10-K 1 rdc-12312014x10k.htm 10-K RDC-12.31.2014-10K
 
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

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




 
Page 
 
 
 
 
 
 
 
 
 
 




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 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents.  The Bob Palmer, 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

17


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

18


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.


19


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.

20


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.

21



 
 
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.
 

22


 
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



23


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 programs2
 
Approximate dollar value of shares that may yet be purchased under the plans or programs2
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.


24


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.

25


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.
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 in the fourth quarter of 2014 in the amount of $565.7 million.
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.


26


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.


27


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.


28


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.


29


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.

30



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):

31


 
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):

32


 
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

33


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
%


34


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.


35


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.

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.

36


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


37


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

38


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.


39


ITEM 8.  FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 

40


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

41


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


42


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


43


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

 
$