of each performance period, and the amount of the payout at each rank to determine the probability-weighted expected payout. The Company uses liability accounting to account for the P-Units. Compensation is recognized on a straight-line basis over a maximum period of three years from the grant date and is adjusted for changes in fair value through the vesting date.

Other long-term liabilities at December 31, 2014 , and 2013, included liabilities for estimated P-Unit obligations in the amount of $11.6 million and $4.5 million , respectively.

No performance-based awards vested or settled in 2014 , 2013, or 2012.

Share Appreciation Rights – Share appreciation rights (SARs) give the holder the right to receive ordinary shares at no cost to the employee, or cash at the discretion of the Committee, equal in value to the excess of the market price of a share on the date of exercise over the exercise price. All SARs granted have exercise prices equal to the market price of the underlying shares on the date of grant. SARs become exercisable in one-third annual increments over a three -year service period and expire ten years following the grant date. The Company intends to share-settle any exercises of SARs and has therefore accounted for SARs as equity awards.

Fair values of SARs granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions:



	2013	2012
Expected life in years	6.0	6.0
Risk-free interest rate	1.058%	1.108%
Expected volatility	41.11%	44.30%
Weighted-average grant-date per-share fair value	$13.91	$15.28

No SARs were granted in 2014.

The Company uses the simplified method for determining the expected life of SARs because the Company does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term, as permitted under US GAAP.

SARs activity for the year ended December 31, 2014 , is summarized below:



	Number of shares under SARs		Weighted-average exercise price		Weighted-average remaining contractual term (in years)	Aggregate intrinsic value (in thousands)
Outstanding at January 1, 2014	1,831,695		$	30.45
Exercised	(67,707	)	17.39
Forfeited or expired	(2,718	)	35.47
Outstanding at December 31, 2014	1,761,270		$	30.94	5.0	$	2,451

Exercisable at December 31, 2014	1,444,099		$	30.15	4.3	$	2,451

The aggregate intrinsic value of SARs exercised in 2014 , 2013, and 2012 was $0.9 million , $0.5 million , and $0.4 million , respectively.

Share Options – Share options granted to employees generally became exercisable in one-third or one-quarter annual increments over a three or four -year service period at a price generally equal to the market price of the Company’s common shares on the date of grant. The Company has not granted share options since 2008. Unexercised options expire ten years after the grant date.

Share option activity for the year ended December 31, 2014 , is summarized below:

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	Number of shares under option		Weighted-average exercise price		Weighted-average remaining contractual term (in years)	Aggregate intrinsic value (in thousands)
Outstanding at January 1, 2014	384,643		$	24.52
Exercised	(189,000	)	25.00
Forfeited or expired	(10,239	)	43.85
Outstanding at December 31, 2014	185,404		$	22.96	2.7	$	835

Exercisable at December 31, 2014	185,404		$	22.96	2.7	$	835

The aggregate intrinsic value of options exercised was $1.4 million in 2014 , $2.0 million in 2013 and $0.3 million in 2012 .

Award modifications – In 2014 the Company accelerated the vesting of share-based awards and extended the exercise period for vested SARs held by two retiring employees whose awards would otherwise have been forfeited upon retirement. As a result of the modifications, the Company recognized additional compensation expense in 2014 in the amount of $1.7 million , net of forfeitures, which is included in selling, general and administrative expense. The Company valued the modified SARs assuming they are to be outstanding near or until such time as they expire.

In 2012 the Company modified share-based awards held by a retiring employee and recognized additional compensation expense in the amount of $2.3 million , which is included in material charges and other operating expenses.

NOTE 9 – PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS

The Company provides defined-benefit pension, health care and life insurance benefits upon retirement for certain full-time employees. Pension benefits are provided under the Rowan Pension Plan and the Restoration Plan of Rowan Companies, Inc. (the “Rowan SERP”), and health care and life insurance benefits are provided under the Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc.

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The following table presents the changes in benefit obligations and plan assets for the years ended December 31 and the funded status and weighted-average assumptions used to determine the benefit obligation at each year end (dollars in thousands):



	2014									2013
	Pension benefits			Other benefits			Total			Pension benefits			Other benefits			Total
Projected benefit obligations:
Balance, January 1	$	679,880		$	66,832		$	746,712		$	733,355		$	76,639		$	809,994
Interest cost	32,680			3,025			35,705			29,984			3,006			32,990
Service cost	14,573			1,067			15,640			12,309			1,445			13,754
Actuarial (gain) loss	114,030			6,779			120,809			(58,907		)	(10,788		)	(69,695		)
Plan amendments	259			—			259			3,585			—			3,585
Plan settlements	—			—			—			—			—			—
Exchange rate changes	(1,215		)	—			(1,215		)	—			—			—
Benefits paid	(32,254		)	(4,125		)	(36,379		)	(40,446		)	(3,470		)	(43,916		)
Balance, December 31	807,953			73,578			881,531			679,880			66,832			746,712

Plan assets:
Fair value, January 1	542,449			—			542,449			494,432			—			494,432
Actual return	27,596			—			27,596			69,603			—			69,603
Employer contributions	54,834			—			54,834			18,860			—			18,860
Plan settlements	—			—			—			—			—			—
Exchange rate changes	(665		)	—			(665		)	—			—			—
Benefits paid	(32,254		)	—			(32,254		)	(40,446		)	—			(40,446		)
Fair value, December 31	591,960			—			591,960			542,449			—			542,449
Net benefit liabilities	$	(215,993	)	$	(73,578	)	$	(289,571	)	$	(137,431	)	$	(66,832	)	$	(204,263	)

Amounts recognized in Consolidated Balance Sheet:
Accrued liabilities	$	(21,839	)	$	(4,380	)	$	(26,219	)	$	(45,599	)	$	(4,060	)	$	(49,659	)
Other liabilities (long-term)	(194,154		)	(69,198		)	(263,352		)	(91,832		)	(62,772		)	(154,604		)
Net benefit liabilities	$	(215,993	)	$	(73,578	)	$	(289,571	)	$	(137,431	)	$	(66,832	)	$	(204,263	)

Accumulated contributions in excess of (less than) net periodic benefit cost	$	124,248		$	(75,522	)	$	48,726		$	90,708		$	(75,825	)	$	14,883

Amounts not yet reflected in net periodic benefit cost:
Actuarial (loss) gain	(360,753		)	1,944			(358,809		)	(252,794		)	8,961			(243,833		)
Prior service credit	20,512			—			20,512			24,655			32			24,687
Total accumulated other comprehensive loss	(340,241		)	1,944			(338,297		)	(228,139		)	8,993			(219,146		)
Net benefit liabilities	$	(215,993	)	$	(73,578	)	$	(289,571	)	$	(137,431	)	$	(66,832	)	$	(204,263	)

Weighted-average assumptions:
Discount rate	4.12		%	3.95		%				4.58		%	4.74		%
Rate of compensation increase	4.15		%							4.15		%

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The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date and include the estimated effect of future salary increases. The accumulated benefit obligations, which are presented below for all plans in the aggregate at December 31, are based on services rendered to date, but exclude the effect of future salary increases (in thousands):



	2014		2013
Accumulated benefit obligation	$	801,749	$	676,320

Each of the Company’s pension plans has a benefit obligation that exceeds the fair value of plan assets.

The Company estimates the following amounts, which are classified in accumulated other comprehensive loss, a component of shareholders’ equity, will be recognized as net periodic benefit cost in 2015 (in thousands):



	Pension benefits			Other retirement benefits		Total
Actuarial (loss) gain	$	(25,587	)	$	—	$	(25,587	)
Prior service credit	4,519			—		4,519
Total amortization	$	(21,068	)	$	—	$	(21,068	)

In 2012 a pension plan that was assumed by the Company in connection with the sale of its former manufacturing operations made lump sum payments totaling $19.0 million , which exceeded the threshold that required the recognition of a settlement loss in the amount of $8.7 million . Such amount is classified within material charges and other operating expenses on the Consolidated Statements of Income.

The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in thousands):



	2014			2013			2012
Service cost	$	14,573		$	12,309		$	10,742
Interest cost	32,680			29,984			30,613
Expected return on plan assets	(41,592		)	(38,305		)	(36,958		)
Recognized actuarial loss	19,861			28,454			25,504
Amortization of prior service cost	(4,507		)	(4,736		)	(4,647		)
Settlement loss recognized	—			—			8,742
Net periodic pension cost	$	21,015		$	27,706		$	33,996
Less: Discontinued operations	—			—			(402		)
Continuing operations	$	21,015		$	27,706		$	33,594

Discount rate	4.83		%	4.16		%	4.58		%
Expected return on plan assets	8.00		%	8.00		%	8.00		%
Rate of compensation increase	4.15		%	4.15		%	4.15		%

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The components of net periodic cost of other postretirement benefits and the weighted average discount rate used to determine net cost were as follows (dollars in thousands):



	2014			2013			2012
Service cost	$	1,067		$	1,445		$	1,660
Interest cost	3,025			3,006			3,501
Amortization of transition obligation	—			—			475
Amortization of prior service cost	(32		)	(147		)	(147		)
Amortization of net (gain) loss	(237		)	—			—
Net periodic cost of other postretirement benefits	$	3,823		$	4,304		$	5,489

Discount rate	4.74		%	3.89		%	4.46		%

The assumed health care cost trend rates used to measure the expected cost of retirement health benefits was 7.0% for 2015 , gradually decreasing to 4.5% for 2026 and thereafter. A one-percentage-point change in the assumed health care cost trend rates would change the reported amounts as follows (in thousands):



	One-percentage-point change
	Increase		Decrease
Effect on total service and interest cost components for the year	$	269	$	(229	)
Effect on postretirement benefit obligation at year-end	3,570		(3,097		)

The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal the plans’ expected investment return or the inflation rate plus 3% , whichever is greater; to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities; to maintain liquidity sufficient to pay benefits when due; and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.

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Target allocations among asset categories and the fair values of each category of plan assets as of December 31, 2014 and 2013 , classified by level within the US GAAP fair value hierarchy is presented below. The plans will periodically reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in thousands):



	Target range	Total		Quoted prices in active markets for identical assets (Level 1)		Significant observable inputs (Level 2)		Significant unobservable inputs (Level 3)
December 31, 2014:
Equities:	53% to 69%
U.S. large cap	22% to 28%	$	159,541	$	—	$	159,541	$	—
U.S. small cap	4% to 10%	38,106		—		38,106		—
International all cap	21% to 29%	135,947		—		135,947		—
International small cap	2% to 8%	29,736		—		29,736		—
Real estate equities	0% to 13%	45,758		—		45,758		—
Fixed income:	25% to 35%
Cash and equivalents	0% to 10%	8,416		1		8,415		—
Aggregate	9% to 19%	85,412		—		85,412		—
Core plus	9% to 19%	86,325		86,325		—		—
Group annuity contracts		2,719		—		2,719		—
Total		$	591,960	$	86,326	$	505,634	$	—

December 31, 2013:
Equities:	53% to 69%
U.S. large cap	22% to 28%	$	125,061	$	—	$	125,061	$	—
U.S. small cap	4% to 10%	36,330		—		36,330		—
International all cap	21% to 29%	118,530		—		118,530		—
International small cap	2% to 8%	31,270		—		31,270		—
Real estate equities	0% to 13%	40,055		—		40,055		—
Fixed income:	25% to 35%
Cash and equivalents	0% to 10%	59,301		—		59,301		—
Aggregate	9% to 19%	66,074		—		66,074		—
Core plus	9% to 19%	65,828		65,828		—		—
Total		$	542,449	$	65,828	$	476,621	$	—

Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Securities in both the aggregate and core plus fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in non-U.S. securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. Group annuity contracts are invested in a combination of equity, real estate, bond and other investments in connection with a pension plan in Norway.

The following is a description of the valuation methodologies used for the pension plan assets at December 31, 2014 and 2013:

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•	Fair values of all U.S. equity securities, the international all cap equity securities and aggregate fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.


•	Fair value of international small cap equity securities categorized as Level 2 were held in a limited partnership fund which was valued monthly based on a net asset value.


•	The real estate categorized as Level 2 was held in two accounts (a commingled fund and a limited partnership). The assets in the commingled fund were valued monthly based on a net asset value and the assets in the limited partnership were valued quarterly based on a net asset value.


•	Cash and equivalents categorized as Level 2 were valued at cost, which approximates fair value.


•	Fair value of mutual fund investments in core plus fixed income securities categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.

To develop the expected long-term rate of return on assets assumption, the Company considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was reduced at 7.45% at December 31, 2014 , from 8% at December 31, 2013 .

The Company currently expects to contribute approximately $22 million to its pension plans in 2015 and to directly pay other postretirement benefits of approximately $4 million , net of estimated Medicare subsidy receipts.

Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in thousands):



	Pension benefits		Other postretirement benefits
Year ended December 31,
2015	$	66,000	$	4,690
2016	40,420		4,940
2017	40,950		5,130
2018	42,520		5,370
2019	43,730		5,640
2020 through 2023	236,460		25,220

The Company sponsors defined contribution plans covering substantially all employees. Employer contributions to such plans are expensed as incurred and totaled $19.0 million in 2014 , $14.3 million in 2013 and $9.6 million in 2012 .

NOTE 10 – SHAREHOLDERS’ EQUITY

Reclassifications from Accumulated Other Comprehensive Loss

The following table sets forth the significant amounts reclassified out of each component of accumulated other comprehensive loss and their effect on net income for the period (in thousands):



	2014			2013			2012
Amounts recognized as a component of net periodic pension and other postretirement benefit cost:
Amortization of net loss	$	(19,624	)	$	(28,454	)	$	(34,245	)
Amortization of transition obligation	—			—			(474		)
Amortization of prior service credit	4,539			4,882			4,794
Total before tax	(15,085		)	(23,572		)	(29,925		)
Tax (expense) benefit	5,261			8,250			10,474
Total reclassifications for the period, net of tax	$	(9,824	)	$	(15,322	)	$	(19,451	)

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Cash Dividends

Prior to 2014, the Company had not paid a regular quarterly cash dividend since 2008. On April 25, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on May 20, 2014, to shareholders of record at the close of business on May 5, 2014. On July 31, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on August 26, 2014, to shareholders of record at the close of business on August 11, 2014. On October 30, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on November 25, 2014, to shareholders of record at the close of business on November 11, 2014. On January 29, 2015, the Board of Directors approved a quarterly cash dividend of $0.10 per share payable on March 3, 2015, to shareholders of record at the close of business on February 9, 2015.

In September 2014 we completed a capital reduction under U.K. law, which increased the Company's distributable reserves and will provide the Company with greater flexibility to increase shareholder return in the form of dividends and share repurchases. The capital reduction was authorized by our Board of Directors and approved by our shareholders at a general meeting in August 2014. The capital reduction was achieved through the issuance and cancellation of $2.0 billion of newly created Class C shares pursuant to a customary, court approved process in the U.K.

Share Repurchase Program

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 percent 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 canceled. The authority to repurchase shares terminates in April 2017 unless otherwise reapproved by the Company’s shareholders prior to that time. U.K. law prohibits the Company from purchasing its shares in the open market because they are not traded on a recognized investment exchange in the U.K.

NOTE 11 – INCOME TAXES

RCI, our predecessor company, was domiciled in the U.S. and subject to a statutory rate of 35% . As a result of our redomestication to the U.K., we became subject to the U.K. statutory rate of 24% for the financial year beginning April 1, 2012; 23% for the financial year beginning April 1, 2013; and 21% for the financial year beginning April 1, 2014. The rate reduces to 20% for the financial year beginning April 1, 2015. We have computed our statutory tax rate for 2014 using a weighted average U.K. rate of 21.5% .

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The significant components of income taxes attributable to continuing operations are presented below (in thousands):



	2014			2013			2012
Current:
U.S.	$	(62,332	)	$	(38,025	)	$	(69,934	)
Non - U.S.	53,494			31,932			23,931
State	151			(5,141		)	100
Current expense (benefit)	(8,687		)	(11,234		)	(45,903		)
Deferred:
U.S.	(140,305		)	20,827			45,794
Non - U.S.	(1,740		)	(930		)	(19,720		)
Deferred provision (benefit)	(142,045		)	19,897			26,074
Total provision (benefit)	$	(150,732	)	$	8,663		$	(19,829	)

Differences between our provision for income taxes and the amount determined by applying the U.K. statutory rate to income before income taxes are set forth below (dollars in thousands):



	2014			2013			2012
U.K. Statutory rate	21.5		%	23.25		%	24.5		%
Tax at statutory rate	$	(57,965	)	$	60,738		$	44,950
Increase (decrease) due to:
Capitalized interest transactions	(20,145		)	(11,317		)	(39,204		)
Tax audit settlements	10,449			—			—
Foreign rate differential	38,216			(27,078		)	(27,591		)
Deferred intercompany gain/loss	(86,635		)	(9,062		)	(8,749		)
Change in valuation allowance	(3,570		)	8,381			2,806
Prior period adjustments	7,511			(9,837		)	4,482
Unrecognized tax benefits	(35,791		)	17,544			2,463
Excess compensation	657			1,022			1,432
Foreign taxes of subsidiaries for which U.S. federal income taxes have been provided	—			9,155			—
Foreign tax credits/deductions	(4,925		)	(31,078		)	(1,632		)
Other, net	1,466			195			1,214
Total provision (benefit)	$	(150,732	)	$	8,663		$	(19,829	)

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Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31 were as follows (in thousands):



	2014					2013
	Current		Noncurrent			Current		Noncurrent
Deferred tax assets:
Accrued employee benefit plan costs	$	30,912	$	118,096		$	27,295	$	76,619
U.S. net operating loss	—		46,675			—		28,486
U.K. net operating loss	—		2,708			—		8,280
Norway net operating loss	—		—			—		13,949
Trinidad net operating loss	—		13,034			—		—
Other NOLs and tax credit carryforwards	819		23,634			—		—
Other	888		28,069			700		28,744
Total deferred tax assets	32,619		232,216			27,995		156,078
Less: valuation allowance	—		(22,339		)	—		(25,909		)
Deferred tax assets, net of valuation allowance	32,619		209,877			27,995		130,169

Deferred tax liabilities:
Property, plant and equipment	—		369,095			—		514,612
Other	5,134		51,764			5,858		45,212
Total deferred tax liabilities	5,134		420,859			5,858		559,824
Net deferred tax asset (liability)	$	27,485	$	(210,982	)	$	22,137	$	(429,655	)

At December 31, 2014 , the Company had approximately $84 million of net operating loss carryforwards (NOLs) in the U.S., which expire at various times between 2035 and 2041; $49 million of NOLs in the U.S. attributable to the Company’s non-U.S. subsidiaries expiring in 2032 and which is subject to a valuation allowance of $36 million at December 31, 2014 ; $13.6 million of non-expiring NOLs in the U.K., of which $13.6 million is subject to a valuation allowance; and $52 million of non-expiring NOLs in Trinidad, of which $25 million is subject to a valuation allowance. In addition, at December 31, 2014 , the Company had $6 million of non-expiring NOLs in other foreign jurisdictions, of which $4 million is subject to a valuation allowance. Management has determined that no other valuation allowances were necessary at December 31, 2014 , as anticipated future tax benefits relating to all recognized deferred income tax assets are expected to be fully realized when measured against a more likely than not standard.

The Company has not provided deferred income taxes on undistributed earnings of the Company’s non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. The earnings of non-U.K. subsidiaries that are not subsidiaries of RCI can be distributed to Rowan plc without the imposition of either U.K. or local country tax.

At December 31, 2014 , 2013 and 2012 , we had approximately $48 million , $75 million and $58 million , respectively, of net unrecognized tax benefits attributable to continuing operations. At December 31, 2014 , $48 million would reduce the Company’s income tax provision if recognized. The Company believes it is reasonably possible that a decrease of up to $16 million may be necessary within the next twelve months.

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The following table sets forth the changes in the Company’s gross unrecognized tax benefits for the years ended December 31 (in thousands):



	2014			2013			2012
Gross unrecognized tax benefits - beginning of year	$	81,920		$	58,900		$	55,300
Gross increases - tax positions in prior period	19,928			11,021			700
Gross decreases - tax positions in prior period	(10,649		)	(4,114		)	—
Gross increases - current period tax positions	9,458			16,674			2,900
Settlements	(37,809		)	—			—
Lapse of statute of limitations	(8,188		)	(561		)	—
Gross unrecognized tax benefit - end of year	$	54,660		$	81,920		$	58,900

Interest and penalties relating to income taxes are included in income tax expense. At December 31, 2014 , 2013 and 2012 , accrued interest was $5.5 million , $2.4 million and $2.5 million , respectively, and accrued penalties were $2.6 million , $1.7 million and $1.4 million , respectively. Accrued interest and penalties relating to uncertain tax positions that are not actually assessed will be reversed in the year of the resolution.

In 2009, the Company recognized certain tax benefits as a result of applying the facts of a third-party tax case to the Company’s situation. That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years. Our position was challenged by the IRS. We appealed their findings and reached a settlement agreement in September 2014 with respect to three of the four years under review in the amount of approximately $36 million , including interest, which we collected in October 2014. A remaining year continues to be under examination. We plan to vigorously defend our position.

The Company’s U.S. federal tax returns for 2009 through 2013 are currently under audit by the IRS. Various state tax returns for 2009 and subsequent years remain open for examination. In the Company’s non-U.S. tax jurisdictions, returns for 2006 and subsequent years remain open for examination. We are undergoing other routine tax examinations in various U.S. and non-US. taxing jurisdictions in which the Company has operated. These examinations cover various tax years and are in various stages of finalization. The Company believes that any income taxes ultimately assessed by any taxing authorities will not materially exceed amounts for which the Company has already provided.

The components of income (loss) from continuing operations before income taxes were as follows (in thousands):



	2014			2013		2012
U.S.	$	(198,300	)	$	163,400	$	9,800
Non-U.S.	(71,300		)	97,800		173,700

NOTE 12 – GEOGRAPHIC AREA INFORMATION

The classifications of revenues and assets among geographic areas in the tables which follow were determined based on the physical location of assets. Because the Company’s offshore drilling rigs are mobile, classifications by area are dependent on the rigs’ location at the time revenues are earned, and may vary from one period to the next.

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Revenues by geographic area are set forth below (in thousands):



	2014		2013		2012
Saudi Arabia	$	443,873	$	412,799	$	376,406
United Kingdom	288,248		327,217		385,174
United States	283,835		240,820		209,296
Norway	213,393		168,931		131,251
Indonesia	125,851		90,027		13,677
Trinidad	94,722		101,262		98,764
Malaysia	93,962		127,216		88,960
Angola	80,499		—		—
Qatar	53,522		21,938		26,298
Spain (Canary Islands)	36,956		—		—
Morocco	33,027		—		—
Egypt	32,426		89,074		25,435
Namibia	25,479		—		—
Tunisia	18,590		—		—
Vietnam	—		—		37,346
Consolidated revenues	$	1,824,383	$	1,579,284	$	1,392,607

Long-lived assets by geographic area at December 31 are set forth below (in thousands):



	2014		2013		2012
Norway	$	1,394,994	$	503,308	$	495,518
United States	1,374,420		868,147		903,823
Rigs under construction	1,023,647		1,009,382		756,245
Saudi Arabia	932,714		1,204,915		1,103,220
United Kingdom	842,666		1,336,400		1,555,324
Spain (Canary Islands)	759,275		—		—
Malaysia	383,308		386,402		447,949
Trinidad	238,697		254,671		250,765
Indonesia	221,512		251,169		184,706
Tunisia	214,790		—		—
Qatar	46,156		85,240		153,282
Angola	33		—		—
Netherlands	—		270,409		—
Egypt	—		215,712		220,897
Consolidated long-lived assets	$	7,432,212	$	6,385,755	$	6,071,729

NOTE 13 – MATERIAL CHARGES AND OTHER OPERATING EXPENSES

Operating expenses in 2014 included noncash asset impairment charges aggregating $574.0 million , including $565.7 million in connection with twelve of the Company's oldest jack-up drilling units and $8.3 million for a Company aircraft, which we sold later in 2014 at an immaterial loss.

Operating expenses in 2013 included a $4.5 million noncash impairment charge on a dock and storage facility.

Operating expenses in 2012 included $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the 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,

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$8.1 million of noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee.

NOTE 14 – SUPPLEMENTAL CASH FLOW INFORMATION

Noncash investing and financing activities and other supplemental cash flow information follows (in thousands):



	2014		2013			2012
Accrued but unpaid additions to property and equipment at December 31	$	48,646	$	49,220		$	41,754
Cash interest payments in excess of interest capitalized	78,744		65,824			44,579
Net cash income tax payments (refunds)	8,549		(5,929		)	13,150

NOTE 15 – GUARANTEES OF REGISTERED SECURITIES

Rowan plc and its 100% -owned subsidiary, RCI, have entered into agreements providing for, among other things, the full, unconditional and irrevocable guarantee by Rowan plc of the prompt payment, when due, of any amount owed to the holders of RCI's Senior Notes.

The condensed consolidating financial information that follows is presented on the equity method of accounting in accordance with Rule 3-10 of Regulation S-X in connection with Rowan plc’s guarantee of the Senior Notes and reflects the corporate ownership

structure as of December 31, 2014. Financial information as of December 31, 2013, and for the years ended December 31, 2013 and 2012 has been recast to reflect changes to the corporate ownership structure that occurred in 2014 and is presented as though the structure at December 31, 2014, was in place at January 1, 2012.

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Balance Sheets

December 31, 2014

(in thousands)



	Rowan Companies plc (Parent)		RCI (Issuer)		Non-guarantor subsidiaries		Consolidating adjustments			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	45,909	$	48,580	$	244,665	$	—		$	339,154
Receivables - trade and other	26		4,317		540,861		—			545,204
Other current assets	424		47,986		8,328		—			56,738
Assets of discontinued operations	—		—		—		—			—
Total current assets	46,359		100,883		793,854		—			941,096

Property, plant and equipment - gross	—		610,063		8,190,119		—			8,800,182
Less accumulated depreciation and amortization	—		271,293		1,096,677		—			1,367,970
Property, plant and equipment - net	—		338,770		7,093,442		—			7,432,212

Investments in subsidiaries	4,624,874		5,863,509		—		(10,488,383		)	—
Due from affiliates	36,586		1,412,860		71,867		(1,521,313		)	—
Other assets	—		18,103		19,781		—			37,884
	$	4,707,819	$	7,734,125	$	7,978,944	$	(12,009,696	)	$	8,411,192

CURRENT LIABILITIES:
Accounts payable - trade	$	912	$	8,576	$	93,285	$	—		$	102,773
Deferred revenues	—		—		36,189		—			36,189
Accrued liabilities	400		100,167		93,692		—			194,259
Liabilities of discontinued operations	—		—		—		—			—
Total current liabilities	1,312		108,743		223,166		—			333,221

Long-term debt	—		2,807,324		—		—			2,807,324
Due to affiliates	9,282		45,457		1,466,574		(1,521,313		)	—
Other liabilities	5,826		312,575		49,865		—			368,266
Deferred income taxes - net	—		507,281		167,094		(463,393		)	210,982
Shareholders' equity	4,691,399		3,952,745		6,072,245		(10,024,990		)	4,691,399
	$	4,707,819	$	7,734,125	$	7,978,944	$	(12,009,696	)	$	8,411,192

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Balance Sheets

December 31, 2013

(in thousands)



	Rowan Companies plc (Parent)		RCI (Issuer)		Non-guarantor subsidiaries		Consolidating adjustments			Consolidated
CURRENT ASSETS:
Cash and cash equivalents	$	64,292	$	92,116	$	936,436	$	—		$	1,092,844
Receivables - trade and other	58		10,254		334,234		—			344,546
Other current assets	289		43,612		23,774		—			67,675
Assets of discontinued operations	—		23,813		—		—			23,813
Total current assets	64,639		169,795		1,294,444		—			1,528,878

Property, plant and equipment - gross	—		593,606		7,604,109		—			8,197,715
Less accumulated depreciation and amortization	—		243,666		1,568,294		—			1,811,960
Property, plant and equipment - net	—		349,940		6,035,815		—			6,385,755

Investments in subsidiaries	4,860,492		5,292,282		—		(10,152,774		)	—
Due from affiliates	136		1,491,831		231,164		(1,723,131		)	—
Other assets	—		60,343		785		—			61,128
	$	4,925,267	$	7,364,191	$	7,562,208	$	(11,875,905	)	$	7,975,761

CURRENT LIABILITIES:
Accounts payable - trade	$	1,359	$	13,409	$	109,208	$	—		$	123,976
Deferred revenues	—		—		54,515		—			54,515
Accrued liabilities	—		101,478		54,493		—			155,971
Liabilities of discontinued operations	—		20,122		—		—			20,122
Total current liabilities	1,359		135,009		218,216		—			354,584

Long-term debt	—		2,008,700		—		—			2,008,700
Due to affiliates	22,012		226,847		1,474,272		(1,723,131		)	—
Other liabilities	8,135		236,307		44,619		—			289,061
Deferred income taxes - net	—		574,828		320,532		(465,705		)	429,655
Shareholders' equity	4,893,761		4,182,500		5,504,569		(9,687,069		)	4,893,761
	$	4,925,267	$	7,364,191	$	7,562,208	$	(11,875,905	)	$	7,975,761

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Income Statements

Year ended December 31, 2014

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
REVENUES	$	—		$	63,811		$	1,824,623		$	(64,051	)	$	1,824,383

COSTS AND EXPENSES:
Direct operating costs (excluding items below)	—			3,699			1,048,235			(60,594		)	991,340
Depreciation and amortization	—			13,767			307,693			1,181			322,641
Selling, general and administrative	26,337			17			104,118			(4,638		)	125,834
Loss (gain) on disposals of property and equipment	—			(4,986		)	3,208			—			(1,778		)
Litigation settlement	—			—			(20,875		)	—			(20,875		)
Material charges and other operating expenses	—			12,191			561,759			—			573,950
Total costs and expenses	26,337			24,688			2,004,138			(64,051		)	1,991,112

INCOME (LOSS) FROM OPERATIONS	(26,337		)	39,123			(179,515		)	—			(166,729		)

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	—			(103,934		)	(3,102		)	3,102			(103,934		)
Interest income	340			3,558			1,065			(3,102		)	1,861
Dividends	—			—			—			—			—
Other - net	22,402			(22,291		)	(916		)	—			(805		)
Total other income (expense) - net	22,742			(122,667		)	(2,953		)	—			(102,878		)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(3,595		)	(83,544		)	(182,468		)	—			(269,607		)
Provision (benefit) for income taxes	—			(116,790		)	(36,255		)	2,313			(150,732		)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(3,595		)	33,246			(146,213		)	(2,313		)	(118,875		)

DISCONTINUED OPERATIONS, NET OF TAX	—			4,023			—			—			4,023

EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX	(111,257		)	(142,289		)	—			253,546			—

NET INCOME	$	(114,852	)	$	(105,020	)	$	(146,213	)	$	251,233		$	(114,852	)

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Income Statements

Year ended December 31, 2013

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
REVENUES	$	—		$	114,673		$	1,573,111		$	(108,500	)	$	1,579,284

COSTS AND EXPENSES:
Direct operating costs (excluding items below)	—			11,421			957,972			(108,500		)	860,893
Depreciation and amortization	—			39,658			231,350			—			271,008
Selling, general and administrative	28,456			3,119			99,798			—			131,373
Loss (gain) on disposals of property and equipment	—			130			(20,249		)	—			(20,119		)
Material charges and other operating expenses	—			—			4,453			—			4,453
Total costs and expenses	28,456			54,328			1,273,324			(108,500		)	1,247,608

INCOME (LOSS) FROM OPERATIONS	(28,456		)	60,345			299,787			—			331,676

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	—			(69,794		)	(213		)	213			(69,794		)
Interest income	210			528			1,053			(213		)	1,578
Loss on debt extinguishment	—			—			—			—			—
Other - net	9,997			(9,915		)	(2,303		)	—			(2,221		)
Total other income (expense) - net	10,207			(79,181		)	(1,463		)	—			(70,437		)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(18,249		)	(18,836		)	298,324			—			261,239
Provision (benefit) for income taxes	—			(21,757		)	54,865			(24,445		)	8,663

NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(18,249		)	2,921			243,459			24,445			252,576

DISCONTINUED OPERATIONS, NET OF TAX	—			—			—			—			—

EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX	270,825			114,805			—			(385,630		)	—

NET INCOME	$	252,576		$	117,726		$	243,459		$	(361,185	)	$	252,576

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Income Statements

Year ended December 31, 2012

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
REVENUES	$	—		$	133,346		$	1,362,955		$	(103,694	)	$	1,392,607

COSTS AND EXPENSES:
Direct operating costs (excluding items below)	—			35,057			820,810			(103,694		)	752,173
Depreciation and amortization	—			50,377			197,523			—			247,900
Selling, general and administrative	17,508			14,686			67,518			—			99,712
Loss (gain) on disposals of property and equipment	—			(572		)	(1,930		)	—			(2,502		)
Litigation settlement	—			(4,700		)	—			—			(4,700		)
Material charges and other operating expenses	13,835			19,176			11,961			—			44,972
Total costs and expenses	31,343			114,024			1,095,882			(103,694		)	1,137,555

INCOME (LOSS) FROM OPERATIONS	(31,343		)	19,322			267,073			—			255,052

OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized	—			(50,513		)	(279		)	75			(50,717		)
Interest income	74			362			384			(75		)	745
Loss on debt extinguishment	—			(21,603		)	(620		)	—			(22,223		)
Other - net	4,920			(5,065		)	758			—			613
Total other income (expense) - net	4,994			(76,819		)	243			—			(71,582		)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES	(26,349		)	(57,497		)	267,316			—			183,470
Provision (benefit) for income taxes	—			(87,065		)	59,010			8,226			(19,829		)

NET INCOME (LOSS) FROM CONTINUING OPERATIONS	(26,349		)	29,568			208,306			(8,226		)	203,299

DISCONTINUED OPERATIONS, NET OF TAX	—			(22,697		)	—			—			(22,697		)

EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX	206,951			124,677			—			(331,628		)	—

NET INCOME	$	180,602		$	131,548		$	208,306		$	(339,854	)	$	180,602

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income

Year ended December 31, 2014

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
NET LOSS	$	(114,852	)	$	(105,020	)	$	(146,213	)	$	251,233		$	(114,852	)

OTHER COMPREHENSIVE INCOME (LOSS):
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes	(87,293		)	(87,293		)	—			87,293			(87,293		)
Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes	9,824			9,824			—			(9,824		)	9,824
										—
	(77,469		)	(77,469		)	—			77,469			(77,469		)

COMPREHENSIVE LOSS	$	(192,321	)	$	(182,489	)	$	(146,213	)	$	328,702		$	(192,321	)

Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income

Year ended December 31, 2013

(in thousands)



	Rowan Companies plc (Parent)		RCI (Issuer)		Non-guarantor subsidiaries		Consolidating adjustments			Consolidated
NET INCOME	$	252,576	$	117,726	$	243,459	$	(361,185	)	$	252,576

OTHER COMPREHENSIVE INCOME:
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes	63,315		63,315		—		(63,315		)	63,315
Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes	15,322		15,322		—		(15,322		)	15,322

	78,637		78,637		—		(78,637		)	78,637

COMPREHENSIVE INCOME	$	331,213	$	196,363	$	243,459	$	(439,822	)	$	331,213

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Comprehensive Income

Year ended December 31, 2012

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries		Consolidating adjustments			Consolidated
NET INCOME	$	180,602		$	131,548		$	208,306	$	(339,854	)	$	180,602

OTHER COMPREHENSIVE INCOME:
Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes	(14,862		)	(14,862		)	—		14,862			(14,862		)
Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes	19,451			19,451			—		(19,451		)	19,451

	4,589			4,589			—		(4,589		)	4,589

COMPREHENSIVE INCOME	$	185,191		$	136,137		$	208,306	$	(344,443	)	$	185,191

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Cash Flows

Year ended December 31, 2014

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	63,769		$	82,504		$	452,905		$	(176,219	)	$	422,959

INVESTING ACTIVITIES:
Property, plant and equipment additions	—			(21,079		)	(1,937,148		)	—			(1,958,227		)
Proceeds from disposals of property, plant and equipment	—			14,574			7,413			—			21,987
Investments in consolidated subsidiaries	—			(105,261		)	—			105,261			—

Net cash used in investing activities	—			(111,766		)	(1,929,735		)	105,261			(1,936,240		)

FINANCING ACTIVITIES:
Advances (to) from affiliates	(49,182		)	(731,835		)	782,198			(1,181		)	—
Contributions from parent	—			—			105,261			(105,261		)	—
Proceeds from borrowings	—			793,380			—			—			793,380
Debt issue costs	—			(687		)	—			—			(687		)
Dividends paid	(37,695		)	(75,000		)	(102,400		)	177,400			(37,695		)
Excess tax benefits from share-based compensation	—			(132		)	—			—			(132		)
Proceeds from exercise of share options	4,725			—			—			—			4,725

Net cash provided by (used in) financing activities	(82,152		)	(14,274		)	785,059			70,958			759,591

DECREASE IN CASH AND CASH EQUIVALENTS	(18,383		)	(43,536		)	(691,771		)	—			(753,690		)
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	64,292			92,116			936,436			—			1,092,844

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	45,909		$	48,580		$	244,665		$	—		$	339,154

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Cash Flows

Year ended December 31, 2013

(in thousands)



	Rowan Companies plc (Parent)			RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(13,993	)	$	160,703		$	476,466		$	—		$	623,176

INVESTING ACTIVITIES:
Property, plant and equipment additions	—			(49,594		)	(557,717		)	—			(607,311		)
Proceeds from disposals of property, plant and equipment	—			2,432			42,118			—			44,550
Investments in consolidated subsidiaries	(100		)	(162,379		)	—			162,479			—

Net cash used in investing activities	(100		)	(209,541		)	(515,599		)	162,479			(562,761		)

FINANCING ACTIVITES:
Advances (to) from affiliates	15,026			(90,821		)	75,795			—			—
Contributions from parent	—			—			162,479			(162,479		)	—
Proceeds from exercise of share options	2,911			—			—			—			2,911
Excess tax benefits from share-based compensation	—			3,690			—			—			3,690
Other	1,820			—			—			—			1,820

Net cash provided by (used in) financing activities	19,757			(87,131		)	238,274			(162,479		)	8,421

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	5,664			(135,969		)	199,141			—			68,836
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	58,628			228,085			737,295			—			1,024,008

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	64,292		$	92,116		$	936,436		$	—		$	1,092,844

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Rowan Companies plc and Subsidiaries

Condensed Consolidating Statements of Cash Flows

Year ended December 31, 2012

(in thousands)



	Rowan Companies plc (Parent)		RCI (Issuer)			Non-guarantor subsidiaries			Consolidating adjustments			Consolidated
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	33,797	$	94,628		$	406,149		$	(140,865	)	$	393,709

INVESTING ACTIVITIES:
Property, plant and equipment additions	—		(94,009		)	(591,247		)	—			(685,256		)
Proceeds from disposals of property, plant and equipment	—		6,406			4,094			—			10,500
Investments in consolidated subsidiaries	—		(256,160		)	—			256,160			—

Net cash used in investing activities	—		(343,763		)	(587,153		)	256,160			(674,756		)

FINANCING ACTIVITIES:
Repayments of borrowings	—		(200,446		)	(38,007		)	—			(238,453		)
Advances (to) from affiliates	3,359		(611,666		)	608,307			—			—
Contributions from parent	—		—			256,160			(256,160		)	—
Proceeds from borrowings	—		1,104,929			—			—			1,104,929
Debt issue costs	—		(2,026		)	—			—			(2,026		)
Dividends paid	—		—			(140,865		)	140,865			—
Proceeds from exercise of share options	—		588			—			—			588
Excess tax benefits from share-based compensation	—		1,164			—			—			1,164

Net cash provided by (used in) financing activities	3,359		292,543			685,595			(115,295		)	866,202

INCREASE IN CASH AND CASH EQUIVALENTS	37,156		43,408			504,591			—			585,155
CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD	21,472		184,677			232,704			—			438,853

CASH AND CASH EQUIVALENTS, END OF PERIOD	$	58,628	$	228,085		$	737,295		$	—		$	1,024,008

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SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)

Unaudited quarterly financial data for each full quarter within the two most recent fiscal years follows (in thousands except per share amounts):



	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
2014:
Revenues	$	377,602	$	422,878	$	467,692	$	556,211
Income (loss) from continuing operations	76,557		62,321		106,184		(411,791		)
Net income (loss) from continuing operations	55,552		32,864		119,597		(326,888		)
Net income (loss)	59,595		32,844		119,597		(326,888		)

Basic earnings (loss) per share:
Continuing operations	$	0.45	$	0.26	$	0.96	$	(2.63	)
Net income (loss)	0.48		0.26		0.96		(2.63		)

Diluted earnings (loss) per share:
Continuing operations	$	0.45	$	0.26	$	0.96	$	(2.63	)
Net income (loss)	0.48		0.26		0.96		(2.63		)

2013:
Revenues	$	394,238	$	408,883	$	382,808	$	393,355
Income from continuing operations	90,414		112,267		68,509		60,486
Net income from continuing operations	68,134		82,844		51,900		49,698
Net income	68,134		82,844		51,900		49,698

Basic earnings per share:
Continuing operations	$	0.55	$	0.67	$	0.42	$	0.40
Net income	0.55		0.67		0.42		0.40

Diluted earnings per share:
Continuing operations	$	0.55	$	0.67	$	0.42	$	0.40
Net income	0.55		0.67		0.42		0.40

The sum of the per-share amounts for the quarters may not equal the per-share amounts for the full year due to differences in the computation of weighted average shares for the quarters and full year.

Income from continuing operations in the first, second, and fourth quarters of 2014 includes a $20.9 million gain on settlement of a lawsuit, an $8.3 million noncash asset impairment charge, and a $565.7 million noncash asset impairment charge, respectively.

Income from continuing operations in the second and fourth quarters of 2013 includes a $19.1 million gain on sale of the Rowan Paris and a $4.5 million noncash asset impairment charge, respectively.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None

ITEM 9A. CONTROLS AND PROCEDURES

The Company’s management has evaluated, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief Executive Officer, along with the Company’s Chief Financial Officer, concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014 .

Our management is responsible for establishing and maintaining internal control over financial reporting (ICFR). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed,

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have inherent limitations, and therefore can only provide reasonable assurance with respect to financial statement preparation and presentation.

Our management’s assessment is that the Company did maintain effective ICFR as of December 31, 2014 , within the context of the Internal Control - Integrated Framework (2013) established by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and that the Company did not have a material change in ICFR during the fourth quarter of 2014 .

See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.

ITEM 9B. OTHER INFORMATION

Not applicable

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

Information concerning our directors will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A of the Exchange Act (Regulation 14A) on or before April 30, 2015 , under the caption “Election of Directors.” Such information is incorporated herein by reference.

Information concerning our executive officers appears in Part I under the caption “Executive Officers of the Registrant” of this Form 10-K.

Information concerning our Audit Committee will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2015 , under the caption “Committees of the Board of Directors.” Such information is incorporated herein by reference.

Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2015 , under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.

ITEM 11. EXECUTIVE COMPENSATION

Information concerning director and executive compensation will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2015 , under the captions “Director Compensation and Attendance,” “Compensation Discussion & Analysis,” “Compensation Committee Report,” and “Executive Compensation.” Such information is incorporated herein by reference.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Information concerning the security ownership of management will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2015 , under the caption “Security Ownership of Certain Beneficial Owners and Management.” Such information is incorporated herein by reference.

The business address of all directors is the principal executive offices of the Company as set forth on the cover page of this Form 10-K.

Equity Compensation Plan Information

The following table provides information about our ordinary shares that may be issued under equity compensation plans as of December 31, 2014 .

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	Number of securities to be issued upon exercise of outstanding options, warrants and rights ⁽¹⁾ (a)	Weighted-average exercise price of outstanding options, warrants and rights ⁽²⁾ (b)	Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c)
Equity compensation plans approved by security holders	284,816	$21.02	5,619,212
Equity compensation plans not approved by security holders	—	—	—
Total	284,816	$21.02	5,619,212


(1)	The number of securities to be issued includes (i) 185,404 options and 99,412 shares issuable under outstanding SARs (see note (2) below).

(2)

The weighted-average exercise price in column (b) is based on (i) 185,404 shares under outstanding options with a weighted average exercise price of $22.96 per share, and (ii) 99,412 shares of stock that would be issuable in connection with 1,761,270 stock appreciation rights (SARs) outstanding at December 31, 2014 . The number of shares issuable under SARs is equal in value to the excess of the Company’s share price on the date of exercise over the exercise price. The number of shares issuable under SARs included in column (a) was based on a December 31, 2014 closing stock price of $23.32 and a weighted-average exercise price of $30.94 per share.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE

Information concerning director and executive related party transactions will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A on or before April 30, 2015 , within the section and under the captions “Director Independence” and “Related Party Transactions.” Such information is incorporated herein by reference.

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES

Information concerning principal accounting fees and services will appear in our proxy statement for the 2015 annual general meeting of shareholders, to be filed pursuant to Regulation 14A no later than April 30, 2015 , in the last paragraph under the caption “Fees of Audit Firm.” Such information is incorporated herein by reference.

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PART IV

ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a) Index to Financial Statements, Financial Statement Schedules and Exhibits

(1) Financial Statements

See Item 8, “Financial Statements and Supplementary Data,” beginning on page 40 of this Form 10-K for a list of financial statements filed as a part of this report.

(2) Financial Statement Schedules

Financial Statement Schedules I, II, III, IV, and V are not included in this Form 10-K because such schedules are not required, the required information is not significant, or the information is presented elsewhere in the financial statements.

(3) Exhibits

Unless otherwise indicated below as being incorporated by reference to another filing of the Company with the Securities and Exchange Commission, each of the following exhibits is filed herewith:



2.1			Agreement and Plan of Merger and Reorganization by and between Rowan Companies, Inc. and Rowan Mergeco, LLC dated February 27, 2012, incorporated by reference to Annex A of the Registration Statement on Form S-4 filed by Rowan Companies Limited (now Rowan Companies plc) on February 28, 2012 with the Securities and Exchange Commission (File No. 333-179749).
2.2			Amendment No. 1 to Agreement and Plan of Merger and Reorganization dated April 12, 2012, incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 12, 2012 (File No. 1-5491).
3.1			Articles of Association of the Company, incorporated by reference to Exhibit 3.1 of Rowan Companies, Inc.’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
4.1			Form of Share Certificate for the Company, incorporated by reference to Exhibit 4.5 of the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
4.2			Indenture for Senior Debt Securities dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
4.3			First Supplemental Indenture dated as of July 21, 2009, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated July 21, 2009 (File No. 1-5491).
4.4			Form of 7.875% Senior Note due 2019, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on July 21, 2009 (File No. 1-5491).
4.5			Second Supplemental Indenture dated as of August 30, 2010, between Rowan Companies, Inc. and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on August 30, 2010 (File No. 1-5491).
4.6			Form of 5% Senior Note due 2017, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on August 30, 2010 (File No. 1-5491).
4.7			Third Supplemental Indenture dated as of May 4, 2012, among Rowan Companies, Inc., the Company and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.4 to the Company's Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
4.8			Fourth Supplemental Indenture dated as of May 21, 2012, among Rowan Companies, Inc., the Company and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 21, 2012 (File No. 1-5491).
4.9			Form of 4.875% Senior Note due 2022, incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K filed on May 21, 2012 (File No. 1-5491).
4.10			Fifth Supplemental Indenture dated as of December 11, 2012, among Rowan Companies, Inc., the Company and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.3 to the Company’s Current Report on Form 8-K filed on December 11, 2012 (File No. 1-5491).
4.11			Form of 5.4% Senior Note due 2042, incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K filed on December 11, 2012 (File No. 1-5491).
4.12			Sixth Supplemental Indenture dated as of January 15, 2014, among Rowan Companies, Inc., Rowan Companies plc and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).
4.13			Form of 4.75% Senior Note due 2024, incorporated by reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).
4.14			Seventh Supplemental Indenture dated as of January 15, 2014, among Rowan Companies, Inc., Rowan Companies plc and U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).
4.15			Form of 5.85% Senior Note due 2044, incorporated by reference to Exhibit 4.3 of the Company’s Current Report on Form 8-K filed on January 15, 2014 (File No. 1-5491).
* 10.1			Restated 1988 Nonqualified Stock Option Plan, as amended, incorporated by reference to Appendix C to the Proxy Statement dated March 20, 2002 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10a to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
*10.2			1998 Nonemployee Director Stock Option Plan, incorporated by reference to Exhibit 10b of Form 10-Q for the quarterly period ended March 31, 1998 (File No. 1-5491) and Form of Stock Option Agreement related thereto, incorporated by reference to Exhibit 10b to Form 10-K for the year ended December 31, 2004 (File No. 1-5491).
10.3			Memorandum Agreement dated January 26, 2006 between Rowan Companies, Inc. and C. R. Palmer, incorporated by reference to Exhibit 10jj to Form 10-K for year ended December 31, 2005 (File No. 1-5491).
*10.4			2005 Rowan Companies, Inc. Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File No. 1-5491) and Form of Non-Employee Director 2005 Restricted Stock Unit Grant, Form of Non-Employee Director 2006 Restricted Stock Unit Grant, Form of 2005 Restricted Stock Grant Agreement, Form of 2005 Nonqualified Stock Option Agreement, Form of 2005 Performance Share Award Agreement related thereto, each incorporated by reference to Exhibits 10c, 10d, 10e, 10f and 10g, respectively, to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
*10.5			Form of Change in Control Agreement and Form of Change in Control Supplement, incorporated by reference to Exhibits 10.1 and 10.2 to Form 8-K filed December 21, 2007 (File 1-5491).
10.6			Form of Indemnification Agreement between Rowan Companies, Inc. and each of its directors and certain officers, incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K dated November 2, 2009 (File No. 1-5491).
*10.7			Restoration Plan of Rowan Companies, Inc. (As Restated Effective July 1, 2009), incorporated by reference to Exhibit 10.43 to Form 10-K for the year ended December 31, 2009 (File No. 1-5491).
10.8			Share Purchase Agreement dated July 1, 2010, among Rowan Companies, Inc., Skeie Technology AS, Skeie Tech Invest AS and Wideluck Enterprises Limited and Pre-Acceptance Letters from Skeie Holding AS and Trafalgar AS, each relating to the purchase of shares of common stock of Skeie Drilling & Production ASA, incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 19, 2010 (File No. 1-5491).
10.9			Amended and Restated Credit Agreement dated January 23, 2014 among Rowan Companies, Inc., as Borrower, Rowan Companies plc, as Parent, the Lenders named therein, Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender and Citibank, N.A., DnB Bank ASA, New York Branch, Royal Bank of Canada, Bank of America, N.A., Barclays Bank PLC and Goldman Sachs Bank USA, as Co-Syndication Agents), incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 28, 2014 (File No. 1-5491).
10.10			Amended and Restated Parent Guaranty dated as of January 23, 2014, by the Company, as Guarantor, in favor of Wells Fargo Bank, National Association, as Administrative Agent, incorporated by reference to Exhibit 10.12 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013 (File No. 1-5491).
10.11			Stock Purchase Agreement dated May 13, 2011, between Rowan Companies, Inc., as seller, and Joy Global Inc., as buyer, relating to the sale of all the outstanding equity interests in LeTourneau Technologies, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on May 18, 2011 (File No. 1-5491).
10.12			Purchase and Sale Agreement dated July 19, 2011, among Rowan Companies, Inc., as seller, and Ensign United States Drilling (S.W.) Inc., as buyer, and Ensign Energy Services Inc., as guarantor of the buyer’s performance under the agreement, relating to the sale of all the outstanding equity interests in Rowan Drilling Company LLC, a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on July 20, 2011 (File No. 1-5491).
*10.13			Amendment to the Rowan Companies, Inc. Restated 1988 Nonqualified Stock Option Plan, effective May 4, 2012, incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.14			Amendment to the Rowan Companies, Inc. 1998 Nonemployee Director Stock Option Plan, effective May 4, 2012, incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.15			Amendment to the 2005 Rowan Companies, Inc. Long-Term Incentive Plan, effective May 4, 2012, incorporated by reference to Exhibit 10.11 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.16			2009 Rowan Companies, Inc. Incentive Plan (as Amended and Restated and as Assumed and Adopted by the Company, effective May 4, 2012), incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on May 4, 2012.
*10.17			Form of Restricted Share Notice pursuant to the 2009 Rowan Companies, Inc. Incentive Plan (as Amended and Restated and as Assumed and Adopted by the Company, effective May 4, 2012), incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.18			Form of Non-Employee Director Restricted Share Unit Notice pursuant to 2009 Rowan Companies, Inc. Incentive Plan (as Amended and Restated and as Assumed and Adopted by the Company, effective May 4, 2012), incorporated by reference to Exhibit 10.8 of the Company’s Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2012 (File No. 1-5491).
*10.19			Forms of Restricted Share Unit Award Notice, Share Appreciation Right Award Notice and Performance Unit Award Notice pursuant to the 2009 Rowan Companies, Inc. Incentive Plan (as Amended and Restated and as Assumed and Adopted by the Company, effective May 4, 2012), incorporated by reference to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on March 8, 2013 (File No. 1-5491).
*10.20			Deed of Assumption dated May 4, 2012, executed by the Company, incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.21			Form of Supplement to Change in Control Agreement, incorporated by reference to Exhibit 10.12 of the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
10.22			Form of Deed of Indemnity of the Company, incorporated by reference to Exhibit 10.13 of the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491).
*10.23			Retirement Agreement with William H. Wells dated September 7, 2012, incorporated by reference to Exhibit 10.14 of the Company’s Form 10-Q for the quarter ended September 30, 2012 (File No. 1-5491).
10.24			Retirement Policy of Rowan Companies, Inc., effective March 6, 2013, incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on March 8, 2013 (File No. 1-5491).
*10.25			2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Annex A to the Company’s proxy statement filed on March 13, 2013 (File No. 1-5491).
*10.26			Form of Employee Restricted Share Unit Notice pursuant to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.2 to the Company’s Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).
*10.27			Form of Share Appreciation Right Notice pursuant to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.3 to the Company’s Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).
*10.28			Form of Performance Unit Award Notice pursuant to Annex 2 to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.4 to the Company’s Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).
*10.29			Non-Employee Director Restricted Share Unit Notice pursuant to Annex 1 to the 2013 Rowan Companies plc Incentive Plan (effective April 26, 2013), incorporated by reference to Exhibit 10.5 to the Company’s Current Report on Form 8-K filed on April 30, 2013 (File No. 1-5491).
*10.30			Summary of the Company’s Annual Incentive Plan.
*10.31			Form of Change in Control Agreement entered into with executives on or after April 25, 2014.
*10.32			Amendment to Rowan Companies Incentive Plans, effective as of April 25, 2014, incorporated by reference to Exhibit 10.3 of the Company’s Current Report on Form 8-K filed on May 1, 2014 (File No. 1-5491).
*10.33			Form of Waiver and Release Agreement, incorporated by reference to Exhibit 10.1 of the Company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2014 (File No. 1-5491).
21			Subsidiaries of the Registrant.
23			Consent of Independent Registered Public Accounting Firm.
31.1			Certification of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2			Certification of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1			Certification of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2			Certification of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101.INS			XBRL Instance Document.
101.SCH			XBRL Taxonomy Extension Schema Document.
101.CAL			XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF			XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB			XBRL Taxonomy Extension Label Linkbase Document.
101.PRE			XBRL Taxonomy Extension Presentation Linkbase Document.

__________



*	Executive compensatory plan or arrangement.

Rowan agrees to furnish to the Commission upon request a copy of all instruments defining the rights of holders of long-term debt of the Company and its subsidiaries.

Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



	ROWAN COMPANIES plc
	(Registrant)

	By: /s/ THOMAS P. BURKE
	Thomas P. Burke
	Chief Executive Officer

	Date: March 2, 2015

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.



Signature	Title	Date

/s/ THOMAS P. BURKE	Chief Executive Officer and Director	March 2, 2015
(Thomas P. Burke)

/s/ STEPHEN M. BUTZ	Principal Financial Officer	March 2, 2015
(Stephen M. Butz)

/s/ GREGORY M. HATFIELD	Principal Accounting Officer	March 2, 2015
(Gregory M. Hatfield)

WILLIAM T. FOX III	Director	March 2, 2015
(William T. Fox III)

SIR GRAHAM HEARNE	Director	March 2, 2015
(Sir Graham Hearne)

THOMAS R. HIX	Director	March 2, 2015
(Thomas R. Hix)

LORD MOYNIHAN	Director	March 2, 2015
(Lord Moynihan)

SUZANNE P. NIMOCKS	Director	March 2, 2015
(Suzanne P. Nimocks)

P. DEXTER PEACOCK	Director	March 2, 2015
(P. Dexter Peacock)

JOHN J. QUICKE	Director	March 2, 2015
(John J. Quicke)

W. MATT RALLS	Chairman of the Board	March 2, 2015
(W. Matt Ralls)

TORE I. SANDVOLD	Director	March 2, 2015
(Tore I. Sandvold)

Exhibit 10.10

AMENDED AND RESTATED PARENT GUARANTY

This Amended and Restated Parent Guaranty dated as of January 23, 2014 (as amended, supplemented, amended and restated or otherwise modified from time to time, this “ Guaranty ”) is executed by the undersigned (the “ Parent ”) in favor of Wells Fargo Bank, National Association, as Administrative Agent for the ratable benefit of the Lender Parties (as defined in the Credit Agreement referred to below).

INTRODUCTION

A. The Parent is party to that certain Parent Guaranty dated as of May 4, 2012 (as heretofore amended, restated, supplemented or otherwise modified, the “Existing Guaranty”).

B. Rowan Companies, Inc., a Delaware corporation (the “ Borrower ”), the Lender Parties party thereto from time to time, and Wells Fargo Bank, National Association, as Administrative Agent, Swingline Lender, and Issuing Lender, are parties to that certain Amended and Restated Credit Agreement dated as of January 23, 2014 (as amended, supplemented, amended and restated or otherwise modified from time to time, the “ Credit Agreement ”; the defined terms of which are used herein unless otherwise defined herein).

C. It is a requirement under the Credit Agreement that the Parent guarantee the due payment and performance of all Obligations.

D. The Parent is executing and delivering this Guaranty (a) to induce the Lenders to provide and continue to provide Advances under the Credit Agreement, (b) to induce the Issuing Lenders to provide and continue to provide Letters of Credit under the Credit Agreement, and (c) intending it to be a legal, valid, binding, enforceable and continuing obligation of the Parent.

NOW, THEREFORE, in consideration of the premises, the Parent, for the benefit of the Lender Parties, does hereby further agree as follows:

AGREEMENT

1. Guaranty. The Parent hereby absolutely and unconditionally guarantees, as a guaranty of payment and performance and not merely as a guaranty of collection, prompt payment when due, whether at stated maturity, by required prepayment, upon acceleration, demand or otherwise, and at all times thereafter, of all Obligations, whether direct or indirect, absolute or contingent, liquidated or unliquidated, voluntary or involuntary and whether for principal, interest, premiums, fees indemnities, damages, costs, expenses or otherwise, under the Credit Documents (including all renewals, extensions, amendments, refinancings and other modifications thereof and all costs, attorneys’ fees and expenses incurred by the Lender Parties in connection with the collection or enforcement thereof), and whether recovery upon such Obligations may be or hereafter become unenforceable or shall be an allowed or disallowed claim under any proceeding or case commenced by or against the Parent or any Credit Party under Debtor Relief Laws, and including interest that accrues after the commencement by or against any Credit Party of any proceeding under any Debtor Relief Laws (collectively, the “ Guaranteed Obligations ”). Any Lender Party’s books and records showing the amount of the Guaranteed Obligations shall be admissible in evidence in any action or proceeding, and shall be binding upon the Parent and conclusive for the purpose of establishing the amount of the Guaranteed Obligations. This Guaranty shall not be affected by the genuineness, validity, regularity or enforceability of the Guaranteed Obligations or any instrument or agreement evidencing any Guaranteed Obligations, or by the existence, validity, enforceability, perfection, non-perfection or extent of any collateral therefor, or by any fact or circumstance relating to the Guaranteed Obligations which might otherwise constitute a defense to the obligations of the Parent under this Guaranty, and the Parent hereby irrevocably

waives any defenses it may now have or hereafter acquire in any way relating to any or all of the foregoing. Anything contained herein to the contrary notwithstanding, the obligations of the Parent hereunder at any time shall be limited to an aggregate amount equal to the largest amount that would not render its obligations hereunder subject to avoidance as a fraudulent transfer or conveyance under Section 548 of the Bankruptcy Code (Title 11, United States Code) or any comparable provisions of any similar United States federal or state law, or applicable foreign law. Notwithstanding the foregoing, the Guaranteed Obligations shall not include any Excluded Swap Obligations.

2. No Setoff or Deductions; Taxes; Payments. The Parent shall make all payments hereunder without setoff or counterclaim and free and clear of and without deduction for any taxes, levies, imposts, duties, charges, fees, deductions, withholdings, compulsory loans, restrictions or conditions of any nature now or hereafter imposed or levied by any jurisdiction or any political subdivision thereof or taxing or other authority therein unless the Parent is compelled by law to make such deduction or withholding. If any such obligation (other than Excluded Taxes) is imposed upon the Parent with respect to any amount payable by it hereunder, the Parent will pay to such Lender Party, on the date on which such amount is due and payable hereunder, such additional amount in U.S. dollars as shall be necessary to enable such Lender Party to receive the same net amount which such Lender Party would have received on such due date had no such obligation been imposed upon the Parent. The Parent will deliver promptly to the applicable Lender Party certificates or other valid vouchers for all taxes or other charges deducted from or paid with respect to payments made by the Parent hereunder. The obligations of the Parent under this paragraph shall survive the payment in full of the Guaranteed Obligations and termination of this Guaranty.

3. Rights of Lender. The Parent consents and agrees that the Lender Parties may, at any time and from time to time, without notice or demand, and without affecting the enforceability or continuing effectiveness hereof: (a) amend, extend, renew, compromise, discharge, accelerate in accordance with the Credit Agreement or otherwise change the time for payment or the terms of the Guaranteed Obligations or any part thereof; (b) take, hold, exchange, enforce, waive, release, fail to perfect, sell, or otherwise dispose of any security for the payment of this Guaranty or any Guaranteed Obligations; (c) to the extent permitted by law, apply such security and direct the order or manner of sale thereof as the Lender in its sole discretion may determine; and (d) release or substitute one or more of any endorsers or other guarantors of any of the Guaranteed Obligations. Without limiting the generality of the foregoing, the Parent consents to the taking of, or failure to take, any action which might in any manner or to any extent vary the risks of the Parent under this Guaranty or which, but for this provision, might operate as a discharge of the Parent.

4. Certain Waivers. The Parent waives (a) any defense arising by reason of any disability or other defense of the Borrower or any other guarantor, or the cessation from any cause whatsoever (including any act or omission of the Lender) of the liability of the Borrower; (b) any defense based on any claim that the Parent’s obligations exceed or are more burdensome than those of the Borrower; (c) the benefit of any statute of limitations affecting the Parent’s liability hereunder; (d) any right to require the Lender Parties to proceed against the Borrower or any other guarantor, proceed against or exhaust any security for the Obligations, or pursue any other remedy in any Lender Party’s power whatsoever; (e) any benefit of and any right to participate in any security now or hereafter held by any Lender Party; and (f) to the fullest extent permitted by law, any and all other defenses or benefits that may be derived from or afforded by applicable law limiting the liability of or exonerating guarantors or sureties. The Parent expressly waives all setoffs and counterclaims and all presentments, demands for payment or performance, notices of nonpayment or nonperformance, protests, notices of protest, notices of dishonor and all other notices or demands of any kind or nature whatsoever with respect to the Guaranteed Obligations, and all notices of acceptance of this Guaranty or of the existence, creation or incurrence of new or additional Guaranteed Obligations.

5. Obligations Independent . The obligations of the Parent hereunder are those of primary obligor, and not merely as surety, and are independent of the Guaranteed Obligations and the obligations of any other guarantor, and a separate action may be brought against the Parent to enforce this Guaranty whether or not the Borrower or any other person or entity is joined as a party.

6. Subrogation. The Parent shall not exercise any right of subrogation, contribution, indemnity, reimbursement or similar rights with respect to any payments it makes under this Guaranty until all of the Guaranteed Obligations and any amounts payable under this Guaranty have been indefeasibly paid and performed in full and any commitments of the Lender Parties or facilities provided by the Lender Parties with respect to the Guaranteed Obligations are terminated. If any amounts are paid to the Parent in violation of the foregoing limitation, then such amounts shall be held in trust for the benefit of the Lender Parties and shall forthwith be paid to the Administrative Agent for the benefit of the Lender Parties to reduce the amount of the Guaranteed Obligations, whether matured or unmatured.

7. Termination; Reinstatement. This Guaranty is a continuing and irrevocable guaranty of all Guaranteed Obligations now or hereafter existing and shall remain in full force and effect until all Guaranteed Obligations and any other amounts payable under this Guaranty are indefeasibly paid in full in cash, all Letters of Credit have expired, terminated or been cash collateralized and the Revolving Commitments of the Lender Parties with respect to the Guaranteed Obligations are terminated. Notwithstanding the foregoing, this Guaranty shall continue in full force and effect or be revived, as the case may be, if any payment by or on behalf of the Borrower, any Credit Party or the Parent is made, or any Lender Party exercises its right of setoff, in respect of the Guaranteed Obligations and such payment or the proceeds of such setoff or any part thereof is subsequently invalidated, declared to be fraudulent or preferential, set aside or required (including pursuant to any settlement entered into by a Lender Party in its discretion) to be repaid to a trustee, receiver or any other party, in connection with any proceeding under any Debtor Relief Laws or otherwise, all as if such payment had not been made or such setoff had not occurred and whether or not any Lender Party is in possession of or has released this Guaranty and regardless of any prior revocation, rescission, termination or reduction. The obligations of the Parent under this paragraph shall survive termination of this Guaranty.

8. Subordination. The Parent hereby subordinates the payment of any obligation of any Credit Party to the Parent as subrogee of the Lender Parties or resulting from the Parent’s performance under this Guaranty, to the indefeasible payment in full in cash of all Guaranteed Obligations. If the Administrative Agent so requests, any such obligation or indebtedness of any Credit Party to the Parent shall be enforced and performance received by the Parent as trustee for the Administrative Agent for the benefit of the Lender Parties and the proceeds thereof shall be paid over to the Administrative Agent for the benefit of the Lender Parties on account of the Guaranteed Obligations, but without reducing or affecting in any manner the liability of the Parent under this Guaranty.

9. Stay of Acceleration. In the event that acceleration of the time for payment of any of the Guaranteed Obligations is stayed, in connection with any case commenced by or against the Parent or the Borrower under any Debtor Relief Laws, or otherwise, all such amounts shall nonetheless be payable by the Parent immediately upon demand by the Administrative Agent.

10. Expenses . The Parent shall pay on demand all out-of-pocket expenses (including attorneys’ fees and expenses and the allocated cost and disbursements of internal legal counsel) in any way relating to the enforcement or protection of the Administrative Agent or any Lender Party’s rights under this Guaranty or in respect of the Guaranteed Obligations, including any incurred during any “workout” or restructuring in respect of the Guaranteed Obligations and any incurred in the preservation, protection or enforcement of

any rights of the Administrative Agent or any Lender Party in any proceeding any Debtor Relief Laws. The obligations of the Parent under this paragraph shall survive the payment in full of the Guaranteed Obligations and termination of this Guaranty.

11. Miscellaneous. No provision of this Guaranty may be waived, amended, supplemented or modified, except by a written instrument executed by the Administrative Agent, the Majority Lenders and the Parent. No failure by the Administrative Agent or any Lender Party to exercise, and no delay in exercising, any right, remedy or power hereunder shall operate as a waiver thereof; nor shall any single or partial exercise of any right, remedy or power hereunder preclude any other or further exercise thereof or the exercise of any other right, power or remedy. The remedies herein provided are cumulative and not exclusive of any remedies provided by law or in equity. The unenforceability or invalidity of any provision of this Guaranty shall not affect the enforceability or validity of any other provision herein. Unless otherwise agreed by the Administrative Agent, the Majority Lenders and the Parent in writing, this Guaranty is not intended to supersede or otherwise affect any other guaranty now or hereafter given by the Parent for the benefit of the Lender Parties or any term or provision thereof.

12. Condition of the Borrower. The Parent acknowledges and agrees that it has the sole responsibility for, and has adequate means of, obtaining from the Borrower and any other guarantor such information concerning the financial condition, business and operations of the Borrower and any such other guarantor as the Parent requires, and that the Lender Parties have no duty, and the Parent is not relying on the Administrative Agent or any other Lender Party at any time, to disclose to the Parent any information relating to the business, operations or financial condition of the Borrower or any other guarantor (the guarantor waiving any duty on the part of the Administrative Agent or any Lender Party to disclose such information and any defense relating to the failure to provide the same).

13. Setoff. If and to the extent any payment is not made when due hereunder, the Administrative Agent or any other Lender Party may setoff and charge from time to time any amount so due against any or all of the Parent’s accounts or deposits with such Lender Party.

14. Representations and Warranties. The Parent represents and warrants that (a) it is duly organized and in good standing under the laws of the jurisdiction of its organization and has full capacity and right to make and perform this Guaranty, and all necessary authority has been obtained; (b) this Guaranty constitutes its legal, valid and binding obligation enforceable in accordance with its terms; (c) the making and performance of this Guaranty does not and will not violate the provisions of any applicable law, regulation or order, and does not and will not result in the breach of, or constitute a default or require any consent under, any material agreement, instrument, or document to which it is a party or by which it or any of its property may be bound or affected; and (d) all consents, approvals, licenses and authorizations of, and filings and registrations with, any governmental authority required under applicable law and regulations for the making and performance of this Guaranty have been obtained or made and are in full force and effect.

15. Indemnification and Survival. Without limitation on any other obligations of the Parent or remedies of the Administrative Agent or any other Lender Party under this Guaranty, the Parent shall, to the fullest extent permitted by law, indemnify, defend and save and hold harmless the Administrative Agent and the other Lender Parties from and against, and shall pay on demand, any and all damages, losses, liabilities and expenses (including attorneys’ fees and expenses and the allocated cost and disbursements of internal legal counsel) that may be suffered or incurred by the Administrative Agent or such Lender Party in connection with or as a result of any failure of any Guaranteed Obligations to be the legal, valid and binding obligations of the Borrower enforceable against the Borrower in accordance with their terms. The obligations of the

Parent under this paragraph shall survive the payment in full of the Guaranteed Obligations and termination of this Guaranty.

16. Governing Law; Assignment; Jurisdiction; Notices. THIS GUARANTY SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE INTERNAL LAWS OF THE STATE OF NEW YORK. This Guaranty shall (a) bind the Parent and its successors and assigns, provided that the Parent may not assign its rights or obligations under this Guaranty without the prior written consent of the Administrative Agent and the Majority Lenders or the Lenders, as required by the Credit Agreement (and any attempted assignment without such consent shall be void), and (b) inure to the benefit of the Administrative Agent, and the other Lender Parties and their respective successors and assigns and each Lender Party may, without notice to the Parent and without affecting the Parent’s obligations hereunder, assign, sell or grant participations in the Guaranteed Obligations and this Guaranty, in whole or in part, to the extent permitted by the Credit Agreement. The Parent hereby irrevocably (i) submits to the non‑exclusive jurisdiction of any United States Federal or New York state court sitting in New York City in any action or proceeding arising out of or relating to this Guaranty, and (ii) waives to the fullest extent permitted by law any defense asserting an inconvenient forum in connection therewith. Service of process by the Administrative Agent or any Lender Party in connection with such action or proceeding shall be binding on the Parent if sent to the Parent by registered or certified mail at the address for the Parent specified in the Credit Agreement and in the manner provided for notices in Section 9.7 of the Credit Agreement or Section 9.19 of the Credit Agreement.

17. WAIVER OF JURY TRIAL; FINAL AGREEMENT. TO THE EXTENT ALLOWED BY APPLICABLE LAW, THE PARENT AND EACH LENDER PARTY EACH IRREVOCABLY WAIVES TRIAL BY JURY WITH RESPECT TO ANY ACTION, CLAIM, SUIT OR PROCEEDING ON, ARISING OUT OF OR RELATING TO THIS GUARANTY OR THE GUARANTEED OBLIGATIONS. THIS GUARANTY REPRESENTS THE FINAL AGREEMENT BETWEEN THE PARTIES AND MAY NOT BE CONTRADICTED BY EVIDENCE OF PRIOR, CONTEMPORANEOUS, OR SUBSEQUENT ORAL AGREEMENTS BETWEEN THE PARTIES. THERE ARE NO UNWRITTEN ORAL AGREEMENTS BETWEEN THE PARTIES.

18. Amendment and Restatement. This Guaranty is an amendment and restatement of the Existing Guaranty and supersedes the Existing Guaranty in its entirety; provided, however, that the execution and delivery of this Guaranty shall not effect a novation of the Existing Guaranty but shall be, to the fullest extent applicable, in modification, renewal, confirmation and extension of such Existing Guaranty.

19. Keepwell . The Parent hereby absolutely, unconditionally and irrevocably undertakes to provide such funds or other support as may be needed from time to time by each other Guarantor to honor all of its obligations under its Guaranty in respect of obligations under a Hedging Arrangement with a Hedge Counterparty constituting Obligations hereunder (provided, however, that the Parent shall only be liable under this Section 19 for the maximum amount of such liability that can be hereby incurred without rendering its obligations under this Section 19, or otherwise under the Credit Documents, voidable under applicable law relating to fraudulent conveyance or fraudulent transfer, and not for any greater amount). The obligations of the Parent under this Section 19 shall remain in full force and effect until all of Obligations and any amounts payable under this Agreement have been indefeasibly paid and performed in full and the Revolving Commitments have terminated. The Parent intends that this Section 19 constitutes, and this Section 19 shall be deemed to constitute, a “keepwell, support, or other agreement” for the benefit of each other Guarantor for all purposes of Section 1a(18)(A)(v)(II) of the Commodity Exchange Act.

[Signature Page Follows]

Executed as of the day, month and year first written above.



		ROWAN COMPANIES plc
		an English public limited company

	By:	/s/ J. KEVIN BARTOL
	Name:	J. Kevin Bartol
	Title:	Executive Vice President, Chief Financial Officer and Treasurer

Exhibit 10.30

Summary of Annual Incentive Plan (AIP)

(as of February 2015)



What is the AIP?	The Compensation Committee (the “Committee”) of the Board of Directors of Rowan Companies plc (the “Company”) administers the Company’s targeted cash incentive plan (the “AIP”). The AIP is a compensation plan administered pursuant to the Company’s incentive plan and this document summarizes its material provisions.
Who is eligible?	Executive and other officers (including named executive officers (NEOs)), managers and certain key employees. Any recommendations of the Committee as to our NEOs are reviewed and approved by the Board of Directors.
What is my target bonus?	Each participant in the AIP generally has an incentive target that is denominated as a percentage of base salary depending on salary/responsibility level.
How is the payout calculated?	Once the bonus pool is funded, the Committee determines the actual bonus payout by assessing the Company’s performance against certain financial and operational metrics approved at the beginning of each year by the Committee. Such metrics may include, but are not limited to, the achievement of budgeted EBITDA, actual costs compared to budget, safety performance, newbuild capital projects, contracted non-productive time and other strategic objectives. In addition, the Committee also considers significant achievements made by the Company during the fiscal year. Under the current terms of the AIP, 75% of the target bonus value is determined by reference to these metrics, with payout ranging from 0% to 150% of target depending on achievement of the metric. The remaining 25% of the target bonus value is determined by the discretion of the Committee depending on Company performance outside of the designated metrics, and payout can range from 0% to 50% of target depending on the Committee’s view of such performance. Determinations with respect to any payouts under the AIP are usually made before March 15 of each year. The performance and other metrics for any year (including any methods for determining payout or the application of any discretion by the Committee) vary from year to year and are detailed in our annual proxy statement with respect to payments made for the prior fiscal year.
What is the highest/lowest bonus I may receive?	Payout will be between zero and 200% of your target depending on the achievement of the metrics and discretionary component.
Are there thresholds for the AIP?	The AIP requires the Company to have either more than $100 million of EBITDA or net income of $1 million, in order for any awards to be paid. If this threshold performance hurdle is met, then the bonus pool for all bonus awards is funded at the maximum bonus opportunity. This threshold performance hurdle is set for Section 162(m) and does not reflect the operational or financial metrics contained in the AIP.
Are AIP payouts subject to the Company’s incentive plan clawback provisions?	The Company’s incentive plan grants the Committee authority to make AIP payouts under the Company’s incentive plan subject to clawback provisions that permit the Company to recoup all or a portion of the amounts paid to you under the plan if the Company’s reported financial or operating results are materially and negatively restated within five years of the payment of such amounts. In addition, the Company’s incentive plan permits the Company to recoup from participants who are engaged in conduct that was fraudulent, negligent or not in good faith, and which disrupted, damaged, impaired or interfered with the business, reputation or employees of the Company or its affiliates, or which caused a subsequent adjustment or restatement of the Company’s reported financial statements, all or a portion of the amounts paid under the plan within five years of such conduct.

Exhibit 10.31

FORM OF CHANGE IN CONTROL AGREEMENT

THIS CHANGE IN CONTROL AGREEMENT (this “ Agreement ”), effective as of ________ (the “ Effective Date ”), is made by and between Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (the “ Company ”), and ________ (the “ Executive ”).

WHEREAS, the Company considers it essential to the best interests of the Company and its shareholders to foster the continued employment of key management personnel;

WHEREAS, the Board recognizes that, as is the case with many publicly held corporations, the possibility of a Change in Control (as defined below) exists and that such possibility, and the uncertainty and questions which it may raise among management, may result in the departure or distraction of management personnel to the detriment of the Company and its shareholders;

WHEREAS, the Board has determined that appropriate steps should be taken to reinforce and encourage the continued attention and dedication of key members of the Company’s management, including the Executive, to their assigned duties without the distraction of potentially disturbing circumstances arising from the possibility of a Change in Control; and

WHEREAS, the Company wishes to enter into this Agreement to protect the Executive’s reasonable expectations regarding compensation and duties if a Change in Control occurs, thereby encouraging the Executive to remain in the employ of the Company notwithstanding the possibility of a Change in Control;

NOW, THEREFORE, in consideration of the premises and the mutual covenants herein contained, the Company and the Executive hereby agree as follows:

1. Term of Agreement . The Term of this Agreement shall commence on the Effective Date hereof and shall continue in effect through December 31, 201__; provided, however, that commencing on January 1, 201__ and each January 1 thereafter (each, an “ Extension Date ”), the Term shall automatically be extended for one additional year (i.e., resulting in a two-year Term on the Extension Date) unless, not later than September 30 of the year immediately preceding the Extension Date, the Company or the Executive shall have given written notice to the other party hereto not to extend the Term; and further provided, that if a Change in Control shall have occurred during the Term, the Term shall expire no earlier than three years following the event which constitutes a Change in Control.

2. Company’s General Obligations .

2.1 In order to induce the Executive to remain in the employ of the Company or an Affiliate, as applicable, and in consideration of the Executive’s covenants set forth in Section 7 , the Company agrees, under the conditions described herein, to pay the Executive the Severance Payments and the other payments and benefits described herein. Except as provided in Section 10.1 , no Severance Payments shall be payable under this Agreement unless there shall have been a Qualifying Termination during the Term.

3. Compensation Other Than Severance Payments .

3.1 Following a Change in Control and during the Term, during any period that the Executive fails to perform the Executive’s duties with the Company or an Affiliate thereof as a result of incapacity due to physical or mental illness, the Company shall continue to pay the Executive’s Base Salary to the Executive at the rate in effect at the commencement of any such period, together with all compensation and benefits payable to the Executive under the terms of the Company’s or its Affiliates’ written plans as in effect during such period, until the Executive’s employment is terminated by the Company for Disability.

3.2 Following a Change in Control and during the Term, in the event of the Executive’s death, the Company shall pay to the Executive’s estate, the Executive’s Base Salary, together with all compensation and benefits payable to the Executive under the terms of the Company’s or its Affiliates’ written plans as in effect immediately prior to the date of death, through the date of the Executive’s death.

3.3 If the Executive’s employment is terminated following a Change in Control and during the Term by the Executive for Good Reason or by the Company for any reason other than due to the Executive’s Disability or death, then, in addition to any payments and benefits the Executive is entitled to receive under Section 5 below, if any, the Company shall pay the Executive’s Base Salary to the Executive through the Date of Termination at the rate in effect immediately prior to the Date of Termination or, if higher, the rate in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason, together with all compensation and benefits payable to the Executive through the Date of Termination under the terms of the Company’s or its Affiliates’ written plans as in effect immediately prior to the Date of Termination or, if more favorable to the

Executive, as in effect immediately prior to the first occurrence of an event or circumstance constituting Good Reason.

4. Accelerated Vesting .

Upon the occurrence of a Change in Control during the Term, all unvested awards, including, without limitation, any restricted shares, restricted share units, share appreciation rights, performance units, dividend equivalent rights, options, bonus shares or other performance awards, if any (but excluding, for the avoidance of doubt, the Executive’s short-term annual incentive bonus, if any), granted to the Executive under the Company’s incentive plans (such plans, collectively, the “ Plans ,” and any such awards, collectively, the “ Awards ”), shall become immediately fully vested and where applicable, exercisable, all restrictions and conditions thereon shall be deemed satisfied in full, and all limitations shall be deemed expired unless otherwise provided in the applicable award documents. Any vested share options or share appreciation rights held by the Executive shall be exercisable until the earlier of (i) the second anniversary of the Change in Control or (ii) the original maximum term of the share option or share appreciation right, as applicable. Notwithstanding the foregoing, the Board retains the right to cancel outstanding Awards in exchange for cash (or other consideration) with respect to all Awards granted under the Plans, pursuant to the terms and conditions of the Plans.

5. Severance Payments .

5.1 If the Executive incurs a Qualifying Termination during the Term, then the Company shall pay the Executive the amounts, and provide the Executive the benefits, set forth in this Section 5.1 (“ Severance Payments ”) in addition to any payments and benefits to which the Executive is entitled under Sections 3 and/or 4 , as applicable.

(A) In lieu of any severance payments and benefits otherwise payable to the Executive under any plan or arrangement between the Company or an Affiliate thereof and the Executive, on or before the 14th day following the Executive’s Date of Termination, the Company shall pay to the Executive a lump sum severance payment, in cash, equal to:

(I) ___ time(s) the sum of (a) the Executive’s Base Salary plus (b) the greater of (1) the Executive’s average short-term incentive bonuses awarded to the Executive in respect of the three calendar years prior to the year in which the Date of Termination

occurs or (2) the Executive’s target short-term incentive bonus under the Company’s or one of its Affiliate’s then-current annual incentive plan for the calendar year in which the Date of Termination occurs, plus

(II) an amount equal to the sum of (a) with respect to the non-discretionary portion of the Executive’s short-term incentive bonus opportunity for the calendar year of Executive’s Date of Termination under the Company’s or one of its Affiliate’s then-current annual incentive plan, the amount that would be payable assuming the applicable performance period ended as of the month-end immediately preceding the Date of Termination and based on the attainment of such measures as of such month-end, and multiplied by a fraction the numerator of which is the number of days from January 1 through the Date of Termination and the denominator on which is 365, and (b) with respect to the discretionary portion of the Executive’s short-term incentive bonus opportunity for the calendar year of Executive’s Date of Termination under the Company’s or one of its Affiliate’s then-current annual incentive plan, the amount equal to the Executive’s target short-term incentive bonus, pro-rated as set forth in clause (a) immediately above, plus

(III) a lump-sum amount equal to any forfeited account balance or accrued benefit under any tax-qualified plans maintained by the Company or its Affiliates, with the amount of any forfeited defined benefit plan benefit determined using the actuarial factors then used under such plan for conversion of a benefit to a lump sum amount, plus

(IV) any accrued but unused vacation and sick pay as of the Date of Termination.

(B) During the period ending on the earlier of the __-month anniversary of the Date of Termination or the date the Executive becomes eligible

for healthcare under a subsequent employer’s health plan (in either case, such period, the “ Medical Coverage Period ”), the Company or one of its Affiliates shall provide the Executive, and the Executive’s covered dependents as of the Date of Termination, with Medical Coverage substantially similar to that provided to the Executive and such covered dependents immediately prior to the Date of Termination, at no greater cost to the Executive than the cost to the Executive immediately prior to such date. Notwithstanding the foregoing, (i) if any plan pursuant to which such benefits are provided is not, or ceases prior to the expiration of the period of continuation coverage to be, exempt from the application of Section 409A of the Code under Treasury Regulation Section 1.409A-1(a)(5), or (ii) the Company is otherwise unable to continue to cover the Executive under its group health plans or cannot provide the benefit without violating applicable law (including without limitation, Section 2716 of the Public Health Service Act), then, in either case, an amount equal to each remaining Company subsidy shall thereafter be paid to the Executive in substantially equal monthly installments over the Medical Coverage Period (or the remaining portion thereof).

(C) The Company or one of its Affiliates shall provide the Executive with outplacement services from a service provider selected by the Committee, in accordance with Company practices applicable to similarly-situated executives, for a period of one year from the Date of Termination or, if earlier, until the first acceptance by the Executive of an offer of employment from a subsequent employer; provided , however , that the aggregate amount of the cost incurred by the Company for such outplacement services shall not exceed $25,000, which will be billed directly to the Company or one of its Affiliates.

5.2 Excise Tax .

(A) In the event that any payment or distribution in the nature of compensation (within the meaning of Code Section 280G(b)(2)) to or for the benefit of the Executive (including, without limitation, the accelerated vesting of incentive or equity awards held by the Executive), whether paid or payable or distributed or distributable pursuant to the terms of this Agreement or otherwise (collectively, the “ Payments ”) (i) constitute “parachute payments” within the meaning of Code Section 280G, and (ii) but for this Section 5.2 would be subject to the Excise Tax, then the Payments hereunder shall be either (a) provided to the Executive in full, or (b) reduced to the extent necessary so that no portion of such Payments is subject to the Excise Tax, whichever of the foregoing amounts,

after taking into account applicable federal, state, local and foreign income and employment taxes, the Excise Tax, and any other applicable taxes, results in the receipt by the Executive of the greatest amount of Payments. In the event of a reduction of Payments under Section 5.2(A)(ii)(b) above, such reduction shall be made from the cash amounts payable under Section 5.1(A)(I) , then Section 5.1(A)(II) , and finally Section 5.1(A)(III) . No reductions will be made other than those described in the preceding sentence regardless of the after-tax effect thereof.

(B) All determinations required to be made under this Section 5.2 shall be made by the Company’s accounting firm (the “ Accounting Firm ”). The Accounting Firm shall provide detailed supporting calculations both to the Company and the Executive. All fees and expenses of the Accounting Firm shall be borne solely by the Company. Absent manifest error, any determination by the Accounting Firm shall be binding upon the Company and the Executive. For purposes of making the calculations required by this Section 5.2 , the Accounting Firm may make reasonable assumptions and approximations concerning applicable taxes and may rely on reasonable, good faith interpretations concerning the application of the Code and other applicable legal authority. The Company and the Executive shall furnish to the Accounting Firm such information and documents as the Accounting Firm may reasonably request in order to make a determination under this Section 5.2 . In any event that, notwithstanding anything to the contrary herein, any reduction in benefits under this Section 5.2 shall be made in a manner consistent with the requirements of Section 409A, and, to the extent required to avoid the imposition of any tax or penalty under Section 409A, where two different cash Payments are subject to potential reduction but payable at different times, such amounts shall be reduced on a pro rata basis.

6. Legal Fees and Expenses.

The Company or one of its Affiliates shall pay to the Executive all reasonable legal fees and expenses in seeking in good faith to obtain or enforce any benefit or right provided by this Agreement. Any such payment shall be due upon delivery of the Executive’s written request for payment accompanied with such evidence of such legal fees and expenses incurred as the Company or one of its Affiliates reasonably may require. Any such payment shall be made on the last business day of the calendar month following the month in which the payment becomes due; provided, however, that any such payment shall be made not later than the close of the Executive’s taxable year following the taxable year in which the legal fee or expense is incurred by the Executive. In no event shall any reimbursement be made to the Executive for reasonable legal fees or expenses incurred pursuant to this

Section 6 after the later of (i) the fifth anniversary of the date of Executive’s death or (ii) the date that is five years after the date of Executive’s Date of Termination with the Company or an Affiliate thereof.

7. Confidential Information and Non-Solicitation .

7.1 Confidential Information . The Executive shall hold in a fiduciary capacity for the benefit of the Company and its Affiliates (including, without limitation, Rowan US) (together, the “ Company Group ”) all trade secrets and information, knowledge or data relating to the Company Group and their respective businesses treated as confidential by the Company Group, in any case, which shall have been obtained by the Executive during the Executive’s employment by the Company Group and which shall not have been or hereafter become public knowledge (other than by acts by the Executive or representatives of the Executive in violation of this Agreement) (hereinafter being collectively referred to as “ Confidential Information ”). The Executive shall not, without the prior written consent of the Company or as may otherwise be required by law or legal process, communicate or divulge any Confidential Information to anyone other than the Company and those designated by the Company. Any termination of the Executive’s employment or of this Agreement shall have no effect on the continuing operation of this Section 7.1 . The Executive agrees to return all Confidential Information, including all photocopies, extracts and summaries thereof, and any such information stored electronically on tapes, computer disks or in any other manner to the Company or an Affiliate thereof at any time upon request by the Company of an Affiliate thereof and upon the termination of his employment for any reason and upon the expiration of the Term.

7.2 Non-Solicitation . During the Restricted Period, the Executive agrees that the Executive will not, directly or indirectly, for his benefit or for the benefit of any other person, firm or entity, do any of the following: solicit the employment or services of, or hire, any person who was known to be employed by or was a known consultant to the Company Group upon the Date of Termination, or within six months prior thereto.

7.3 Additional Matters . The Executive and the Company agree and acknowledge that the Company has a substantial and legitimate interest in protecting the Confidential Information and the Company Group’s goodwill. The Executive and the Company further agree and acknowledge that the provisions of this Section 7 are reasonably necessary to protect the Company’s legitimate business interests and are designed to protect the Confidential Information and the Company Group’s goodwill. The Executive agrees that the scope of the restrictions as to time, and scope of activity in this Section 7 are reasonably necessary for the protection of the Company Group’s legitimate business interests and are not oppressive or injurious to the public interest. The Executive agrees that, in the event of a breach or threatened breach of any of the provisions of this Section 7 , the Company shall be entitled to injunctive relief against the Executive’s activities to the extent allowed by law. The Executive further agrees that any breach or threatened breach of any of the provisions of this Section 7 would cause irreparable injury to the Company for which it would have no adequate remedy at law. The Company and the Executive agree that the remedies specified in this Section 7.3 constitute the Company’s sole remedies for a breach of the provisions of this Section 7 by the Executive.

8. Termination Procedures .

8.1 Notice of Termination . After a Change in Control and during the Term, any termination of the Executive’s employment (other than by reason of death) shall be communicated by written Notice of Termination from one party hereto to the other party hereto in accordance with Section 11 hereof. For purposes of this Agreement, a “ Notice of Termination ” shall mean a notice which shall indicate the specific termination provision in this Agreement relied upon and shall set forth the Date of Termination.

8.2 Date of Termination . “ Date of Termination ,” with respect to any termination of the Executive’s employment after a Change in Control and during the Term, shall mean (i) if the Executive’s employment is terminated for Disability, 30 days after Notice of Termination is given (provided that the Executive shall not have returned to the full-time performance of the Executive’s duties during such 30 day period), (ii) if the Executive incurs a Qualifying Termination within six months prior to a Change in Control, the date on which such Change in Control

occurs, and (iii) if the Executive’s employment is terminated for any other reason, the date specified in the Notice of Termination which, in the case of a termination for Cause and, in the case of a termination by the Executive, shall not be less than 15 days nor more than 60 days, respectively, from the date such Notice of Termination is given.

9. No Mitigation .

The Company agrees that, if the Executive’s employment with the Company or an Affiliate thereof terminates during the Term, the Executive is not required to seek other employment or to attempt in any way to reduce any amounts payable to the Executive by the Company pursuant to Sections 3 , 4 and/or 5 , as applicable, hereof. Further, the amount of any payment or benefit provided for in this Agreement shall not be reduced by any compensation earned by the Executive as the result of employment by another employer or by offset against any amount claimed to be owed by the Executive to the Company, or otherwise.

10. Successors; Binding Agreement.

10.1 In addition to any obligations imposed by law upon any successor to the Company, the Company will require any successor (whether direct or indirect, by purchase, merger, consolidation or otherwise) to all or substantially all of the business and/or assets of the Company to expressly assume and agree to perform this Agreement in the same manner and to the same extent that the Company would be required to perform it if no such succession had taken place. Failure of the Company to obtain such assumption and agreement in writing prior to the effectiveness of any such succession shall be a breach of this Agreement and shall entitle the Executive to compensation from the Company in the same amount and on the same terms as the Executive would be entitled to hereunder if the Executive were to incur a Qualifying Termination during the Term, except that, for purposes of implementing the foregoing, the date on which any such succession becomes effective shall be deemed the Date of Termination.

10.2 This Agreement shall inure to the benefit of and be enforceable by the Executive’s personal or legal representatives, executors, administrators, successors, heirs, distributees, devisees and legatees. If the Executive shall die while any amount would still be payable to the Executive hereunder (other than amounts which, by their terms, terminate upon the death of the Executive) if the

Executive had continued to live, all such amounts, unless otherwise provided herein, shall be paid in accordance with the terms of this Agreement to the executors, personal representatives or administrators of the Executive’s estate.

11. Notices

For the purpose of this Agreement, notices and all other communications provided for in the Agreement shall be in writing and shall be deemed to have been duly given when delivered or mailed by United States registered mail, return receipt requested, postage prepaid, addressed, if to the Executive, to the address inserted below the Executive’s signature on the final page hereof and, if to the Company, to the address set forth below, or to such other address as either party may have furnished to the other in writing in accordance herewith, except that notice of change of address shall be effective only upon actual receipt:

To the Company:

Rowan Companies plc
2800 Post Oak Boulevard, Suite 5450
Houston, TX 77056
Attention: General Counsel

12. Miscellaneous

No provision of this Agreement may be modified, waived or discharged unless such waiver, modification or discharge is agreed to in writing and signed by the Executive and such officer as may be specifically designated by the Committee. No waiver by either party hereto at any time of any breach by the other party hereto of, or of any lack of compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. This Agreement supersedes any other agreements or representations, oral or otherwise, express or implied, with respect to the subject matter hereof which have been made by the parties. The validity, interpretation, construction and performance of this Agreement shall be governed by the laws of the State of Texas. All references to sections of the Exchange Act or the Code shall be deemed also to refer to any successor provisions to such sections. Any payments provided for hereunder shall be paid net of any applicable withholding required under federal, state or local law and any additional withholding to which the Executive has agreed. The obligations of the Company and the Executive under this Agreement which by their nature may require either partial or total performance after the expiration of the Term (including, without limitation, those under Section 5 hereof) shall survive such expiration.

13. Validity

The invalidity or unenforceability of any provision of this Agreement shall not affect the validity or enforceability of any other provision of this Agreement, which shall remain in full force and effect.

14. Counterparts

This Agreement may be executed in several counterparts, each of which shall be deemed to be an original but all of which together will constitute one and the same instrument.

15. Settlement of Disputes

All claims by the Executive for benefits under this Agreement shall be directed to and determined by the Committee and shall be in writing. Any denial by the Committee of a claim for benefits under this Agreement shall be delivered to the Executive in writing within 30 days after written notice of the claim is provided to the Company in accordance with Section 11 and shall set forth the specific reasons for the denial and the specific provisions of this Agreement relied upon. The Committee shall afford a reasonable opportunity to the Executive for a review of the decision denying a claim and shall further allow the Executive to appeal to the Committee a decision of the Committee within 60 days after notification by the Committee that the Executive’s claim has been denied.

16. Employment

This Agreement shall not be construed as creating an express or implied contract of employment and, except as otherwise agreed in writing between the Executive and the Company or an Affiliate thereof, the Executive shall not have any rights to be retained in the employ of the Company or any of its Affiliates.

17. Definitions

For purposes of this Agreement, the following terms shall have the meanings indicated below:

(A) “ Accounting Firm ” shall have the meaning set forth in Section 5.2(B) hereof.

(B) “ Affiliate ” shall have the meaning set forth in Rule 12b-2 promulgated under Section 12 of the Exchange Act.

(C) “ Base Salary ” shall mean the normal or customary annual salary as regularly paid by the Company including any portion which the Executive has deferred.

(D) “ Beneficial Owner ” shall have the meaning set forth in Rule 13d-3 under the Exchange Act.

(E) “ Board ” shall mean the Board of Directors of the Company.

(F) “ Cause ” for termination by the Company of the Executive’s employment shall mean (i) the willful and continued failure by the Executive to substantially perform the Executive’s duties with the Company ( other than any such failure resulting from the Executive’s incapacity due to physical or mental illness or any such actual or anticipated failure after the issuance of a Notice of Termination for Good Reason by the Executive pursuant to Section 8.1 hereof) after a written demand for substantial performance is delivered to the Executive by the Board, which demand specifically identifies the manner in which the Board believes that the Executive has not substantially performed the Executive’s duties, (ii) the willful engaging by the Executive in conduct which is demonstrably and materially injurious to the Company or its subsidiaries, (iii) the material breach of Company policy by the Executive, specifically including the Company’s code of conduct, or (iv) the Executive has been convicted of or pled nolo contendere to a misdemeanor involving moral turpitude or a felony.

(G) A “ Change in Control ” shall be deemed to have occurred if the event set forth in any one of the following paragraphs shall have occurred on or following the Effective Date:

(I) any “person” (as defined in Section 3(a)(9) of the Exchange Act, and as modified in Section 13(d) and 14(d) of the Exchange Act) other than (i) the Company or any of its subsidiaries, (ii) any employee benefit plan of the Company or any of its subsidiaries, (iii) any Affiliate of the foregoing, (iv) any company owned, directly or indirectly, by shareholders of the Company in substantially the same proportions as their ownership of the Company or (v) an underwriter temporarily holding securities pursuant to an offering of such securities (a “ Person ”), becomes the Beneficial Owner, directly or indirectly, of securities of the Company representing more than 50% of the voting shares of the Company then outstanding; or

(II) individuals who, as of the Effective Date, constitute the Board (the “ Incumbent Board ”) cease for any reason to constitute at least a majority of the Board; provided, however, that for purposes of this definition of Change in Control, any individual becoming a member of the Board subsequent to the Effective Date whose nomination or appointment to the Board was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an election contest with respect to the election or removal of directors or other solicitation of proxies or consents by or on behalf of a person other than the Board; or

(III) the consummation of any merger, reorganization, business combination or consolidation of the Company or one of its subsidiaries (a “ Business Combination ”) with or into any other entity, other than a merger, reorganization, business combination or consolidation which would result in (i) the holders of the voting securities of the Company outstanding immediately prior thereto holding securities which represent immediately after such merger, reorganization, business combination or consolidation more than 50% of the combined voting power of the voting securities of the Company or the surviving company or the parent of such surviving company or (ii) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such Business Combination were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such Business Combination; or

(IV) the consummation of a sale or disposition by the Company of all or substantially all of the Company’s assets, other than (i) a sale or disposition if the holders of the voting securities of

the Company outstanding immediately prior thereto hold securities immediately thereafter which represent more than 50% of the combined voting power of the voting securities of the acquirer, or parent of the acquirer, of such assets or (ii) at least a majority of the members of the board of directors of the corporation, or the similar managing body of a non-corporate entity, resulting from such sale or disposition were members of the Incumbent Board at the time of the execution of the initial agreement, or of the action of the Board, providing for such sale or disposition; or

(V) the shareholders of the Company approve a plan of complete liquidation or dissolution of the Company.

(H) “ Code ” shall mean the Internal Revenue Code of 1986, as amended from time to time.

(I) “ Committee ” shall mean the compensation committee of the Board, or such other committee designated by the Board.

(J) “ Company ” shall mean Rowan Companies plc and, except in determining under Section 17(G) hereof whether or not any Change in Control has occurred, shall include any successor to its business and/or assets which assumes and agrees to perform this Agreement by operation of law, or otherwise.

(K) “ Company Group ” shall have the meaning set forth in Section 7.1 hereof.

(L) “ Confidential Information ” shall have the meaning set forth in Section 7.1 hereof.

(M) “ Date of Termination ” shall have the meaning set forth in Section 8.2 hereof.

(N) “ Disability ” shall be deemed the reason for the termination by the Company of the Executive’s employment, if, as a result of the Executive’s incapacity due to physical or mental illness, the Executive shall have been absent from the full-time performance of the Executive’s duties with the Company for a period of six consecutive months, the Company shall have given the Executive a

Notice of Termination for Disability, and, within 30 days after such Notice of Termination is given, the Executive shall not have returned to the full-time performance of the Executive’s duties.

(O) “ Exchange Act ” shall mean the Securities Exchange Act of 1934, as amended from time to time.

(P) “ Excise Tax ” shall mean any excise tax imposed under Code Section 4999.

(Q) “ Executive ” shall mean the individual named in the first paragraph of this Agreement.

(R) “ Extension Date ” shall have the meaning set forth in Section 1 hereof.

(S) “ Good Reason ” for termination by the Executive of the Executive’s employment shall mean the occurrence (without the Executive’s express written consent) of any one of the following acts by the Company, or failures by the Company to act, unless, in the case of any act or failure to act described in paragraph (I) below, such act or failure to act is corrected prior to the end of the Company’s cure period specified below:

(I) the assignment to the Executive of any duties materially inconsistent with the Executive’s status as a senior executive officer of the Company or a material adverse alteration in the nature or status of the Executive’s responsibilities from those in effect immediately prior to the Change in Control;

(II) a material reduction by the Company in the Executive’s annual compensation, inclusive of bonuses and equity awards, as in effect on the date hereof or as the same may be increased from time to time, except for across-the-board reductions similarly affecting all senior executives of the Company and all senior executives of any Person in control of the Company; or

(III) the relocation of the Executive’s principal place of employment to a location more than 50 miles from the Executive’s

principal place of employment immediately prior to the Change in Control.

The Executive’s right to terminate the Executive’s employment for Good Reason shall not be affected by the Executive’s incapacity due to physical or mental illness. No act or omission shall constitute “Good Reason” for purposes of this Agreement unless the Executive provides to the Company (i) a written notice clearly and fully describing the particular acts or omissions which the Executive reasonably believes in good faith constitute “Good Reason” within 90 days of the first date of such acts or omissions, and (ii) an opportunity for the Company, within 30 days following its receipt of such notice, to cure such acts or omissions. The Executive’s continued employment shall not constitute consent to, or a waiver of rights with respect to, any act or failure to act constituting Good Reason hereunder.

(T) “ Medical Coverage ” shall mean medical and dental benefits, including the executive medical reimbursement program benefits and reimbursements for annual physical examinations for the Executive and his dependents.

(U) “ Notice of Termination ” shall have the meaning set forth in Section 8.1 hereof.

(V) “ Payments ” shall have the meaning set forth in Section 5.2 hereof.

(W) “ Person ” shall have the meaning given in Section 3(a)(9) of the Exchange Act, as modified and used in Sections 13(d) and 14(d) thereof, except that such term shall not include (i) the Company or any of its subsidiaries, (ii) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (iii) an underwriter temporarily holding securities pursuant to an offering of such securities, or (iv) a corporation owned, directly or indirectly, by the shareholders of the Company in substantially the same proportions as their ownership of shares of the Company.

(X) “ Plans ” shall have the meaning set forth on Section 4 hereof.

(Y) “ Qualifying Termination ” shall mean a termination of the Executive’s employment during the Term (i) by the Company without Cause or by the Executive for Good Reason, in either case, at any time following a Change in Control, (ii) by the Company without Cause within six months prior to a Change

in Control if such termination was at the request, direction or suggestion, directly or indirectly, of a Person who has entered into an agreement or with whom the Company contemplates will enter into an agreement with the Company the consummation of which would constitute a Change in Control or (iii) by the Executive for Good Reason within six months prior to a Change in Control and the circumstance or event which constitutes Good Reason occurs at the request, direction or suggestion, directly or indirectly, of such Person described in clause (ii) hereof.

(Z) “ Restricted Period ” shall mean one year.

(AA) “ Rowan US ” shall mean Rowan Companies, Inc., a Delaware corporation.

(BB) “ Section 409A ” shall mean Code Section 409A and the rules and regulations issued thereunder by the Department of Treasury and the Internal Revenue Service.

(CC) “ Severance Payments ” shall have the meaning set forth in Section 5.1 hereof.

(DD) “ Term ” shall mean the period of time described in Section 1 hereof (including any extension, continuation or termination described therein).

18. Time of Reimbursements

All reimbursements pursuant to this Agreement shall be made in accordance with Treasury Regulation §1.409A-3(i)(1)(iv) such that the reimbursements will be deemed payable at a specified time or on a fixed schedule relative to a permissible payment event. Specifically, the amounts reimbursed under Section 5 during the Executive’s taxable year may not affect the amounts reimbursed in any other taxable year (except that total reimbursements may be limited by a lifetime maximum under a group health plan), the reimbursement of an eligible expense shall be made on or before the last day of the Executive’s taxable year following the taxable year in which the expense was incurred, and the right to reimbursement is not subject to liquidation or exchange for another benefit.

19. Section 409A Compliance

The amounts payable under this Agreement are intended to comply with or be exempt from Section 409A and the provisions of this Agreement will be construed accordingly. If a provision of

the Agreement would result in the imposition of an applicable tax under Section 409A, such provision shall be reformed to avoid imposition of the applicable tax if permissible and no such action taken to comply with Section 409A shall be deemed to adversely affect the rights or benefits of the Executive hereunder.

If the Executive is deemed to be a “Specified Employee” as of the date of his “Separation from Service” (each as defined in Section 409A) as determined by the Company, the payment of any amount under this Agreement on account of Separation from Service that is deferred compensation subject to Section 409A and not otherwise exempt from Section 409A, shall not be paid before the earliest of (i) the first business day that is at least six months after the date of the Executive’s Separation from Service, (ii) the date of the Executive’s death, or (iii) the date that otherwise complies with the requirements of Section 409A. This provision shall be applied by accumulating all payments that otherwise would have been paid within six months of the Executive’s Separation from Service and paying such accumulated amounts, without interest, at the earliest date as described in the preceding sentence and any remaining payments due under this Agreement shall be paid or provided in accordance with the normal payment dates specified herein.

All payments to be made upon a termination of employment under this Agreement may only be made upon a “separation from service” under Section 409A. For purposes of Section 409A, each payment under this Agreement is treated as a separate payment for purposes of applying Section 409A. In no event may the Executive, directly or indirectly, designate the calendar year of payment.

[ Signature Page Follows ]

IN WITNESS WHEREOF, the parties hereto have executed this Agreement effective as of the date above first written.

ROWAN COMPANIES PLC

By:

[Name]

[Title]

EXECUTIVE :

By:_________________________________

[Name]

c/o Rowan Companies

2800 Post Oak Blvd., Suite 5450

Houston, Texas 77056

Exhibit 21

ROWAN COMPANIES PLC

LIST OF SUBSIDIARIES

As of December 31, 2014



Company Name	Jurisdiction(s)
Atlantic Maritime Services LLC (fka Atlantic Maritime Services, Inc.)	USA (Delaware)
British American Offshore Limited	UK (England & Wales)
Caydrill Limited	Cayman Islands
Great White Shark Limited	Gibraltar
Green Turtle Limited	Gibraltar
Lionfish Luxembourg S.a.r.l.	Luxembourg
Manatee Limited	Malta
Manta Ray Limited	Malta
Marine Blue Limited	Gibraltar
Ralph Coffman Cayman Limited (fka Rowan S116E#3, Inc.)	Cayman Islands
Ralph Coffman Limited	Gibraltar
Ralph Coffman Luxembourg S.à r.l. (fka Rowan Financement S.à r.l.)	Luxembourg
RCI Drilling International, Inc.	Cayman Islands
RCI International, Inc.	Cayman Islands
RD International Services Pte Ltd.	Singapore
RDC Arabia Drilling, Inc.	Cayman Islands
RDC Drilling, Ltd.	Bermuda
RDC Holdings Luxembourg S.à r.l.	Luxembourg
RDC Malta Limited (fka RDC (Gibraltar) Limited	Gibraltar
RDC Marine, Inc.	USA (Texas)
RDC Offshore Luxembourg S.à r.l.	Luxembourg
RDC Offshore Malta Limited (fka RDC Offshore (Gibraltar) Limited)	Gibraltar
RDC Qatar, Inc.	USA (Delaware)
Renaissance Cayman Limited (fka Rowan Cayman Holding Limited)	Cayman Islands
Resolute Cayman Limited	Cayman Islands
Rowan 240C#3, Inc.	Cayman Islands
Rowan Angola Limitada	Angola
Rowan Austria GmbH	Austria
Rowan California S.à r.l.	Luxembourg
Rowan Cayman Limited	Cayman Islands
Rowan Companies, Inc.	USA (Delaware)
Rowan Deepwater Drilling (Gibraltar) Limited	Gibraltar
Rowan do Brasil Servicos de Perfuracao Ltda.	Brazil
Rowan Drilling & Aviation (Netherlands) B.V.	The Netherlands
Rowan Drilling Americas Limited	UK (England and Wales)
Rowan Drilling Company, Inc.	USA (Texas)
Rowan Drilling Cyprus Limited	Cyprus
Rowan Drilling (Gibraltar) Limited	Gibraltar
Rowan Drilling Mexico, S. de R.L. de C.V.	Mexico
Rowan Drilling (Trinidad) Limited	Cayman Islands
Rowan Drilling Services Limited (fka Rowan Labor (Gibraltar) Limited)	Gibraltar

Exhibit 21



Company Name	Jurisdiction(s)
Rowan Drilling (U.K.) Limited	UK (Scotland)
Rowan Drilling US Limited	UK (England & Wales)
Rowan Egypt Petroleum Services LLC	Egypt
Rowan Finance LLC	USA (Delaware)
Rowan Finanz S.à r.l.	Luxembourg
Rowan Finanzeieren S.à r.l.	Luxembourg
Rowan Global Drilling Services Limited	Gibraltar
Rowan Gorilla V (Gibraltar) Limited	Gibraltar
Rowan Gorilla VII (Gibraltar) Limited	Gibraltar
Rowan Holdings Luxembourg S.à r.l.	Luxembourg
Rowan Marine Services, Inc.	USA (Texas)
Rowan Middle East, Inc.	Cayman Islands
Rowan N-Class (Gibraltar) Limited	Gibraltar
Rowan No. 1 Limited	England & Wales
Rowan No. 2 Limited	England & Wales
Rowan North Sea, Inc.	Cayman Islands
Rowan Norway, Inc.	USA (Delaware)
Rowan Norway Limited (fka Rowan (Gibraltar) Limited)	Gibraltar
Rowan Offshore (Gibraltar) Limited	Gibraltar
Rowan Offshore Luxembourg S.à r.l.	Luxembourg
Rowan Petroleum, Inc.	USA (Texas)
Rowan Relentless Limited	Gibraltar
Rowan Reliance Cayman Limited	Cayman Islands
Rowan Reliance Limited	Gibraltar
Rowan Reliance Luxembourg S.a.r.l.	Luxembourg
Rowan Resolute Limited	Gibraltar
Rowan Renaissance Luxembourg S.à r.l.	Luxembourg
Rowan Resolute Luxembourg S.a.r.l.	Luxembourg
Rowan, S. de R.L. de C.V.	Mexico
Rowan Services LLC	USA (Delaware)
Rowan S116E#4, Inc.	Cayman Islands
Rowan U.K. Services Limited	Cayman Islands
Rowan (UK) Relentless Limited	England & Wales
Rowan (UK) Reliance Limited	England & Wales
Rowan (UK) Renaissance Limited	England & Wales
Rowan UK Renaissance Onshore Limited	England & Wales
Rowan (UK) Resolute Limited	England & Wales
Rowan US Holdings (Gibraltar) Limited	Gibraltar
Rowandrill, Inc.	USA (Texas)
Rowandrill Labuan Limited	Labuan
Rowandrill Malaysia Sdn. Bhd.	Malaysia
Rowandrill, S. de R.L. de C.V.	Mexico
SKDP 1 Limited	Cyprus
SKDP 2 Limited	Cyprus
SKDP 3 Limited	Cyprus

EXHIBIT 23

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference in Registration Statement No. 33-33755, Registration Statement No. 33-61444, Registration Statement No. 333-84369, Registration Statement No. 333-84405, Registration Statement No. 333-101914, Registration Statement No. 333-132762, Registration Statement No. 333-158985, Registration Statement No. 333-188272, and Registration Statement No. 333-181455, each on Form S-8, and Registration Statement No. 333-160579 on Form S-3, of our reports dated March 2, 2015, relating to the consolidated financial statements of Rowan Companies plc and subsidiaries (the “Company”), and the effectiveness of the Company’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of the Rowan Companies plc for the year ended December 31, 2014.

/s/ Deloitte & Touche LLP

Houston, Texas
March 2, 2015

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Thomas P. Burke, certify that:


1.	I have reviewed this Form 10-K of Rowan Companies plc;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	March 2, 2015	/s/ THOMAS P. BURKE
		Thomas P. Burke
		Chief Executive Officer

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO SECTION 302 OF

THE SARBANES-OXLEY ACT OF 2002

I, Stephen M. Butz, certify that:


1.	I have reviewed this Form 10-K of Rowan Companies plc;


2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;


3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;


4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:


a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;


b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;


c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and


d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.


5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):


a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and


b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.



Date:	March 2, 2015	/s/ STEPHEN M. BUTZ
		Stephen M. Butz
		Executive Vice President, Chief Financial Officer and Treasurer

Exhibit 32.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U. S. C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Rowan Companies plc (the “Company”) on Form 10-K for the year ended December 31, 2014 , as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Thomas P. Burke, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company for the periods presented.



Date:	March 2, 2015	/s/ THOMAS P. BURKE
		Thomas P. Burke
		Chief Executive Officer

Exhibit 32.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U. S. C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of Rowan Companies plc (the “Company”) on Form 10-K for the year ended December 31, 2014 , as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Stephen M. Butz, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:


(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and


(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company for the periods presented.



Date:	March 2, 2015	/s/ STEPHEN M. BUTZ
		Stephen M. Butz
		Executive Vice President, Chief Financial Officer and Treasurer