10-K 1 rdc-12312017x10k.htm 10-K Document

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

FORM 10-K

þ
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2017
 
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

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

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

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

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

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

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

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

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

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

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

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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 $1.3 billion as of June 30, 2017, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange of $10.24 per share.

The number of Class A ordinary shares, $0.125 par value, outstanding at February 21, 2018, was 126,267,762, which excludes 1,848,973 shares held by an affiliated employee benefit trust.

DOCUMENTS INCORPORATED BY REFERENCE

Document
Part of Form 10-K
Portions of the Proxy Statement for the 2018 Annual General Meeting of Shareholders
Part III, Items 10-14




 
Page 
 
 
 
 
 
 
 
 
 
 




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

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our ability to retain highly skilled personnel on commercially reasonable terms, whether due to competition, cost cutting initiatives, labor regulations, unionization or otherwise; our ability to seek and receive visas for our personnel to work in our areas of operation in a timely manner;
governmental action and political and economic uncertainties, including uncertainty or instability resulting from civil unrest, military or political demonstrations, acts of war, strikes, terrorism, piracy or outbreak or escalation of hostilities or other crises in areas in which we operate, which may result in expropriation, nationalization, confiscation, damage or deprivation of assets, extended business interruptions, suspended operations, or suspension and/or termination of contracts and payment disputes based on force majeure events;
cyber-breaches of our corporate or offshore control networks;
epidemics or other related travel restrictions which may result in business interruptions or shortages of available labor;
the outcome of legal proceedings, or other claims or contract disputes, including inability to collect receivables or resolve significant contractual or day rate disputes, any renegotiation, nullification, cancellation or breach of contracts with customers or other parties;
potential for additional asset impairments;
our liquidity, adequacy of cash flows to meet obligations, or our ability to access or obtain financing and other sources of capital, such as in the debt or equity capital markets;
volatility in currency exchange rates and limitations on our ability to use or convert illiquid currencies;
effects of accounting changes and adoption of accounting policies;
potential unplanned expenditures and funding requirements, including investments in pension plans and other benefit plans;
economic volatility and political, legal and tax uncertainties following the Brexit vote in the U.K. and any subsequent referendum in Scotland to seek independence from the U.K.;
other important factors described from time to time in the reports filed by us with the SEC and the NYSE.
Should one or more of these risks or uncertainties materialize or should our underlying assumptions prove incorrect, actual results may vary materially from those indicated.
All forward-looking statements contained in this Annual Report on Form 10-K speak only as of the date of this report 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 Annual Report on Form 10-K, or to reflect the occurrence of unanticipated events, except as required by applicable law.
Other relevant factors are included in Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K.

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GLOSSARY OF TERMS
The following frequently used abbreviations or acronyms are used in this Annual Report on Form 10-K as defined below:
Abbreviation/Acronym
 
Definition
2017 Notes
 
The Company's 5% Senior Notes due 2017
2019 Notes
 
The Company's 7.875% Senior Notes due 2019
2022 Notes
 
The Company's 4.875% Senior Notes due 2022
2024 Notes
 
The Company's 4.75% Senior Notes due 2024
2025 Notes
 
The Company's 7.375% Senior Notes due 2025
2042 Notes
 
The Company's 5.4% Senior Notes due 2042
2044 Notes
 
The Company's 5.85% Senior Notes due 2044
ARO
 
Saudi Aramco Rowan Offshore Drilling Company
ASC
 
Accounting Standards Codification
ASU
 
Accounting Standards Update
Board
 
Board of directors of the Company
 
 
 
BSEE
 
U.S. Bureau of Safety and Environmental Enforcement
Cobalt
 
Cobalt International Energy, L.P.
Company Compensation Committee
 
Compensation committee of the board of directors of the Company
Directors RSUs
 
Directors Deferred Restricted Share Units
Directors ND RSUs
 
Directors Non-Deferred Restricted Share Units
E.U.
 
European Union
EBT
 
Employee benefit trust of the Company
Exchange Act
 
Securities Exchange Act of 1934
FASB
 
Financial Accounting Standards Board
FCPA
 
U.S. Foreign Corrupt Practices Act
FCX
 
Freeport-McMoRan Inc.
FMOG
 
Freeport-McMoRan Oil and Gas LLC
HPHT
 
High-pressure/high-temperature
IMO
 
International Maritime Organization
IRS
 
U.S. Internal Revenue Service
MARPOL 73/78
 
International Convention for the Prevention of Pollution from Ships, 1973 as modified by the Protocol of 1978
NOLs
 
Net Operating Loss Carryforwards
NYSE
 
The New York Stock Exchange
OPEC
 
Organization of Petroleum Exporting Countries
P-Units
 
Performance Units
Plan
 
Amended and Restated 2013 Rowan Companies plc Incentive Plan, dated May 25, 2017
 
 
 
RCI
 
Rowan Companies Inc., a subsidiary of the Company
Retiree Medical Plan
 
Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc.
Revolving Credit Facility
 
The Company's revolving credit facility, which matures in January 2021
Rowan plc
 
Rowan Companies plc
Rowan SERP
 
Restoration Plan of Rowan Companies, Inc.
RSAs
 
Restricted Share Awards
RSUs
 
Restricted Share Units

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Abbreviation/Acronym
 
Definition
SARs
 
Share Appreciation Rights
Saudi Aramco
 
Saudi Arabian Oil Company
SEC
 
The United States Securities and Exchange Commission
SEMS
 
Safety and environmental management system
Senior Notes
 
The 2019 Notes, 2022 Notes, 2024 Notes, 2025 Notes, 2042 Notes and 2044 Notes, collectively
Subject Notes
 
The 2017 Notes, 2019 Notes, 2022 Notes and the 2024 Notes, collectively
TSR
 
Total Shareholder Return
U.K.
 
United Kingdom
U.S.
 
United States
U.S. Tax Act
 
2017 Tax Cuts and Jobs Act
UK Bribery Act
 
U.K. Bribery Act 2010
US GAAP
 
Accounting principles generally accepted in the United States of America
US GOM
 
United States Gulf of Mexico
USD
 
U.S. Dollar
WTI
 
West Texas Intermediate


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PART I
ITEM 1.  BUSINESS
Overview
Rowan Companies plc is a public limited company incorporated under the laws of England and Wales and listed on the NYSE. The terms “Rowan,” “Rowan plc,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc and its consolidated subsidiaries, unless the context otherwise requires. Intercompany balances and transactions have been eliminated in consolidation.
We are a global provider of offshore contract drilling services to the oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, we now operate in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the various arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 13, 2018, the date of our most recent Fleet Status Report, one of our four drillships was under contract in the US GOM. We had three jack-up rigs under contract in the North Sea, seven under contract in the Middle East, three under contract in Trinidad and one under contract in the US GOM. Additionally, we had five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
For information with respect to our revenue, operating income and assets by operating segment, and revenue and long-lived assets by geographic area, see Note 13 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. For additional information see "ARO Joint Venture" in Note 1 and Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. The information discussed therein is incorporated by reference into this Part I, Item 1.
Drilling Fleet
We believe our high-specification and premium jack-up fleet and ultra-deepwater drillships are well positioned to serve the worldwide market, including requirements for HPHT wells in harsh and benign locations. As of February 13, 2018, our drilling fleet consists of the following:
Four ultra-deepwater drillships;
Seventeen high-specification jack-up rigs; and
Six premium jack-up rigs. 
We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds and the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments.
Ultra-Deepwater Drillships Our ultra-deepwater drillships are self-propelled vessels equipped with computer-controlled dynamic-positioning systems, which allow them to maintain position without anchors using their onboard propulsion and station-keeping systems. Drillships have greater variable loading capacity than semisubmersible rigs, enabling them to carry more supplies on board and, thus, making them better suited for drilling in deep water in remote locations. Our drillships are equipped with two drilling stations within a single derrick, allowing the drillships to perform preparatory activities off-line and potentially simultaneous

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drilling tasks during certain stages of drilling, subject to legal restrictions in various jurisdictions, enabling increased drilling efficiency particularly during the initial stages of a well. In addition, our drillships are equipped to drill in 12,000-foot water depths, are equipped with 2,500,000-pound hook-load capability and are capable of drilling HPHT wells to 40,000-foot depths. Each is equipped with two fully redundant blowout preventers, which are designed to prevent environmental and safety issues as well as significantly reduce non-productive time associated with repair and maintenance. In addition, each drillship is equipped with an active-heave compensating crane for deployment of subsea equipment simultaneous to drilling station operations. The sum total of these and other advanced features make the drillships very attractive to our customers.
Jack-up Rigs Our jack-ups are capable of drilling wells to maximum depths ranging from 25,000 to 40,000 feet and in maximum water depths ranging from 300 to 550 feet, depending on rig size, location and outfitting. All of our high-specification rigs are equipped with or can readily accommodate the high-pressure circulation and pressure control equipment that is necessary for HPHT operations. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean floor, and the hull raises itself out of the water up to the elevation required to drill the well using a self-contained rack and pinion system.
Our three N-Class rigs are capable of drilling in water depths to 435 feet in harsh environments such as the North Sea depending on location and outfitting. The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously.
Three of our four Super Gorilla class rigs can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water in harsh environments such as the North Sea. The Bob Palmer, our fourth Super Gorilla class rig, is an enhanced version of the Super Gorilla class jack-up designated as Super Gorilla XL. The Bob Palmer can operate in water depths up to 550 feet in normally benign environments like the US GOM and the Middle East or in water depths up to 400 feet in harsh environments such as the North Sea.
Our three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet in benign environments, depending on rig size, location and outfitting, and are equipped with a hook-load capacity of 2.5 million pounds. The rigs are also capable of operating in harsh environments at reduced water depths compared to their benign environment ratings.
Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet and are equipped with a hook-load capacity of two million pounds.
We recently purchased two Super 116E class rigs. These are premium rigs capable of drilling in water depths up to 350 feet and are equipped with a hook-load capacity of 1.5 million pounds.
Our two remaining Tarzan Class rigs are specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our four remaining 116C class rigs are premium rigs capable of operating in water depths up to 300 feet in benign environments. Rowan has three of these rigs under contract directly with Saudi Aramco that are managed by ARO. The fourth rig is cold-stacked.
Our one remaining Gorilla class rig, the Rowan Gorilla IV, was designed as a heavier-duty class of jack-up rig capable of operating in water depths to 450 feet in benign environments.
In November 2017, we sold one of our older rigs in our jack-up fleet, the Cecil Provine, under an agreement that prohibits its future use as a drilling unit. In October 2017, we also sold one premium and two high-specification jack-ups to ARO. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
See Part I, Item 2, “Properties,” of this Annual Report on Form 10-K for additional information regarding our fleet.
Our operations are subject to many uncertainties and hazards. See Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K for additional information.
Contracts
Our drilling contracts generally provide for a fixed amount of compensation per day (day rate), and are either “well-to-well,” “multiple-well” or "fixed-term" generally ranging from one month to several years. Well-to-well contracts are typically cancellable by either party upon completion of drilling.  Fixed-term contracts usually contain a termination provision such that either party may terminate if drilling operations are suspended for extended periods as a result of events of force majeure.  While many fixed-term contracts are for relatively short periods of three months or less, others are for one or more years, and all can continue for periods longer than the original terms. Well-to-well contracts can be extended over multiple series of wells.  Many drilling contracts

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contain renewal or extension provisions exercisable at the option of the customer at mutually agreeable rates.  Some of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization. We recognize certain lump-sum fees and related expenses over the primary contract term. We recognize reimbursement of certain costs as revenue and expenses at the time they are incurred.  Our contracts for work generally provide for payment in USD except for amounts required by applicable law to be paid in the local currency or amounts required to meet local expenses.
A number of factors affect our ability to obtain contracts at profitable rates within a given region.  Such factors, which are discussed further under “Competition” in this Part I, Item 1 of this Annual Report on Form 10-K and in “Risk Factors” included in Part I, Item 1A of this Annual Report on Form 10-K include the global economic climate, the price of oil and gas which can affect our customers' drilling budgets, over- or under-supply of drilling units, location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, competence of drilling personnel and other competitive factors.  Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations.
During periods of weak demand and declining day rates, we have historically entered into contracts at lower rates in order to keep our rigs working. At times, however, market conditions have forced us to "warm-stack" rigs to reduce costs during extended periods between contracts.  We currently have three ultra-deepwater drillships and five jack-ups warm stacked. We have also cold-stacked certain of our idle older rigs to reduce cost further and have ultimately sold six such rigs over the last three years, the Rowan Juneau, Rowan Alaska, Rowan Louisiana, Rowan Gorilla II, Rowan Gorilla III and Cecil Provine. All were sold under agreements that prohibit or limit their future use as drilling units.
Our contract backlog was estimated to be approximately $456.2 million at February 13, 2018, down from approximately $1.7 billion at February 14, 2017.  Our backlog excludes any backlog associated with ARO Drilling. See "Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" in Part II, Item 7 of this Annual Report on 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, local content requirements and reputation.
In the jack-up drilling market, we compete with numerous offshore drilling contractors that together have 463 marketed jack-up rigs worldwide as of February 13, 2018, with an additional 91 units that are under construction or on order.  (We define marketed rigs as all rigs that are not cold-stacked.) We estimate that 73 delivered and marketed jack-ups, or 16 percent of the world’s marketed jack-up fleet, are high-specification, including Rowan's 16 high-specification rigs.
At February 13, 2018, there were 201 marketed floaters (drillships and semi-submersibles) worldwide, with an additional 42 units that are under construction or on order. We estimate that 103 of these floaters, or approximately 51 percent of the world’s marketed fleet, are capable of drilling in water depths of 10,000 feet or more, but only an estimated 35 floaters, or approximately 17 percent of the world's marketed fleet, have 2,500,000 pound hook-load capability and are equipped with dual blow-out preventers, which are key specifications valued by many deepwater customers.
A significant contributing factor to the softness in the offshore drilling market has been the influx of 247 newbuild jack-ups and 163 newbuild floaters delivered since early 2006. The addition of newbuild units, combined with numerous rigs having rolled off contracts in past months, has continued to increase competition, putting additional downward pressure on day rates and utilization. Of the approximately 91 jack-up rigs under construction worldwide scheduled for delivery through 2020 (28% of the currently utilized jack-up fleet of approximately 328 rigs), approximately 28 are considered high-specification (38% of the delivered high-specification fleet). Currently, there are approximately 58 competitive newbuild jack-up rigs scheduled for delivery during 2018, and none of them have contracts in place. For the floater market there are approximately 42 floaters under construction worldwide for delivery through 2021 (28% of the currently utilized floater fleet of approximately 150 rigs). Following the negotiated delivery delays on several units into future years, there are approximately 21 competitive newbuild floaters scheduled for delivery during 2018, with only 6 having contracts.
Based on the number of rigs as tabulated by IHS-Petrodata, we are the eighth largest offshore drilling contractor in the world and the fifth largest jack-up rig contractor. Based on market capitalization, we are the fourth largest publicly traded pure play offshore driller. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete.  In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.
We market our drilling services to present and potential customers, including large international energy companies, smaller independent energy companies and government-owned or government-controlled energy companies.  See “Management’s

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Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of this Annual Report on Form 10-K for a discussion of current and anticipated industry conditions and their impact on our operations.
Governmental Regulation
Many aspects of our operations are subject to governmental regulation, including those relating to environmental protection and pollution control. In addition, governmental regulations concerning licensing and permitting, equipment specifications, training requirements or other matters could increase the costs of our operations and could reduce exploration activity in the areas in which we operate.
We could become liable for damages resulting from pollution which could materially affect our financial position, results of operations and liquidity. In many of our drilling contracts, we are indemnified for pollution, well damage and environmental damage, except in certain cases of pollution emanating from our drilling rigs. This indemnity includes costs associated with regaining control of a wild well, removal and disposal of pollutants, environmental remediation and claims by third parties for damages. However, such contractual indemnification provisions may not adequately protect us for several reasons such as (i) the contractual indemnity provisions may require us to assume certain types or amounts of the liability; (ii) our customers may not have the financial resources necessary to honor the contractual indemnity provisions; or (iii) the contractual indemnity provisions may be unenforceable under applicable law.
Our customers often require us to assume responsibility for pollution damages when we are at fault. We seek to limit our liability to certain types of exposures such as claims by third parties. We may also seek to limit our liability to a non-material monetary amount or an amount within the limits of our available insurance coverage. For example, a contract may provide that we will assume the first $50 million of costs related to an incident resulting in wellbore pollution due to our negligence, with the customer assuming responsibility for costs in excess of that amount. We can provide no assurance that we will be able to negotiate indemnities and/or limitation of liability provisions or that such indemnification and/or limitation of liability provisions can be enforced or will be sufficient. Our customers may challenge the validity or enforceability of the indemnity provision for several reasons, including but not limited to applicable law, judicial decisions, the language of the indemnity provision, reasons of public policy, degree of fault and/or the circumstances resulting in the pollution.
In the event of an incident resulting in wellbore pollution where we are liable for all or a portion of such event, the impact on our financial position, results of 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, if available, and redress from all parties at fault. In addition, we maintain limited insurance for liability related to negative environmental impacts of a sudden and accidental pollution event, as described below. Such an event would adversely affect our results of operations, financial position and cash flows if both insurance and indemnity protection were unavailable or insufficient and the incident was significant.
The jurisdictions in which we operate have various regulations and requirements with which we must comply. For example, pursuant to the U.S. Clean Water Act, a National Pollutant Discharge Elimination ("NPDES") permit is required for discharges into the US GOM. The permit holder is the designated responsible party for any environmental impacts that occur in the event of the discharge of any unpermitted substance, including a fuel spill or oil leak from an offshore installation such as a mobile drilling unit or in the event of non-compliance with permit requirements. We operate in accordance with NPDES permit standards regardless of the holder.
Pursuant to the U.K. Offshore Directive, we are required to have an approved Oil Pollution Emergency Plan ("OPEP") for each drilling unit operating in U.K. waters. The Offshore Directive also specifies additional regulations related to safety, licensing, environmental protection, emergency response and liability with which we comply.
Additionally, pursuant to the IMO MARPOL 73/78, 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 in conjunction with the rig's emergency response manual and updated as necessary. Onboard drills are conducted periodically to maintain effectiveness of the plan, and each rig is outfitted with equipment to respond to minor spills. For operations anywhere in the world including in the U.S., our SOPEPs are subject to review and approval by Flag State, or a Recognized Organization acting on behalf of Flag State.
As the designated responsible party, an operator has the primary responsibility for spill response, including having contractual arrangements in place with emergency spill response organizations to supplement any onboard spill response equipment. Pursuant to our SOPEPs, we have certain resources and supplies onboard our drilling units to mitigate the impact of an incident until an emergency spill response organization can deploy its resources. However, we also have an agreement with an emergency spill response organization should we have an incident that exceeds the scope of our onboard spill response equipment. Our primary spill response provider in the U.S. specializes in helping industries prevent and clean up oil and other hydrocarbon spills. Our provider has represented it holds all necessary licenses, certifications and permits to respond to environmental emergencies in the

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US GOM and maintains contracts with other response resources and organizations outside the US GOM. We believe we have adequate equipment and third-party resources available to us to respond to an emergency spill; however, we can provide no assurance that adequate resources will be available. 
We are actively involved in various industry-led initiatives and work groups, including but not limited to those of the International Maritime Organization (a specialized agency of the United Nations), United States Coast Guard National Offshore Safety Advisory Committee, American Petroleum Institute, the International Association of Drilling Contractors, the Offshore Operations Committee, the Oil Companies International Marine Forum, the Center for Offshore Safety and the British Rig Owners Association, which are intended to improve safety and protection of the environment.
Oil and gas operations in the US GOM and in many of the other jurisdictions in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive SEMS. Any serious oil and gas industry related event heightens governmental and environmental concerns and may lead to legislative proposals being introduced which may materially limit or prohibit offshore drilling in certain areas. New regulations may 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.
Regulatory compliance has and may continue to materially impact our capital expenditures and earnings, particularly in the event of an environmental incident. Given the state-of-the-art design of our drillships and high specification of our jack-up fleet, we believe we are well positioned competitively to our peers to be able to comply with current and future governmental regulations.
Insurance
We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution and other types of loss or damage. Our insurance coverage is subject to deductibles and self-insured retentions which must be met prior to any recovery. Additionally, our insurance is subject to exclusions and limitations, and we can provide no assurance that such coverage will adequately protect us against liability from all potential consequences and damages.
Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of either $25 million or $15 million per occurrence, depending on the unit's geographic location. This coverage does not include damage to our rigs arising from a US GOM named windstorm, for which we are self-insured.
We maintain insurance policies providing limited coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability) and automobile liability, and these policies are subject to various exclusions, deductibles and underlying limits. In addition, we maintain excess liability coverage with an annual aggregate limit of $700 million subject to a self-insured retention of $10 million except for liabilities (including removal of wreck) arising out of a US GOM named windstorm, which are subject to a self-insured retention of $200 million.
Our rig physical damage and liability insurance renews each June. We can provide no assurance we will be able to secure coverage of a similar nature with similar limits at comparable costs upon renewal.
Employees
At December 31, 2017, we had approximately 2,800 employees worldwide, compared to approximately 2,900 and 3,500 at December 31, 2016 and 2015, respectively, and approximately 330 independent contractors. Certain of our employees and contractors in various regions, such as Trinidad and Norway, are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation. We consider relations with our employees to be satisfactory.
Customers
In 2017, Saudi Aramco, Anadarko, and Cobalt accounted for 29%, 17% and 14%, respectively, of consolidated revenue. Saudi Aramco revenue was derived from our Jack-ups segment, and Anadarko and Cobalt revenue was derived from our Deepwater segment.
Reports filed with or furnished to the SEC
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website

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at www.rowan.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on or accessible from our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered a part of this report or any other filing that we make with the SEC.
ITEM 1A.  RISK FACTORS
There are numerous factors that affect our business and operating results, many of which are beyond our control. The following is a description of significant factors that might cause our future operating results to differ materially from those currently expected. The risks described below are not the only risks facing our Company.
Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by declines in oil or gas prices and reduced demand for oil and gas products.
Our business depends heavily on a variety of economic and political factors and the level of oil and gas activity worldwide. Sustained declines in oil or natural gas prices, combined with market expectations of a prolonged weakened global market, have caused oil and gas companies to significantly reduce their exploration, development and production activities, thereby decreasing demand for offshore drilling services and leading to lower rig utilization and day rates for our services. Oil and natural gas prices have historically been very volatile, and our drilling operations have in the past suffered through long periods of weak market conditions.
Demand for our drilling services depends on many factors beyond our control, including:
worldwide demand for and prices of oil and natural gas, and expectations regarding future energy prices;
the supply of drilling units in the worldwide fleet versus demand;
the level of exploration and development expenditures by energy companies and their ability to raise capital;
the willingness and ability of the 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, interest rates and changes in the rate of economic growth;
the condition of global capital markets;
adverse sea, weather and climate conditions in our principal operating areas, including possible disruption of exploration and development activities due to loop currents, hurricanes and other severe sea and weather conditions;
the cost of exploring for, developing, producing and delivering oil and natural gas;
environmental and other laws and regulations;
policies of various governments regarding exploration and development of oil and natural gas reserves;
nationalization of assets or workforce and/or confiscation of assets;
worldwide tax policies and treaties;
political and military conflicts in oil-producing areas and the effects of terrorism;                                                                                                                  
increased supply of oil and gas from onshore development and relative cost of offshore drilling versus onshore oil and gas production;
the development and exploitation of alternative fuels and energy sources including the growing demand, often government-mandated, for electric powered vehicles; and
merger, divestiture, restructuring and consolidation of our customers and competitors and their assets.
Adverse developments affecting the industry as a result of one or more of these factors, including any further decline in oil or gas prices or the failure of oil or gas prices to increase, a global recession, continued declines in demand for oil and gas products, increased oversupply of drilling units, and increased regulation of drilling and production, would adversely affect our business, financial condition and results of operations.

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The success of our business is dependent upon our ability to secure contracts for our drilling units at sufficient day rates. Depressed oil and gas prices and an oversupply of drilling units have led to further reductions in rig utilization and day rates, which may materially impact our profitability.
Our ability to meet our cash flow obligations depends on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 13, 2018, we had nine jack-up drilling units without contracts (including two cold-stacked and two recently purchased jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs); eleven with contract terms ending in 2018; and three with contract terms ending in 2019; and three of our four drillships without contracts; one of our drillships has a contract ending in 2018. Given current market conditions, future demand for offshore drilling units and day rates may continue to remain at low levels, possibly for an extended period of time. Failure to secure profitable contracts for our drilling units could negatively impact our operating results and financial position, impair our ability to generate sufficient cash flow to fund our capital expenditures and/or meet our other obligations.
Prior to the downturn in the drilling sector, the industry experienced a significant increase in construction activity. The resulting increase in supply of newbuild drilling units, combined with the decrease in demand for offshore drilling services, has led to an oversupply of drilling units and further declines in utilization and day rates that is expected to continue for some time. According to industry sources, there were 463 marketed jack-up rigs worldwide as of February 13, 2018, an additional 91 units that are under construction or on order and 201 marketed floaters (drillships and semi-submersible) worldwide, with an additional 42 units that are under construction or on order. (We define marketed rigs as all rigs that are not cold-stacked.) A continued decline in utilization and day rates would further impact our revenue and profitability. 
A further decline in the market for contract drilling services could result in additional asset impairment charges.
We recognized asset impairment charges on our jack-up drilling units aggregating approximately $330 million in 2015 and $34 million in 2016, or approximately 4% and 0.5%, respectively, of our fixed asset carrying values. Prolonged periods of low utilization and day rates, the cold-stacking of idle assets, or the sale of assets below their then carrying value could result in the recognition of additional impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable. See “Impairment of Long-lived Assets” in Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
We are subject to operating risks that could result in environmental damage, property loss, personal injury, death, business interruptions and other losses.
Our drilling operations are subject to many operational hazards such as blowouts, explosions, fires, collisions, punch-throughs (i.e., when one leg of a jack-up rig breaks through the hard crust of the ocean floor, placing stress on the other legs), mechanical or technological failures, navigation errors, or equipment defects that could increase the likelihood of accidents. Accidents can result in:
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 punch-throughs and towing accidents resulting in lost or damaged equipment and high-pressure drilling accidents resulting in lost or damaged formations. Any future such events could result in operating losses and have a material impact on our business.

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The global nature of our operations involves additional risks, particularly in certain jurisdictions.
Our operations are diversified geographically although we have a concentrated presence in certain locations.  Foreign operations are often subject to additional political, economic and other uncertainties, such as with respect to taxation policies, customs restrictions, local content requirements, regulatory requirements, currency convertibility and repatriation restrictions, security threats including terrorism, piracy, and the risk of asset expropriation.  Political unrest and regulatory restrictions could halt operations or impact us in other unforeseen ways, especially in areas of concentrated presence (see Note 13 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K).
Many countries have regulations or policies requiring or rewarding the participation of local companies and individuals in petroleum-related activities. Such participation requirements can include, without limitation, the ownership of oil and gas concessions, the hiring of local agents and partners, the procurement of goods and services from local sources, and the employment of local workers. The requirements can also include co-ownership of our drilling units, in whole or in part, by home country companies or citizens and /or require reflagging of our drilling units under the flag of the home country. The governments of many of these countries have become increasingly active in requiring higher levels of local participation which may increase our costs and risks of operating in these regions, thereby limiting our ability to enter into, relocate from, or compete in these regions.
In addition, our inability to obtain visas and work permits for our employees in the jurisdictions in which we operate on a timely basis could delay or interrupt our operations resulting in an adverse impact on our business. Further, governmental restrictions in some jurisdictions may make it difficult for us to move our personnel, assets and operations in and out of these regions without delays or downtime.
In certain jurisdictions where legal protections may be less available to us, we assume greater risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action.  Additionally, operations in certain areas, such as the North Sea and US GOM, are highly regulated and have higher compliance and operating costs in general.
Although we are a U.K. company, a significant majority of our revenue and expenses are transacted in USD, which is our functional currency. However, in certain countries in which we operate, local laws or contracts may require us to receive some portion of payment in the local currency.  We are exposed to foreign currency exchange risk to the extent the amount of our monetary assets denominated in the foreign currency differs from our obligations in that foreign currency. In order to mitigate the effect of exchange rate risk, we attempt to limit foreign currency holdings to the extent they are needed to pay liabilities denominated in the foreign currency. We can provide no assurance that we will be able to convert into USD or utilize such foreign currency holdings due to controls over currency exchange or controls over the repatriation of income or capital. For more information, see “Assets and Liabilities Measured at Fair Value on a Recurring Basis” in Note 7 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K.
The offshore drilling industry is highly competitive and cyclical, with intense price competition.
The offshore contract drilling industry is a highly competitive and cyclical business characterized by numerous competitors, high capital and operating costs and evolving capability of newer rigs. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition, rig availability, location and suitability, experience of the workforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing, and client relations are all factors in determining which contractor is awarded a contract. Our future success and profitability will partly depend upon our ability to keep pace with our customers’ demands with respect to these factors.
In addition to intense competition, our industry has historically been cyclical. The contract drilling industry is currently in a period of low demand for offshore drilling services and excess rig supply, resulting from a prolonged period of weak oil and gas prices and reduced worldwide drilling activity. These conditions have intensified the competition in the industry and put significant downward pressure on day rates. As a result, we may be unable to secure profitable contracts for our drilling units, we may have to contract our rigs at substantially lower rates for long periods of time, enter into nontraditional fee arrangements, accept less favorable contract terms or idle or cold-stack some of our drilling units, all of which would adversely affect our operating results, cash flows and financial position.
We may experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of drilling revenue may not be fully realized.
We may be subject to the increased risk of our customers seeking to terminate or renegotiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by their own financial position, restricted credit markets and the current industry downturn. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for

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an extended period of time, or if a number of our contracts are renegotiated, such events would adversely affect our business, financial condition and results of operations.
Most of our term drilling contracts may be canceled by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the drilling unit, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. While most of our contracts require the customer to pay a termination fee in the event of an early cancellation without cause, early termination payments may not fully compensate us for the loss of the contract and could result in the drilling unit becoming idle or cold-stacked for an extended period of time.  If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts having less favorable terms, our backlog of estimated revenue would decline, adversely affecting our financial results.
We must make substantial capital and operating expenditures to maintain and upgrade our drilling fleet.
Our business is highly capital intensive and dependent on having sufficient cash flow and or available sources of financing in order to fund capital expenditure requirements. We can provide no assurance that we will have access to adequate or economical sources of capital to fund necessary capital and operating expenditures.
We have and will likely continue to have certain customer concentrations, and the loss of a significant customer would adversely impact our financial results.
A concentration of customers increases the risks associated with any possible (i) termination or nonperformance of drilling contracts, (ii) failure to renew contracts or award new contracts, or (iii) reduction of our customers' drilling programs. In 2017, three customers accounted for 60% of our consolidated revenue (Saudi Aramco - 29%; Anadarko - 17%; Cobalt - 14%). The loss or material reduction of business from a significant customer would have an adverse impact on our results of operations and cash flows.  Moreover, our drilling contracts subject us to counterparty risks. The ability of each of our counterparties to perform its obligations under a contract with us will depend on a number of factors that are beyond our control such as the overall financial condition of the counterparty. Should a significant counterparty fail to honor its obligations under an agreement with us, we could sustain losses, which could have a material adverse effect on our business, financial condition and results of operations.
If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our profitability may be reduced.
Crude oil and natural gas exploration and production operations require numerous permits and approvals for us and our customers from governmental agencies in the areas in which we operate.  In addition, many governmental agencies have increased regulatory oversight and permitting requirements in recent years.  If we or our customers are not able to obtain necessary permits and approvals in a timely manner, our operations will be adversely affected.  Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals. Future changes to these permits or approvals or any adverse change in the interpretation of existing permits and approvals could result in further unexpected, substantial expenditures.  In addition, such regulatory requirements and restrictions could also delay or curtail our operations, require us to make substantial expenditures to meet compliance requirements, and could have a material impact on our financial condition or results of operations and may create a risk of expensive delays or loss of value if a project is unable to function as planned.
For example, the U.S. Bureau of Ocean Energy Management and BSEE, have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM.  These regulations have at times adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits.  
We may not realize the expected benefits of the ARO joint venture and it may introduce additional risks to our business.
In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each selling existing drilling units and contributing capital as the foundation of the new company. The new entity, ARO, commenced operations on October 17, 2017, and is expected to add up to 20 newbuild jack-up rigs to its fleet over ten years commencing as early as 2021. There can be no assurance that the new jack-up rigs will begin operations as anticipated or we will realize the expected return on our investment. We may also experience difficulty jointly managing the venture, and integrating our existing employees, business systems, technologies and services with those of Saudi Aramco in order to operate the joint venture efficiently. Further, in the event ARO has insufficient cash from operations or is unable to obtain third party financing, we may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion, which could affect our liquidity position. As a result of these risks, it may take longer than expected for us to realize the expected returns from ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and harm our operating results or financial condition.

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Operating through ARO, in which we have a shared interest, may also result in us having less control over many decisions made with respect to projects and internal controls relating to projects. ARO may not apply the same internal controls and internal control reporting that we follow. As a result, internal control issues may arise, which could have a material adverse effect on our financial condition and results of operations. Additionally, in order to establish or preserve our relationship with our joint venture partner, we may agree to risks and contributions of resources that are proportionately greater than the returns we could receive, which could reduce our income and return on our investment in ARO compared to what we may traditionally require in other areas of our business.
Increases in regulatory requirements could significantly increase our costs or delay our operations.
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. For example, operations in certain areas, such as the US GOM and the North Sea, are highly regulated and have higher compliance and operating costs in general. We may be required to make significant expenditures in order to comply with existing or new governmental laws and regulations. It is also possible that such laws and regulations may in the future add significantly to our operating costs or result in a reduction of revenue associated with downtime required to implement regulatory requirements.
Oil and gas operations in many of the locations in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive safety and environmental management system, or SEMS. New regulations continue to be implemented, including rules regarding drilling systems and equipment, such as blowout preventer and well-control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third-party audits of SEMS programs. Such new regulations may require modifications or enhancements to existing systems and equipment, or require new equipment, and could increase our operating costs and cause downtime for our units if we are required to take any of them out of service between scheduled surveys or inspections, or if we are required to extend scheduled surveys or inspections to meet any such new requirements. Additional governmental regulations concerning licensing, taxation, equipment specifications, training requirements or other matters could increase the costs of our operations and could reduce exploration activity in the areas in which we operate.
Governments in some countries are increasingly active in regulating and controlling the ownership of concessions, the exploration for oil and gas, and other aspects of the oil and gas industry. These governmental regulations may limit or substantially increase the cost of drilling activity in an operating area generally. The modification of existing laws or regulations or the adoption of new laws or regulations curtailing exploratory or developmental drilling for oil and gas for economic, environmental or other reasons could materially and adversely affect our operations by limiting drilling opportunities. In addition, the offshore drilling industry is highly dependent on demand for services from the oil and gas industry and accordingly, regulations of the production and transportation of oil and gas generally could impact demand for our services.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Numerous large cities globally and a few countries have mandated conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation, thereby reducing future demand for oil which could have a material impact on our business. Laws, regulations, treaties and international agreements related to greenhouse gases and climate change may unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs, operating restrictions and could reduce drilling in the offshore oil and gas industry, all of which would have a material adverse impact on our business.
Our drilling units are subject to damage or destruction by severe weather, and our drilling operations may be affected by severe weather conditions.
Our drilling rigs are located in areas that frequently experience hurricanes and other forms of severe weather conditions. These conditions can cause damage or destruction to our drilling units. Further, high winds and turbulent seas can cause us to suspend operations on drilling units for significant periods of time.  Even if our drilling units are not damaged or lost due to severe weather, we may experience disruptions in our operations due to evacuations, reduced ability to transport personnel or necessary supplies to the drilling unit, or damage to our customers’ platforms and other related facilities.  Additionally, our customers may not choose to contract our rigs for use during hurricane season, particularly in the US GOM.  Future severe weather could result in the loss

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or damage to our rigs or curtailment of our operations, which could adversely affect our financial position, results of operations and cash flows.
Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.
We are subject to tax laws, regulations and treaties in many jurisdictions. Changes to these laws or interpretations could affect the taxes we pay in various jurisdictions. Our tax positions are subject to audit by relevant tax authorities who may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations, or their applicability to our corporate structure or certain of our transactions we have undertaken.  We could therefore incur material amounts of income tax cost in excess of currently recorded amounts if our positions are challenged and we are unsuccessful in defending them.
Changes in or non-compliance with tax laws and changes to our income tax estimates could adversely impact our financial results.
In 2012, we changed our legal domicile to the U.K. There have been legislative proposals in the U.S. that attempted to treat companies that have undertaken similar transactions as U.S. corporations subject to U.S. taxes or to limit the tax deductions or tax credits available to U.S. subsidiaries of these corporations. The realization of the expected tax benefits of our redomestication could be impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof or differing interpretation or enforcement of applicable law by the IRS or other tax authorities. Changes in our effective tax rates as determined from time to time, the inability to realize anticipated tax benefits, or the imposition of additional taxes could have a material impact on our results of operations, financial position and cash flows. Our future effective tax rates could be adversely affected by changes in the valuation of our deferred tax assets and liabilities, repatriation of earnings from the non-U.S. subsidiaries of RCI, a wholly owned, indirect subsidiary of the Company, or changes in applicable regulations and accounting principles.
Changes in our recorded tax estimates (including estimated reserves for uncertain tax positions) may have a material impact on our results of operations, financial position and cash flows. We do not provide for deferred income taxes on certain undistributed earnings of non-U.K. subsidiaries. No subsidiary of RCI has a plan to distribute earnings to RCI in a manner that would cause those earnings to be subject to U.S., U.K. or other local country taxation.
On December 22, 2017, the U.S. government enacted tax legislation commonly referred to as the U.S. Tax Act. The U.S. Tax Act significantly changes U.S. corporate income tax laws including but not limited to (i) reducing the U.S. corporate income tax rate from 35% to 21% starting in 2018 (ii) requiring a one-time transition tax on mandatory deemed repatriation of certain unremitted non-U.S. earnings as of December 31, 2017, (iii) changing how non-U.S. subsidiaries are taxed in the U.S. as of January 1, 2017, (iv) eliminating the carryback abilities and establishing an 80% limitation on the annual utilization of net operating losses after December 31, 2017, (v) establishing new limitations on interest deductions as of January 1, 2018 and (vi) requiring additional U.S. tax on certain payments by U.S. subsidiaries to non-U.S. subsidiaries if such payments are subject to reduced rates of U.S. withholding tax under a treaty after December 31, 2017. As we do not have all the necessary information to analyze all effects of this tax reform, our financial statements include provisional amounts, which we believe represents a reasonable estimate of the accounting implications of this tax reform.
The U.S. Tax Act requires complex computations to be performed that were not previously provided in U.S. tax law, significant judgments to be made in interpretation of the U.S. Tax Act, and the preparation and analysis of information not previously relevant or regularly produced. As such, the application of accounting guidance for such items is currently uncertain. As a result, we have provided a provisional estimate on the effect of the U.S. Tax Act in our financial statements. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts.

Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.
Our operations are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas, which may result in extended business interruptions, suspended operations and danger to our employees, or result in claims by our customers of a force majeure situation and payment disputes.  Additionally, we are subject to risks of terrorism, piracy, political instability, hostilities, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in many of our areas of operations.

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Operating and maintenance costs of our drilling units may be significant and could have an adverse effect on the profitability of our contracts. In addition, operational interruptions or maintenance or repair work may cause our customers to suspend or reduce payment of day rates until operation is resumed, which may lead to loss of revenue or termination or renegotiation of the drilling contract.
Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation and reduced day rates during periods of other activities.  Given current market conditions, we may not be able to negotiate day rates sufficient to cover increased or unanticipated costs. Our operating expenses and maintenance costs can be unpredictable and depend on a variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, customer and regulatory requirements, and shipyard costs, many of which are beyond our control. Our profit margins may therefore vary over the terms of our contracts, which could adversely affect our financial position, results of operations and cash flows.
Our customers may be entitled to pay a waiting, or standby, rate lower than the full operational day rate if a drilling unit is idle for reasons that are not related to the ability of the rig to operate. In addition, if a drilling unit is taken out of service for maintenance and repair for a period of time exceeding the scheduled maintenance periods set forth in the drilling contract, we may not be entitled to payment of day rates until the unit is able to work. If the interruption of operations were to exceed a determined period, our customers may have the right to pay a rate that is significantly lower than the waiting rate for a period of time, and, thereafter, may terminate the drilling contracts related to the subject rig. Suspension of drilling contract payments, prolonged payment of reduced rates or termination of any drilling contract as a result of an interruption of operations could materially adversely affect our business, financial condition and results of operations.
Our rig operating and maintenance costs include fixed costs that will not decline in proportion to decreases in rig utilization and day rates.
We do not expect our rig operating and maintenance costs to decline proportionately when rigs are not in service or when day rates decline.  Fixed costs continue to accrue during out-of-service periods (such as shipyard stays and rig mobilizations preceding a contract), which represented approximately 6.8% of our available rig days in 2017. Operating revenue may fluctuate as rigs are recontracted at prevailing market rates upon termination of a contract, but costs for operating a rig are generally fixed or only slightly variable regardless of the day rate being earned.  Additionally, if our rigs are idle between contracts, we typically continue to incur operating and personnel costs because the crew is retained to prepare the rig for its next contract.  During times of reduced activity, reductions in costs may not be immediate as some crew members may be required to assist in the rig's removal from service.  Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.
We may have difficulty obtaining or maintaining insurance in the future, and some of our losses may not be covered by insurance.
We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution, and other types of loss or damage.  There are some losses, however, for which insurance may not be available or only available at much higher prices. For example, we do not currently maintain named windstorm physical damage coverage on any of our drilling units located in the US GOM.  
We can provide no assurance that our insurance coverage will adequately protect us against liability from potential consequences and damages, or that we will be able to maintain adequate insurance in the future. A significant event which is not adequately covered by insurance and /or the failure of one or more of our insurance providers to meet claim obligations or losses or liabilities resulting from uninsured or underinsured events could have material adverse affects on our financial position, results of operations and cash flows.
Our contractual indemnification provisions may not be sufficient to cover our liabilities.
Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between the parties with respect to liabilities resulting from various hazards associated with the drilling industry, such as loss of well control, well-bore pollution and damage to subsurface reservoirs and injury or death to personnel.  The degree of indemnification we may receive from operators varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated, and recovery is dependent on the customer's financial condition. Our drilling contracts generally indemnify us for injuries and death of our customers’ employees and loss or damage to our customers’ property.  Our service agreements generally indemnify us for injuries and death of our service providers’ employees. However, the enforceability of our indemnities may be subject to differing interpretations, or further limited or prohibited under applicable law, particularly in cases of gross negligence, willful misconduct, punitive damages or punitive fines and/or penalties.  The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from or unenforceable under contractual indemnification obligations would adversely affect our financial position, results of operations and cash flows.

17


Our information technology systems are subject to cybersecurity risks and threats.
We depend heavily on technologies, systems and networks that we manage, and others that are managed by our third-party service and equipment providers or customers, to conduct our business and operations.  Cybersecurity risks and threats to such systems continue to grow and may be difficult to anticipate, prevent, identify or mitigate. If any of our, our service providers' or our customers' security systems prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our companies’, employees’, vendors’ or customers’ confidential or proprietary information altered, lost or stolen, or our (or our customers’) business operations, financial systems or safety procedures disrupted, degraded or damaged. A breach or failure could also result in injury (financial or otherwise) to people, loss of control of, or damage to, our (or our customers’) assets, harm to the environment, reputational damage, breaches of laws or regulations, litigation and other legal liabilities.  In addition, we may incur significant costs to prevent, respond to or mitigate cybersecurity risks or events and to defend against any investigations, litigation or other proceedings that may follow such events.  Such a failure or breach of our systems could adversely and materially impact our business operations, financial position, results of operations and cash flows.
Failure to comply with anti-corruption and anti-bribery laws could result in fines, criminal penalties and drilling contract terminations and could have an adverse impact on our business.
The FCPA, the UK Bribery Act and similar laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to governmental officials for the purpose of obtaining or retaining business. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the FCPA, UK Bribery Act, or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to civil and criminal penalties or other sanctions, which would adversely affect our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant jurisdictions, including prohibition of our participation in or curtailment of business operations in those jurisdictions and the seizure of drilling units or other assets.
Failure to retain highly skilled personnel could hurt our operations.
We require highly skilled and experienced personnel to operate our rigs and provide technical services and support for our operations.  In the past, during periods of high demand for drilling services and increasing worldwide industry fleet size, shortages of qualified personnel have occurred. The recent prolonged industry downturn may further reduce the number of qualified personnel available in the future. Such shortages could result in our loss of qualified personnel to competitors, impair the timeliness and quality of our work and create upward pressure on costs. If we are unable to retain or train skilled personnel, our operations and quality of service could be adversely impacted.
We are involved in litigation and legal proceedings from time to time that could have a negative effect on us if determined adversely.
We are, from time to time, involved in various legal proceedings, which may include, among other things, contract disputes, personal injury, environmental, toxic tort, employment, tax and securities litigation, governmental investigations or proceedings, and litigation that arises in the ordinary course of our business. Although we intend to defend any of these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter.  Our profitability may be adversely affected by the outcome of claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any purported nullification, cancellation or breach of contracts with customers or other parties.  Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of resources, reputational damage, and other factors.
Downgrades in our credit ratings may affect our ability to access the credit and debt capital markets.
Our ability to maintain a sufficient level of liquidity to meet our financial and operating needs is dependent upon our future performance, operating cash flows, and our access to credit and debt capital markets. In turn, our level of liquidity and access to credit and debt capital markets depends on general economic conditions, industry cycles, financial, business and other factors affecting our operations, as well as our credit ratings. Tightening in the credit markets due to the current economic environment, concerns about the offshore drilling industry and our credit ratings may restrict our access to the credit and debt capital markets in the future and increase the cost of such indebtedness. As a result, our future cash flows and access to capital may be insufficient to meet all of our capital requirements, debt obligations and contractual commitments, and any insufficiency could have an adverse impact on our business.
Certain credit rating agencies have downgraded our credit ratings below investment grade and may further downgrade our credit ratings at any time. A further downgrade in our ratings could have adverse consequences on our business and future prospects, including the following:

18


Restrict our ability to access credit and debt capital markets;
Cause us to refinance or issue debt with less favorable terms and conditions;
Negatively impact current and prospective customers’ willingness to transact business with us;
Impose additional insurance, guarantee and collateral requirements; or
Limit our access to bank and third-party guarantees, surety bonds and letters of credit.
Technology disputes could negatively impact our operations or increase our costs.
Drilling rigs use proprietary technology and equipment which can involve potential infringement of a third party’s rights, including patent rights. The majority of the intellectual property rights relating to our jack-ups and drillships are owned by us or our suppliers or sub-suppliers, however, in the event that we or one of our suppliers or sub-suppliers becomes involved in a dispute over infringement rights relating to equipment owned or used by us, we may lose access to repair services or replacement parts, or we could be required to cease use of some equipment or forced to modify our jack-ups or drillships. We could also be required to pay license fees or royalties for the use of equipment. Technology disputes involving us, or our suppliers or sub-suppliers could adversely affect our financial results and operations.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in various regions such as Trinidad and Norway are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation.  Further, efforts may be made from time to time to unionize other portions of our workforce. In addition, we have experienced, and in the future may experience, strikes or work stoppages and other labor disruptions. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenue or limit our operations.
Supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenue and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations could expose us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenue by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs. Our reliance on one or more of these third-party suppliers could further exacerbate such issues.
The enforcement of civil liabilities against Rowan plc may be more difficult.
Because Rowan plc is a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against Rowan plc in U.S. courts than would be the case for U.S. judgments obtained against a U.S. company.  In addition, it may be more difficult to bring some types of claims against Rowan plc in courts in the U.K. than it would be to bring similar claims against a U.S. company in a U.S. court.
Our articles of association include mandatory offer provisions that may have the effect of discouraging, delaying or preventing hostile takeovers, including those that might result in a premium being paid over the market price of our shares, and discouraging, delaying or preventing changes in control or management.
Although Rowan plc is not currently subject to the U.K. Takeover Code, certain provisions similar to the mandatory offer provisions and certain other aspects of the U.K. Takeover Code are included in our articles of association. As a result, among other matters, a Rowan plc shareholder, that together with persons acting in concert, acquired 30 percent or more of our issued shares without making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative would be at risk of certain Board sanctions unless they acted with the consent of our Board or the prior approval of the shareholders.  The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association.  The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the

19


consent of our Board before effecting any additional purchases.  In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.
As a result of shareholder approval requirements required under U.K. law, we may have less flexibility than a Delaware corporation with respect to certain aspects of capital management.
Unlike most U.S. state corporate law, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders, which such authorization may only extend for a maximum period of five years. English law also generally provides shareholders preemptive rights when new shares are issued for cash unless such rights are waived by the shareholders.
English law also generally prohibits us from repurchasing our shares on the open market and prohibits us from repurchasing our shares by way of “off-market purchases” without the prior approval of shareholders, which approval may only extend for a maximum period of five years.
At our 2017 annual general meeting of shareholders, our Board was authorized to allot a certain amount of shares, exclude certain preemptive rights in shares for cash offerings and effect off market purchases, in each case without further shareholder approval. However, these authorizations expire in May 2018. As such, we will be unable to issue new shares or repurchase shares unless and until we receive renewed shareholder approval. In addition, even if approved by shareholders, our ability to issue and repurchase shares may be substantially more restricted than a U.S. company.
English law requires that we meet certain additional financial requirements before we declare dividends and return funds to shareholders.
Under English law, a public company may only declare dividends and make other distributions to shareholders (such as a share buyback) if the company has sufficient distributable reserves and meets certain net asset requirements. If we do not have sufficient distributable reserves or cannot meet the net asset requirements, we may be limited in our ability to timely pay dividends and effect other distributions to our shareholders.
The U.K.’s referendum to exit from the E.U. will have uncertain effects and could adversely impact our business, results of operations and financial condition.
On June 23, 2016, the U.K. voted to exit from the E.U. (commonly referred to as Brexit). The terms of Brexit and the resulting U.K./E.U. relationship are uncertain for companies doing business both in the U.K. and the overall global economy. In addition, our business and operations may be impacted by any subsequent vote in Scotland to seek independence from the U.K. Risks related to Brexit that we may encounter include:
adverse impact on macroeconomic growth and oil and gas demand;
continued volatility in currencies including the British pound and USD that may impact our financial results;
reduced demand for our services in the U.K. and globally;
increased costs of doing business in the U.K. and in the North Sea;
increased regulatory costs and challenges for operating our business in the North Sea;
volatile capital and debt markets, and access to other sources of capital;
risks related to our global tax structure and the tax treaties upon which we rely;
business uncertainty resulting from prolonged political negotiations; and
uncertain stability of the E.U. and global economy if other countries exit the E.U.
ITEM 1B.  UNRESOLVED STAFF COMMENTS
The Company has no unresolved SEC staff comments.

20


ITEM 2.  PROPERTIES
Our primary U.S. offices are located in leased space in Houston, Texas. Additionally, we own or lease other office, maintenance and warehouse facilities in the U.S., Saudi Arabia (primarily for ARO operations), Norway, Scotland, Trinidad, Bahrain, Dubai, Luxembourg and Egypt.
Drilling Rigs
Following is the principal drilling equipment owned by Rowan and its location at February 13, 2018.
 
 
Depth (feet)
 
 
Rig Name/Type
Class Name
Water (6)
Drilling (7)
Year of Shipyard Delivery
Location
 
 
 
 
 
 
Ultra-Deepwater Drillships:
 
 
 
 
 
Rowan Renaissance
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Resolute
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Reliance
Gusto MSC P10,000
12,000
40,000
2014
US GOM
Rowan Relentless
Gusto MSC P10,000
12,000
40,000
2015
US GOM
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
Rowan Norway (1)
N-Class
400
35,000
2011
U.K.
Rowan Stavanger (1)
N-Class
400
35,000
2011
Norway
Rowan Viking (1)
N-Class
435
35,000
2010
Norway
Bob Palmer (1) (5)
Super Gorilla XL
475
35,000
2003
Saudi Arabia
Rowan Gorilla VII (1)
Super Gorilla
400
35,000
2001
U.K.
Rowan Gorilla VI (1)
Super Gorilla
400
35,000
2000
Trinidad
Rowan Gorilla V (1)
Super Gorilla
400
35,000
1998
U.K.
Joe Douglas (1)
240C
350
35,000
2012
Trinidad
Ralph Coffman (1)
240C
350
35,000
2009
In-transit to US GOM
Rowan Mississippi (1) (5)
240C
375
35,000
2008
Saudi Arabia
Rowan EXL IV  (1)
EXL
320
35,000
2011
Bahrain
Rowan EXL III (1)
EXL
350
35,000
2010
US GOM
Rowan EXL II (1)
EXL
350
35,000
2010
Trinidad
Rowan EXL I (1)
EXL
350
35,000
2010
Bahrain
P-59 (2) (4)
Super 116E
350
30,000
2013
Brazil
P-60 (2) (4)
Super 116E
350
30,000
2013
Brazil
Hank Boswell (1) (5)
Tarzan
300
35,000
2006
Saudi Arabia
Scooter Yeargain (1) (5)
Tarzan
300
35,000
2004
Saudi Arabia
Rowan California (2)(3)
116C
300
25,000
1983
Bahrain
Arch Rowan (2) (5)
116C
300
25,000
1981
Saudi Arabia
Charles Rowan (2) (5)
116C
300
25,000
1981
Saudi Arabia
Rowan Middletown (2) (5)
116C
300
25,000
1980
Saudi Arabia
Rowan Gorilla IV (1) (3)
Gorilla
450
30,000
1986
US GOM
______________________________     
(1)     High-specification jack-up, which is defined as having hook-load capacity of at least two million pounds.
(2)     Premium jack-up, which is defined as an independent leg, cantilevered rig capable of operating in water depths of 300 feet or more.    
(3)     Currently cold-stacked.
(4)    Purchased in January 2018 and not yet placed in service.
(5)    Managed by ARO.
(6)    Water depths are the maximum "rated" depths as currently outfitted.
(7)    Maximum estimated drilling depth, subject to well characteristics and rig outfitting.

21


ITEM 3.  LEGAL PROCEEDINGS
We are involved in various routine legal proceedings incidental to our businesses and vigorously defend our position in all such matters.  Although the outcome of such proceedings cannot be predicted with certainty, we believe there are no known contingencies, claims or lawsuits that will have a material adverse effect on our financial position, results of operations or cash flows.
ITEM 4.  MINE SAFETY DISCLOSURES
Not applicable.
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 as reported on the NYSE for the periods indicated.
 
 
2017
 
2016
Quarter
 
High
 
Low
 
High
 
Low
First
 
$
20.50

 
$
14.05

 
$
18.43

 
$
10.67

Second
 
15.96

 
10.04

 
19.94

 
14.58

Third
 
13.07

 
9.02

 
19.06

 
12.00

Fourth
 
15.79

 
12.35

 
21.68

 
13.02

On February 21, 2018, there were 72 shareholders of record. Many of our shareholders hold their shares in "street name" by a nominee of Depository Trust Company, which is a single shareholder of record.
In January 2016, our Board discontinued dividend payments.

22


The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment & Services Index, and the S&P 500 Index for the five-year period ended December 31, 2017, assuming reinvestment of dividends.
 chart2017.jpg

 
 
12/31/2012
 
12/31/2013
 
12/31/2014
 
12/31/2015
 
12/31/2016
 
12/31/2017
Rowan
 
100.00

 
113.08

 
75.39

 
55.89

 
62.28

 
51.63

S&P 500 Index
 
100.00

 
132.39

 
150.51

 
152.59

 
170.84

 
208.14

Dow Jones US Oil Equipment & Services Index
 
100.00

 
128.41

 
106.29

 
82.40

 
104.91

 
87.38



23


Issuer Purchases of Equity Securities
The following table presents information with respect to acquisitions of our shares for the fourth quarter of 2017:
Month ended
 
Total number of shares purchased (1)
 
Average price paid per share (1)
 
Total number of shares purchased as part of publicly announced plans or programs (2)
 
Approximate dollar value of shares that may yet be purchased under the plans or programs (2)
October 1 - 31, 2017
 
1,996

 
$
12.71

 

 
$

November 1 - 30, 2017
 
168

 
$
13.90

 

 
$

December 1 - 31, 2017
 
7,996

 
$
14.99

 

 
$

Total
 
10,160

 
$
14.52

 

 
 

 
 
 
 
 
 
 
 
 
(1) The total number of shares acquired includes shares acquired from employees by an affiliated EBT in satisfaction of tax withholding requirements. 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 2017.
(2) The ability to make share repurchases is subject to the discretion of our Board and the limitations set forth in the U.K. Companies Act of 2006, which generally provide that share repurchases may only be made out of distributable reserves. At our 2017 general meeting of shareholders on May 25, 2017, our shareholders approved new repurchase agreements and counterparties, which approval will remain valid until May of 2022. Our Board has authority to commence or suspend share repurchase programs from time to time without prior notice pursuant to these approved repurchase agreements. There are no share repurchase programs outstanding at December 31, 2017.
For information concerning our shares to be issued in connection with equity compensation plans, see Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters in Part III, Item 12, of this Annual Report on Form 10-K.

24


ITEM 6.  SELECTED FINANCIAL DATA
Selected financial data for each of the last five years is presented below:
 
2017
 
2016
 
2015
 
2014
 
2013
 
(Dollars in millions, except per share amounts)
Operations
 
 
 
 
 
 
 
 
 
Revenue
$
1,282.8

 
$
1,843.2

 
$
2,137.0

 
$
1,824.4

 
$
1,579.3

Costs and expenses:
 

 
 

 
 

 
 

 
 

Direct operating costs (excluding items shown below)
684.8

 
778.2

 
993.1

 
991.3

 
860.9

Depreciation and amortization
403.7

 
402.9

 
391.4

 
322.6

 
271.0

Selling, general and administrative
104.9

 
102.1

 
115.8

 
125.8

 
131.3

Gain on sale of assets to unconsolidated subsidiary (1)
(157.4
)
 

 

 

 

(Gain) loss on disposals of property and equipment
9.4

 
8.7

 
(7.7
)
 
(1.7
)
 
(20.1
)
Gain on litigation settlement (2)

 

 

 
(20.9
)
 

Material charges and other operating items (3)

 
32.9

 
337.3

 
574.0

 
4.5

Total costs and expenses
1,045.4

 
1,324.8

 
1,829.9

 
1,991.1

 
1,247.6

Equity in earnings from unconsolidated subsidiary
0.9

 

 

 

 

Income (loss) from operations
238.3

 
518.4

 
307.1

 
(166.7
)
 
331.7

Other income (expense) — net (4)
(139.0
)
 
(192.8
)
 
(149.4
)
 
(102.9
)
 
(70.5
)
Income (loss) from continuing operations before income taxes
99.3

 
325.6

 
157.7

 
(269.6
)
 
261.2

Provision (benefit) for income taxes
26.6

 
5.0

 
64.4

 
(150.7
)
 
8.6

Income (loss) from continuing operations
72.7

 
320.6

 
93.3

 
(118.9
)
 
252.6

Discontinued operations, net of taxes (5)

 

 

 
4.0

 

Net income (loss)
$
72.7

 
$
320.6

 
$
93.3

 
$
(114.9
)
 
$
252.6

Basic income (loss) per common share:
 

 
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
0.58

 
$
2.56

 
$
0.75

 
$
(0.96
)
 
$
2.04

Income (loss) from discontinued operations

 

 

 
0.03

 

Net income (loss)
$
0.58

 
$
2.56

 
$
0.75

 
$
(0.93
)
 
$
2.04

Diluted income (loss) per common share:
 

 
 

 
 

 
 

 
 

Income (loss) from continuing operations
$
0.57

 
$
2.55

 
$
0.75

 
$
(0.96
)
 
$
2.03

Income (loss) from discontinued operations

 

 

 
0.03

 

Net income (loss)
$
0.57

 
$
2.55

 
$
0.75

 
$
(0.93
)
 
$
2.03

Financial Position
 

 
 

 
 

 
 

 
 

Cash and cash equivalents
$
1,332.1

 
$
1,255.5

 
$
484.2

 
$
339.2

 
$
1,092.8

Property and equipment — net
$
6,552.7

 
$
7,060.0

 
$
7,405.8

 
$
7,432.2

 
$
6,385.8

Total assets
$
8,458.3

 
$
8,675.6

 
$
8,347.3

 
$
8,392.3

 
$
7,975.8

Current portion of long-term debt
$

 
$
126.8

 
$

 
$

 
$

Long-term debt, less current portion
$
2,510.3

 
$
2,553.4

 
$
2,692.4

 
$
2,788.5

 
$
2,008.7

Shareholders’ equity (6)
$
5,386.1

 
$
5,113.9

 
$
4,772.5

 
$
4,691.4

 
$
4,893.8

Statistical Information
 

 
 

 
 

 
 

 
 

Current ratio (7)
6.06

 
3.27

 
2.80

 
2.82

 
4.50

Debt to capitalization ratio
32
%
 
34
%
 
36
%

37
%

29
%
Book value per share of common stock outstanding
$
42.66

 
$
40.76

 
$
38.24

 
$
37.66

 
$
39.39

Price range of common stock:
 

 
 

 
 

 
 

 
 

High
$
20.50

 
$
21.68

 
$
25.13

 
$
35.17

 
$
38.65

Low
$
9.02

 
$
10.67

 
$
14.63

 
$
19.50

 
$
30.21

Cash dividends declared per share
$

 
$

 
$
0.40

 
$
0.30

 
$

___________________
(1)
In 2017, the Company recognized a $157.4 million gain on the sale of assets to ARO.
(2)
Gain on litigation settlement includes: 2014 – a gain of $20.9 million in cash received for damages incurred as a result of a tanker’s collision with the Rowan EXL I in 2012.
(3)
Material charges and other operating expenses consisted of the following: 2016 – $34.3 million of non-cash impairment charges and a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. A payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest; 2015 – $329.8 million of non-cash asset impairment charges and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015; 2014 – $574.0 million of non-cash asset impairment charges; and 2013 – $4.5 million of non-cash asset impairment charges.
(4)
In 2016, other income (expense), net includes $31.2 million loss on debt extinguishment.

25


(5)
In 2011, the Company sold its manufacturing and land drilling operations, which were classified as discontinued operations. In 2014, we sold a land rig retained from the sale and recognized a $4.0 million gain, net of tax.
(6)
2017 includes a $206.6 million increase to Retained earnings related to the adoption of ASU No. 2016-16.
(7)
Current ratio excludes assets and liabilities of discontinued operations.
ITEM 7.  MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OUR BUSINESS
We are a global provider of offshore contract drilling services to the oil and gas industry, with a focus on high-specification and premium jack-up rigs and ultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, we now operate in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the various arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East and Trinidad.
As of February 13, 2018, the date of our most recent Fleet Status Report, one of our four ultra-deepwater drillships was under contract in the US GOM. We had three jack-up rigs under contract in the North Sea, seven under contract in the Middle East, three under contract in Trinidad and one under contract in the US GOM. Additionally, we had an additional five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Gain on sale of assets to unconsolidated subsidiary
On October 17, 2017, pursuant to an Asset Transfer and Contribution Agreement with ARO, we agreed to sell three rigs to ARO: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets for a total cash consideration of $357.7 million. The book value of these assets was approximately $200.3 million. As a result of this sale transaction with ARO, we recognized a gain on the disposal of rig assets in the amount of $157.4 million in 2017. See Notes 1, 3 and 14 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Customer Contract Termination Amendment
On September 15, 2016, we amended our contract with Cobalt, for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Customer Contract Termination and Settlement
On May 23, 2016, we reached an agreement with FMOG and its parent company, FCX, in connection with the drilling contract for the drillship Rowan Relentless, which was scheduled to terminate in June 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.

26


CURRENT BUSINESS ENVIRONMENT
Commodity prices have broadly improved over the past six months and industry sentiment is more favorable. However, the business environment for offshore drillers continues to be challenging due to a decrease in operators' offshore capital expenditures for the third year in a row, and an imbalance of offshore rig supply and demand, resulting in downward pressure on utilization and day rates.
Over the past three years, the cancellation and postponement of drilling programs have resulted in significantly reduced demand for offshore drilling services globally. Additionally, the 247 new jack-ups and 163 new floaters that have been delivered since the beginning of the current newbuild cycle in early 2006 have exacerbated the supply and demand imbalance. Since the industry downturn, contractors have responded by retiring assets, stacking certain idle equipment and deferring newbuild deliveries.  Since the beginning of 2014, we estimate that approximately 50 jack-ups and 101 floaters have been removed from the total fleet in various forms of attrition. Partly as a result of these actions, overall marketed utilization, for both jack-ups and floaters, appears to have stabilized. However, excessive levels of idle capacity continue to pressure day rates.

Further, as of February 13, 2018, there were 91 additional jack-up rigs on order or under construction worldwide for delivery through 2020 (relative to approximately 328 jack-up rigs currently on contract), and 42 floaters on order or under construction worldwide for delivery through 2021 (relative to approximately 150 floater rigs currently on contract). Only 14 floaters currently on order or under construction have contracts secured for their future delivery dates. To our knowledge, none of the jack-up newbuilds have contracts in place. We expect several of these rigs may eventually be cancelled and many others will likely continue to be deferred until a recovery in demand is visible.
In response to market conditions over the past three years, we have reduced day rates on certain drilling contracts, some in exchange for extended contract duration, agreed to certain contract terminations, sold six of our oldest jack-ups, cold-stacked two of our older jack-ups, and have had as many as six warm stacked jack-ups and three warm stacked ultra-deepwater drillships. As of February 13, 2018, five jack-ups and three ultra-deepwater drillships were marketed and not under contract.
While we have seen some recent improvement in tender activity, given the current offshore rig supply and demand dynamics, we expect the marketing environment to remain extremely competitive across the broad offshore rig market for the next few years until a more pronounced recovery in offshore rig demand materializes. Due to the short cycle nature of the shallow water markets, we expect jack-up demand to improve in advance of the floater market.
Despite the challenging business environment, we believe that we are strategically well-positioned to take advantage of the next up-cycle given our financial condition, solid operational reputation, and modern fleet of high-specification jack-ups and state-of-the-art ultra-deepwater drillships. While challenging market conditions persist, we continue to focus on operating efficiencies, cost cutting initiatives, upgrade of various systems and data analytics to drive improved drilling performance and predictive maintenance.
RESULTS OF OPERATIONS
We analyze the financial results of each of our operating segments. The operating segments presented are consistent with our reportable segments discussed in Note 13 of our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.

27


The following table presents certain key performance indicators by rig classification (7):
 
2017
 
2016
 
2015
Revenue (in millions):
 
 
 
 
 
Deepwater
 
 
 
 
 
Day rate revenue
$
465.7

 
$
824.7

 
$
730.8

Rebillable revenue (1)
2.2

 
2.8

 
17.0

Total Deepwater
$
467.9

 
$
827.5

 
$
747.8

 
 
 
 
 
 
Jack-ups
 
 
 
 
 
Day rate revenue
$
784.7

 
$
994.7

 
$
1,361.3

Secondment revenue (1)
9.2

 

 

Rebillable revenue (1)
12.0

 
18.1

 
26.0

Miscellaneous revenue (1)
1.6

 
2.9

 
1.9

Total Jack-ups
$
807.5

 
$
1,015.7

 
$
1,389.2

 
 
 
 
 
 
Unallocated
 
 
 
 
 
Transition services revenue (1)
$
7.4

 
$

 
$

 
 
 
 
 
 
Total revenue
$
1,282.8

 
$
1,843.2

 
$
2,137.0

 
 
 
 
 
 
Revenue-producing days: (2)
 
 
 
 
 
Deepwater
783

 
1,238

 
1,178

Jack-ups
6,144

 
5,999

 
7,852

Total revenue-producing days
6,927

 
7,237

 
9,030

 
 
 
 
 
 
Available days: (3)
 
 
 

 
 

Deepwater
1,460

 
1,464

 
1,263

Jack-ups
8,162

 
8,784

 
9,558

Total available days
9,622

 
10,248

 
10,821

 
 
 
 
 
 
Average day rate (in thousands): (4)
 

 
 

 
 

Deepwater (2) (5)
$
594.8

 
$
550.7

 
$
620.5

Jack-ups
$
127.7

 
$
165.8

 
$
173.4

Total fleet (2) (5)
$
180.5

 
$
231.7

 
$
231.7

 
 
 
 
 
 
Utilization: (2) (6)
 
 
 
 
 
Deepwater
54
%
 
85
%
 
93
%
Jack-ups
75
%
 
68
%
 
82
%
Total fleet
72
%
 
71
%
 
83
%
 
 
 
 
 
 
(1) Rebillable, secondment, miscellaneous and transition services revenue is excluded from the computation of average day rate.
(2) Revenue-producing days for the year ended December 31, 2017, includes 125 days for the Deepwater drillship Rowan Reliance when it was not operating. The drillship did not operate in the third and fourth quarter of 2017, but was available for Cobalt through November 2, 2017 per the 2016 contract amendment (See Note 1 of "Notes to Consolidated Financial Statements" in Item 8 of this Annual Report on Form 10-K). Revenue of $70 million, previously deferred in 2016, was recognized during the year ended December 31, 2017 related to these days for which the rig was available to Cobalt but was not operating as well as the recognition of any remaining deferred revenue at November 2, 2017 as Cobalt did not exercise their right to use the rig.
(3) Available days are defined as the aggregate number of calendar days (excluding days for which a rig is cold-stacked) in the period, or, with respect to new rigs entering service, the number of calendar days in the period from the date the rig was placed in service.
(4) Average day rate is computed by dividing day rate revenue by the number of revenue-producing days, including fractional days. Day rate revenue includes 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. Revenue attributable to reimbursable expenses is excluded from average day rates.
(5) Average day rate for 2016 includes operating days for the Rowan Relentless up to the contract termination which was 143 days for 2016.
(6) Utilization is the number of revenue-producing days, including fractional days, divided by the number of available days.
(7) All revenue and KPIs exclude the results from rigs owned by ARO beginning on October 17, 2017, the date the rigs were sold to ARO.

28


Rig Utilization (4) 
The following table sets forth an analysis of time that our rigs were idle or out-of-service as a percentage of available days (which excludes cold-stacked rigs) and time that our rigs experienced operational downtime and are off-rate as a percentage of revenue-producing day:
 
2017
 
2016
 
2015
Deepwater:
 
 
 
 
 
Idle (1)
46.4
%
 
15.2
%
 
%
Out-of-service (2)
%
 
0.1
%
 
%
Operational downtime (3)
%
 
0.1
%
 
6.7
%
 
 
 
 
 
 
Jack-up:
 
 
 
 
 
Idle (1)
15.7
%
 
25.4
%
 
13.5
%
Out-of-service (2)
8.1
%
 
5.3
%
 
3.3
%
Operational downtime (3)
1.3
%
 
1.4
%
 
1.2
%
 
 
 
 
 
 
(1) Idle Days – We define idle days as the time a rig is not under contract and is available to work. Idle days exclude cold-stacked rigs, which are not marketed.
(2) Out-of-Service Days – We define out-of-service days as those days when a rig is (or is planned to be) out of service and is not able to earn revenue. The Company may be compensated for certain out-of-service days, such as for shipyard stays or for rig transit periods preceding a contract; however, recognition of any such compensation is deferred and recognized over the primary term of the drilling contract.
(3) Operational Downtime – We define operational downtime as the unbillable time when a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures.
(4) All revenue and utilization metrics exclude the results from rigs owned by ARO beginning on October 17, 2017, the date the rigs were sold to ARO.


29


2017 Compared to 2016
A summary of our consolidated results of operations follows (in millions):
 
Year ended December 31,
 
 
 
 
 
2017
 
2016
 
Change
 
% Change
Deepwater:
 
 
 
 
 
 
 
Revenue
$
467.9

 
$
827.5

 
$
(359.6
)
 
(43
)%
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
151.4

 
222.0

 
(70.6
)
 
(32
)%
Depreciation and amortization
111.6

 
115.0

 
(3.4
)
 
(3
)%
Other operating items - expense
0.1

 
0.1

 

 
n/m

Income from operations
$
204.8

 
$
490.4

 
$
(285.6
)
 
(58
)%
 
 
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
 
 
Revenue
$
807.5

 
$
1,015.7

 
$
(208.2
)
 
(20
)%
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
533.4

 
556.2

 
(22.8
)
 
(4
)%
Depreciation and amortization
289.4

 
282.6

 
6.8

 
2
 %
Gain on sale of assets to unconsolidated subsidiary
(157.4
)
 

 
(157.4
)
 
n/m

Other operating items - expense
9.3

 
40.9

 
(31.6
)
 
n/m

Income from operations
$
132.8

 
$
136.0

 
$
(3.2
)
 
(2
)%
 
 
 
 
 
 
 
 
ARO:
 
 
 
 
 
 
 
Revenue
$
48.6

 
$

 


 
 
Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
22.2

 

 


 
 
Depreciation and amortization
12.9

 

 


 
 
Selling, general and administrative
6.1

 

 


 
 
Other operating items - income
(0.1
)
 

 


 
 
Income from operations
$
7.5

 
$

 


 
 
 
 
 
 
 
 
 
 
Unallocated and other:
 
 
 
 
 
 
 
Revenue
$
7.4

 
$

 
$
7.4

 
n/m

Operating expenses:
 
 
 
 
 
 
 
Depreciation and amortization
2.7

 
5.3

 
(2.6
)
 
(49
)%
Selling, general and administrative
104.9

 
102.1

 
2.8

 
3
 %
Other operating items - expense

 
0.6

 
(0.6
)
 
n/m

Loss from operations
$
(100.2
)
 
$
(108.0
)
 
$
7.8

 
(7
)%
 
 
 
 
 
 
 
 
“n/m” - not meaningful.
 
 
 
 
 
 
 

30


 
Year ended December 31,
 
 
 
 
 
2017
 
2016
 
Change
 
% Change
Reportable segments total:
 
 
 
 
 
 
 
Revenue
$
1,331.4

 
$
1,843.2

 


 


Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
707.0

 
778.2

 


 


Depreciation and amortization
416.6

 
402.9

 


 


Selling, general and administrative
111.0

 
102.1

 


 


Gain on sale of assets to unconsolidated subsidiary
(157.4
)
 

 


 


Other operating items - expense
9.3

 
41.6

 


 


Income from operations
$
244.9

 
$
518.4

 


 


 
 
 
 
 
 
 
 
Eliminations and adjustments:
 
 
 
 
 
 
 
Revenue
$
(48.6
)
 
$

 


 


Operating expenses:
 
 
 
 
 
 
 
Direct operating costs (excluding items below)
(22.2
)
 

 


 


Depreciation and amortization
(12.9
)
 

 


 


Selling, general and administrative
(6.1
)
 

 


 
 
Other operating items - income
0.1

 

 


 
 
Equity in earnings of unconsolidated subsidiary
$
0.9

 
$

 


 
 
Loss from operations
$
(6.6
)
 
$

 


 


 
 
 
 
 
 
 
 
Total company:
 
 
 
 
 
 
 
Revenue
$
1,282.8

 
$
1,843.2

 
$
(560.4
)
 
(30
)%
Direct operating costs (excluding items below)
684.8

 
778.2

 
(93.4
)
 
(12
)%
Depreciation and amortization
403.7

 
402.9

 
0.8

 
 %
Selling, general and administrative
104.9

 
102.1

 
2.8

 
3
 %
Gain on sale of assets to unconsolidated subsidiary
(157.4
)
 

 
(157.4
)
 
n/m

Other operating items - expense
9.4

 
41.6

 
(32.2
)
 
n/m

Equity in earnings of unconsolidated subsidiary
0.9

 

 
0.9

 
n/m

Income from operations
$
238.3

 
$
518.4

 
$
(280.1
)
 
(54
)%
Other (expense), net
(139.0
)
 
(192.8
)
 
53.8

 
(28
)%
Income before income taxes
99.3

 
325.6

 
(226.3
)
 
(70
)%
Provision for income taxes
26.6

 
5.0

 
21.6

 
n/m

Net Income
$
72.7

 
$
320.6

 
$
(247.9
)
 
(77
)%
 
 
 
 
 
 
 
 
“n/m” - not meaningful.
 
 
 
 
 
 
 


31


Revenue
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
 
Increase (decrease)
Fewer operating days
$
(277.1
)
Prior year Contract Termination for Rowan Relentless and related items
(142.7
)
Lower reimbursable revenue
(0.6
)
Higher drillship day rates (a)
60.8

Decrease
$
(359.6
)
 
 
(a) Higher average drillship day rates resulted largely from the blend and extend arrangement for the Rowan Resolute. In addition, in November 2017 the Company accelerated the recognition of approximately $29 million in previously deferred revenue for the Rowan Reliance (to which no operating days were associated) as Cobalt did not exercise their right to use the rig. These increases were partially offset by a decrease for the Rowan Reliance due to lower average day rates in 2017 compared to 2016.
Jack-ups. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
 
Increase (decrease)
Lower jack-up day rates
$
(244.2
)
Decrease due to sale of assets to ARO
(12.6
)
Lower reimbursable revenue
(6.1
)
Lower other revenue
(1.3
)
Increased operating days
46.8

Increase in ARO related secondment reimbursables
9.2

Decrease
$
(208.2
)
Unallocated. From October 17, 2017 to December 31, 2017, we recorded $7.4 million of revenue related to transition services provided to ARO (see Note 1 and Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).

Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
 
Decrease
Decrease due to idle drillships
$
(44.8
)
Reduction in shore base costs and other
(17.6
)
Reduction in drillship direct operating expenses
(7.6
)
Lower reimbursable costs
(0.6
)
Decrease
$
(70.6
)

32


Jack-ups. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
 
Increase (decrease)
Decrease due to idle or cold-stacked rigs
$
(21.5
)
Decrease due to sale of assets to ARO
(7.8
)
Lower reimbursable costs
(6.1
)
Reduction in shore base costs and other
(2.1
)
Increase in ARO related secondment reimbursable costs
9.2

ARO management fee
7.8

Reduction in jack-up direct operating expenses
(2.3
)
Decrease
$
(22.8
)
Gain on sale of assets to unconsolidated subsidiary
We recognized a gain of $157.4 million on the sale of assets to ARO. See Notes 1, 3 and 14 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
In 2017, we had a loss on disposals of property and equipment of $9.4 million compared to a loss of $8.7 million in 2016.
Other expense, net
The decrease in Other expense, net, is primarily due to a $1.7 million gain on the early extinguishment of debt in 2017 compared to a net loss on the early extinguishment of debt of $31.2 million in 2016. Interest income increased in 2017 primarily due to higher cash balances in 2017 as compared to 2016, and $2.1 million of interest income related to the note receivable from ARO (see Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). Additionally, our foreign currency exchange losses decreased to $0.4 million in 2017 compared to $9.7 million in 2016 primarily due to the devaluation of the Egyptian pound in 2016.
Provision for income taxes
In 2017, we recognized an income tax provision of $26.6 million on pretax income of $99.3 million. The 2017 tax provision primarily includes $28.7 million of tax expense for current year operations, $20.5 million of tax expense due to an increase in the valuation allowance assessed on deferred tax assets, and a partial offset by a $27.3 million reduction in accrued unrecognized tax benefits due to a lapse in statutes of limitation and an audit settlement.
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The 2016 tax provision was primarily due to 2016 operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of 2016 restructuring.


33


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

 
$
747.8

 
$
79.7

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

 
276.6

 
(54.6
)
 
(20
)%
Depreciation and amortization
115.0

 
94.6

 
20.4

 
22
 %
Other operating items - expense
0.1

 

 
0.1

 
n/m

Income from operations
$
490.4

 
$
376.6

 
$
113.8

 
30
 %
 
 
 
 
 
 
 
 
Jack-ups:
 
 
 
 
 
 
 
Revenue
$
1,015.7

 
$
1,389.2

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

 
716.5

 
(160.3
)
 
(22
)%
Depreciation and amortization
282.6

 
283.9

 
(1.3
)
 
 %
Other operating items - expense
40.9

 
328.8

 
(287.9
)
 
n/m

Income from operations
$
136.0

 
$
60.0

 
$
76.0

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

 
$
12.9

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

 
115.8

 
(13.7
)
 
(12
)%
Other operating items - expense
0.6

 
0.8

 
(0.2
)
 
n/m

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

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

 
$
2,137.0

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

 
993.1

 
(214.9
)
 
(22
)%
Depreciation and amortization
402.9

 
391.4

 
11.5

 
3
 %
Selling, general and administrative
102.1

 
115.8

 
(13.7
)
 
(12
)%
Other operating items - expense
41.6

 
329.6

 
(288.0
)
 
n/m

Income from operations
$
518.4

 
$
307.1

 
$
211.3

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

 
157.7

 
167.9

 
106
 %
Provision for income taxes
5.0

 
64.4

 
(59.4
)
 
(92
)%
Net Income
$
320.6

 
$
93.3

 
$
227.3

 
244
 %
 
 
 
 
 
 
 
 
“n/m” - not meaningful.
 
 
 
 
 
 
 


34


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

Lower drillship average day rates
(84.8
)
Lower reimbursable revenue
(14.3
)
Rowan Reliance and Rowan Relentless fully in service in 2016 versus startup in February and June of 2015, respectively, net of idle time in 2016
21.5

Lower unbillable downtime
14.6

Increase
$
79.7

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

Decrease
$
(373.5
)
Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
 
Increase (decrease)
Reduction in drillship direct operating expense
$
(34.8
)
Decrease due to idle drillship
(15.4
)
Lower reimbursable costs
(14.3
)
Reduction in shore base costs and other
(9.8
)
Addition of Rowan Reliance and Rowan Relentless
19.7

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

35


Selling, general and administrative
Selling, general and administrative expenses for 2016 decreased largely due to lower personnel costs. In addition, professional fees and information technology expenses decreased in 2016 as compared to 2015.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
Material charges for 2015 included a $329.8 million non-cash impairment charge to reduce the carrying values of ten of our jack-up drilling units and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement for this matter was signed during the third quarter of 2015.
In 2016, we had a loss on disposals of property and equipment of $8.7 million compared to a gain of $7.7 million in 2015.
Other expense, net
The increase in Other Expense, Net, is primarily due to a $31.2 million net loss on the early extinguishment of debt in 2016 compared to $1.5 million in 2015. Interest capitalization was $16.2 million in 2015. There was no interest capitalization in 2016 as the drillship construction program was completed in 2015. Additionally, our foreign currency exchange losses increased to $9.7 million in 2016 compared to $3.9 million in 2015 primarily due to the devaluation of the Egyptian pound. Partially offsetting these increases, our debt retirements in late 2015 and early 2016 resulted in a reduction in interest expense in 2016.
Provision for income taxes
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The 2016 tax provision was primarily due to 2016 operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of 2016 restructuring.
In 2015, we recognized an income tax provision of $64.4 million on pretax income of $157.7 million. The 2015 tax provision was primarily due to the establishment of a valuation allowance on the U.S. deferred tax assets, impairments of assets in jurisdictions with no tax benefits, and an increase in income in high-tax jurisdictions, offset by additional tax benefit for the U.S. impaired assets and an increase in income in low-tax jurisdictions.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios at December 31 were as follows (dollars in millions):
 
2017
 
2016
Cash and cash equivalents
$
1,332.1

 
$
1,255.5

Current assets
$
1,560.4

 
$
1,580.3

Current liabilities
$