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, 2018
OR
¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________

Commission File Number: 1-5491

Rowan Companies plc

(Exact name of registrant as specified in its charter)

England and Wales	98-1023315
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

2800 Post Oak Boulevard, Suite 5450

Houston, Texas 77056-6189

(Address of principal executive offices)

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Name of each exchange on which registered
Class A ordinary shares, $0.125 par value	New York Stock Exchange

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 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 $2.1 billion as of June 30, 2018, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange of $16.22 per share.

The number of Class A ordinary shares, $0.125 par value, outstanding at February 21, 2019, was 127,294,643, which excludes 908,042 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 2019 Annual General Meeting of Shareholders	Part III, Items 10-14

	Page
PART I
Item 1. Business	6
Item 1A. Risk Factors	12
Item 1B. Unresolved Staff Comments	24
Item 2. Properties	25
Item 3. Legal Proceedings	26
Item 4. Mine Safety Disclosures	26
PART II
Item 5. Market for Registrant’s Common Stock, Related Stockholder Matters, and Issuer Purchases of Equity Securities	26
Item 6. Selected Financial Data	29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A. Quantitative and Qualitative Disclosures about Market Risks	49
Item 8. Financial Statements and Supplementary Data	51
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	112
Item 9A.Controls and Procedures	112
Item 9B. Other Information	113
PART III
Item 10. Directors, Executive Officers and Corporate Governance	113
Item 11. Executive Compensation	114
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	114
Item 13. Certain Relationships and Related Transactions, and Director Independence	115
Item 14. Principal Accounting Fees and Services	115
PART IV
Item 15. Exhibits and Financial Statement Schedules	115
Item 16. Form 10-K Summary	120

FORWARD-LOOKING STATEMENTS

Statements contained in this Annual Report on Form 10-K (this "Annual 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; the proposed transaction with Ensco plc; dividend payments; share repurchases or repayment of debt; business strategies; expected utilization, day rates, revenue, operating expenses, contract terms, contract backlog and fleet status; performance 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 Existing Credit Facility and New 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:

• failure, difficulties and delays in meeting conditions required for closing set forth in the agreement governing the Transaction with Ensco;

• the potential impact of the announcement or consummation of the Transaction with Ensco on relationships, including with employees, suppliers, customers, competitors, lenders and credit rating agencies;

• our ability to successfully integrate the operations of the Company and Ensco and to realize synergies and cost savings following the consummation of the Transaction;

• 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, application 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 we 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;

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

• potential cost overruns and other risks inherent with repairs, inspections or upgrades 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, related to well-control issues, collisions, groundings, blowouts, fires, explosions, weather or hurricane delays or damage, losses or liabilities (including wreckage or debris removal) or otherwise;

• our ability to retain highly skilled personnel on commercially reasonable terms, whether due to competition, cost cutting initiatives, labor regulations, unionization or otherwise; our ability to seek and receive visas for our personnel to work in our areas of operation in a timely manner;

• governmental action and political and economic uncertainties, including uncertainty or instability resulting from civil unrest, military or political demonstrations, acts of war, strikes, terrorism, piracy or outbreak or escalation of hostilities or other crises, 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 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;

• system implementations and upgrades;

• economic volatility and political, legal and tax uncertainties following the June 23, 2016, vote in the U.K. to exit from the European Union ("Brexit") and any subsequent referendum in Scotland to seek independence from the U.K.;

• other important factors described from time to time in the reports filed by us with the 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 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, 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.

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GLOSSARY OF TERMS

The following frequently used abbreviations or acronyms are used in this Annual Report 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
Company	Rowan Companies plc together with its wholly-owned subsidiaries
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
Ensco	Ensco plc, a public limited company organized under the laws of England and Wales
Exchange Act	Securities Exchange Act of 1934
Existing Credit Agreement	The Company's amended and restated senior unsecured revolving credit agreement entered into with a group of lenders on May 22, 2018, which matures January 23, 2021
Existing Credit Facility	Commitments in the amount of $310.7 million provided by a group of lenders under the Existing Credit Agreement
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
New Credit Agreement	The Company's senior unsecured revolving credit agreement entered into with a group of lenders on May 22, 2018, which matures May 22, 2023
New Credit Facility	Commitments in the amount of $955 million provided by a group of lenders under the New Credit Agreement
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

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Abbreviation/Acronym	Definition
RCI	Rowan Companies Inc., a subsidiary of the Company
Retiree Medical Plan	Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc.
Rowan plc	Rowan Companies plc
Rowan SERP	Restoration Plan of Rowan Companies, Inc.
RSAs	Restricted Share Awards
RSUs	Restricted Share Units
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
Transaction	The transactions contemplated by the Transaction Agreement, pursuant to which each of the issued and outstanding Class A ordinary shares of the Company will be exchanged for 2.750 Class A ordinary shares of Ensco pursuant to a court-sanctioned scheme of arrangement under Part 26 of the U.K. Companies Act 2006
Transaction Agreement	The agreement, dated October 7, 2018, by and between the Company and Ensco, pursuant to which the Company and Ensco will effect a "merger-of-equals" transaction
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 ultra-deepwater drillships and high-specification and premium jack-up rigs. Many of our high specification jack-up rigs are also rated for operating in harsh environments. Our fleet operates worldwide, including the US GOM, Mexico, Central and South America, the U.K. and Norwegian sectors of the North Sea, the Middle East and the Mediterranean Sea. We currently operate in three segments: Deepwater, Jack-ups and ARO, our 50/50 joint venture with Saudi Aramco. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 21 self-elevating jack-up rigs and includes the impact of the various arrangements with ARO (see Note 4 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for more information. The information discussed therein is incorporated by reference into this Part I, Item 1.) ARO currently owns a fleet of seven self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. ARO has plans to order up to 20 new jack-up rigs over the next 10 years.

As of February 13, 2019, the date of our most recent Fleet Status Report, two of our four drillships were contracted in the US GOM, one was contracted in Mexico and the remaining drillship was marketed without a contract in the US GOM. For our jack-up fleet, we had four rigs under contract in the North Sea, one rig under contract in the Mediterranean Sea, three under contract in Central and South America and two under contract in the US GOM. In the Middle East, we had nine jack-ups leased to ARO to fulfill nine, three-year contracts between Saudi Aramco and ARO, two of which are expected to commence in the first half of 2019. Additionally, we own two jack-up rigs which are cold stacked.

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. Rigs leased to ARO will be through bareboat charter agreements whereby substantially all operating costs will be borne by ARO. ARO will contract with the customer, Saudi Aramco, and directly receive related revenue. For Rowan plc and its consolidated subsidiaries, intercompany balances and transactions have been eliminated in consolidation.

Proposed Combination of Rowan Companies plc and Ensco plc

On October 7, 2018, the Company entered into a Transaction Agreement with Ensco, to effect a “merger-of-equals” transaction. The Transaction Agreement was amended as of January 28, 2019, pursuant to a Deed of Amendment No. 1 to a Transaction Agreement (the “Amendment”). In the Transaction Agreement, as amended, each of the issued and outstanding Class A ordinary shares of the Company will be exchanged (the “Transaction”) for 2.750 Class A ordinary shares of Ensco, each with a nominal value of $0.10 per share. The Transaction is being implemented by means of a court-sanctioned scheme of arrangement (the “Scheme”) under Part 26 of the U.K. Companies Act 2006 (provided that the parties reserve the right under the Transaction Agreement to effect the acquisition by way of a contractual takeover offer as defined in section 974 of the U.K. Companies Act 2006 in certain circumstances). The resulting new combined company will be renamed and trade under a new ticker symbol on the New York Stock Exchange.

The completion of the Transaction is subject to various closing conditions, including, among other things, (i) the sanction of a court-sanctioned scheme of arrangement by the High Court of Justice of England and Wales, (ii) the receipt of the required regulatory approval or elapse of the review period with respect thereto in the Kingdom of Saudi Arabia, (iii) the absence of legal restraints prohibiting or restraining the Transaction and (iv) the absence of any law or order reasonably expected to result in the dissolution of ARO, the sale or disposition of the Company’s interest in ARO, or the forfeiture or nationalization of the Company's interest in ARO or ARO’s assets. The Transaction is expected to close during the first half of 2019.

The Transaction Agreement contains certain termination rights for both Rowan and Ensco including, among other things: (i) by Rowan or Ensco, if the other party breaches or fails to perform any of its representations, warranties or covenants in the Transaction Agreement that cannot be or is not cured in accordance with the terms of the Transaction Agreement and such breach constitutes a “material adverse effect”, (ii) by Rowan, in the event that the board of directors of Ensco makes an Adverse Recommendation Change (as defined in the Transaction Agreement) or upon any “willful breach” by Ensco of the non-solicitation covenant and (iii) by Ensco, in the event that the board of directors of Rowan makes an Adverse Recommendation Change (as defined in the

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Transaction Agreement) or upon any “willful breach” by Rowan of the non-solicitation covenant. If the Transaction Agreement is terminated in accordance with clause (i), (ii) or (iii), then Rowan or Ensco, as the applicable terminating party, shall be required to pay the other a termination fee of $24.0 million (the “Termination Fee”).

Neither Rowan nor Ensco is permitted, among other things, to solicit, initiate or knowingly facilitate or knowingly encourage any inquiries regarding, or the making of any proposal or offer that constitutes, or could reasonably be expected to lead to, a takeover proposal or engage in or participate in any discussions or negotiations regarding any takeover proposal.

The Transaction Agreement contains customary representations, warranties and covenants for a transaction of this nature. The Transaction Agreement also contains customary mutual pre-closing covenants, including the obligation of Rowan and Ensco to conduct their respective businesses in the ordinary course of practice consistent with past practice and to refrain from taking certain specified actions without the consent of the other party.

The foregoing description of the Transaction and the Transaction Agreement does not purport to be complete and is subject to, and qualified in its entirety by, the full text of the Transaction Agreement, a copy of which is included in Exhibit 2.1 as filed with the Form 8-K dated October 9, 2018, and the full text of the Deed of Amendment No. 1 to the Transaction Agreement, a copy of which is included as Exhibit 2.1 as filed with the Form 8-K filed January 29, 2019. The Transaction Agreement, as amended, has been referenced to provide investors with information regarding its terms. It is not intended to provide any other factual information about Rowan or Ensco. In particular, the assertions embodied in the representations and warranties contained in the Transaction Agreement are qualified by matters disclosed in certain of Rowan’s and Ensco’s filings with the SEC prior to the date of the Transaction Agreement and by information in confidential Disclosure Schedules provided by each of Rowan and Ensco to the other in connection with the signing of the Transaction Agreement. These confidential Disclosure Schedules contain information that modifies, qualifies and creates exceptions to the representations and warranties and certain covenants set forth in the Transaction Agreement. The representations, warranties and covenants are also subject to materiality qualifications contained in the Transaction Agreement that may differ from what may be viewed as material by investors. Moreover, certain representations and warranties in the Transaction Agreement were used for the purposes of allocating risk between Rowan and Ensco rather than establishing matters as facts. Accordingly, the representations and warranties in the Transaction Agreement should not be relied on as characterizations of the actual state of facts about Rowan or Ensco. The Transaction Agreement should not be read alone, but should instead be read in conjunction with other information regarding the Company that is or will be contained in, or incorporated by reference into, the Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other documents that the Company files or furnishes with the SEC.

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, Note 4 and Note 15 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report. The information discussed therein is incorporated by reference into this Part I, Item 1.

Drilling Fleet

We believe our fleet of ultra-deepwater drillships and high-specification and premium jack-ups is well positioned to serve the worldwide market. Many of our high specification jack-ups are also rated for operating in harsh environments. As of February 13, 2019, our drilling fleet consists of the following:

• Four ultra-deepwater drillships;

• Fifteen high-specification jack-up rigs; and

• Six premium jack-up rigs. 

We use the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments and the term “high-specification” to describe premium jack-ups that also have a hook-load capacity of at least two million pounds.

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 position reference 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

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simultaneous drilling tasks during certain stages of drilling, subject to legal restrictions in various jurisdictions, enabling increased drilling efficiency particularly during the initial stages of a well. In addition, our drillships are equipped to drill in 12,000-foot water depths, are equipped with 2,500,000-pound hook-load capability and are capable of drilling HPHT wells to 40,000-foot depths. Each is equipped with two fully redundant blowout preventers, which 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 until they penetrate the ocean floor. After the legs are securely set, 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 in up to 450 feet of water in harsh environments such as the North Sea depending on location and outfitting. 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 benign environments like the US GOM and the Middle East or in water depths up to 450 feet in harsh environments such as the North Sea depending on location and outfitting.

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.

In January 2018, we 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 four remaining 116C class rigs are premium rigs capable of operating in water depths up to 300 feet in benign environments. One of these rigs 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. This rig is cold-stacked.

We sold the Scooter Yeargain and Hank Boswell to ARO in October 2018. This follows the previous sale of one premium and two high-specification jack-ups in October 2017 to ARO (see Note 1 and Note 15 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report).

See Part I, Item 2, “Properties” of this Annual Report 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 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 multiple years. Well-to-well contracts are typically cancellable by either party upon completion of drilling a well. 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 contain renewal or extension provisions exercisable at the option of the customer at mutually agreeable or, in some cases, predetermined rates. Some of our drilling contracts provide for separate lump-sum payments for rig mobilization and

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demobilization. We record certain lump-sum fees and related expenses over the expected recognition period. 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 and in “Risk Factors” included in Part I, Item 1A of this Annual Report include the global economic climate, the price of oil and gas which can affect our customers' drilling budgets, over- supply of drilling units, location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, cost of securing competent drilling personnel and other competitive factors.  Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations and capital investment needed for contract specific requirements.

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 one ultra-deepwater drillship warm stacked. We have also cold-stacked certain of our idle older rigs to further reduce costs and have sold the following six such rigs over a period beginning in 2015: 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 $634.9 million at February 13, 2019, up from approximately $456.2 million at February 13, 2018. Our backlog excludes ARO's revenue, but includes bareboat charter and related revenue for jack-ups leased to ARO. 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 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 451 marketed jack-up rigs worldwide as of February 13, 2019, with an additional 77 units that are under construction or on order. (We define marketed rigs as all delivered rigs that are not cold-stacked.) We estimate that 79 marketed jack-ups, or 18 percent of the world’s marketed jack-up fleet, are high-specification, including Rowan's 14 marketed high-specification rigs.

At February 13, 2019, there were 196 marketed floaters (drillships and semi-submersibles) worldwide, with an additional estimated 31units that are under construction or on order. We estimate that 103 of these marketed floaters, or approximately 53 percent of the world’s marketed fleet, are capable of drilling in water depths of 10,000 feet or more, but only an estimated 36 floaters, or approximately 18 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 263 newbuild jack-ups and 165 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 support intense competition, putting downward pressure on day rates and utilization percentage in most regions and sectors. Of the approximately 77 jack-up rigs under construction worldwide scheduled for delivery through 2021 (25% of the currently utilized jack-up fleet of approximately 311 rigs), approximately 37 are considered high-specification (47% of the delivered and marketed high-specification fleet). Currently, there are approximately 44 competitive newbuild jack-up rigs scheduled for delivery during the remainder of 2019, and to our knowledge only one has a contract in place. There are approximately 31 floaters under construction worldwide for delivery through 2021 (25% of the currently utilized floater fleet of approximately 125 rigs). Following the negotiated delivery delays on several units into future years, there are approximately 16 competitive newbuild floaters scheduled for delivery during the remainder of 2019 and, to our knowledge, only one has a contract.

Based on the number of rigs as tabulated by IHS-Petrodata, we are the seventh largest offshore drilling contractor in the world and the sixth largest jack-up rig contractor. Based on market capitalization as of February 13, 2019, we are the third 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 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 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 events heighten 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 nature of the majority 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, 2018, we had approximately 3,300 employees worldwide, compared to approximately 2,800 and 2,900 at December 31, 2017 and 2016, respectively, and approximately 530 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 2018, Saudi Aramco, Anadarko, ARO Drilling, and BP Trinidad and Tobago accounted for 28%, 14%, 14%, and 10%, respectively, of consolidated revenue. Saudi Aramco and BP Trinidad and Tobago revenue was derived from our Jack-ups segment, Anadarko revenue was derived from our Deepwater segment and ARO Drilling revenue was derived from our Jack-ups segment as well as revenue for transition services provided to ARO which is included in Unallocated and other.

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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 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 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 declines in oil or gas prices or the failure of oil or gas prices to increase, a global recession, declines in demand for oil and gas products, increased oversupply

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of drilling units, and increased regulation of drilling and production, would adversely affect our business, financial condition and results of operations.

The success of our business is dependent upon our ability to secure contracts for our drilling units at sufficient day rates. Depressed oil and gas prices and an oversupply of drilling units have led to weak 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, 2019, we had two jack-up drilling units that are currently cold-stacked; seven with contract terms ending in 2019; two with contract terms ending in 2020; one with a contract term ending in 2021; and nine leased to ARO with leases ending in 2021. Additionally, one of our four drillships is without a contract; two have a contract ending in 2019 and one has a contract ending in 2020. Given current market conditions, future demand for offshore drilling units may continue at low day rate 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 levels of utilization and day rates that are expected to remain weak for some time. According to industry sources, there were 451 marketed jack-up rigs worldwide as of February 13, 2019, an additional 77 units that are under construction or on order and 196 marketed floaters (drillships and semi-submersible) worldwide, with an additional 31 units that are under construction or on order. A decline in utilization and day rates would further impact our revenue and profitability. 

A 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 $34 million in 2016, or approximately 0.5% 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 the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information.

We are subject to operating risks that could resultin 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.

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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.

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 14 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report).

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 8 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report.

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.

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

We may be subject to the increased risk of our customers seeking to terminate or renegotiate their contracts. Our customers’ ability to perform their obligations under drilling contracts with us may also be adversely affected by their own financial position, restricted credit markets and the current industry downturn. If our customers cancel or are unable to renew some of their contracts and we are unable to secure new contracts on a timely basis and on substantially similar terms, if contracts are disputed or suspended for an extended period of time, or if a number of our contracts are renegotiated, such events would adversely affect our business, financial condition and results of operations.

Most of our term drilling contracts may be canceled by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the drilling unit, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment. While most of our contracts require the customer to pay a termination fee in the event of an early cancellation without cause, early termination payments may not fully compensate us for the loss of the contract and could result in the drilling unit becoming idle or cold-stacked for an extended period of time.  If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts having less favorable terms, our backlog of estimated 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 2018, four customers accounted for 56% of our consolidated revenue (Saudi Aramco - 28%; Anadarko - 14%; ARO Drilling - 14%; BP Trinidad and Tobago - 10%). 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

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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.

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.

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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 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, 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. If facts and circumstances cause a change in the expectations regarding future tax consequences, the resulting tax impact could have a material effect on the Company’s consolidated financial statements.

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 January 1, 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. In 2017, the Company applied the guidance in accordance with the SEC Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118) that allowed provisional estimates for the tax effects of the U.S. Tax Act. During 2018, the accounting for this matter has been finalized. For more information see Note 13 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report.

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.  We are also 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. Finally, our business may be impacted by changes to trade policies or economic sanctions in places where we conduct or could conduct business.

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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 9.3% of our available rig days in 2018. 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.

Our cost reduction initiatives might have unintended consequences and could negatively impact our business.

In response to changes in our industry, we have implemented and are considering implementing initiatives to reduce costs and improve operational efficiencies. If we do not successfully manage these cost reduction activities, the expected efficiencies and benefits might be delayed or may not be realized, and our operations and business could be disrupted. In addition, there is the risk that such measures could negatively impact our business by reducing our ability to respond to a significant increase in demand for our services, erroneously omitting operational or financial controls, reducing our pool of talent, adversely affecting employee morale, distracting management, or slowing improvements in our services, any of which could adversely affect our business, financial condition and results of operations.

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.

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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.

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.  In addition, we rely on our employees to vigilantly follow the Company’s policies with respect to the use of these systems. Cybersecurity risks and threats to such systems have been encountered and 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 or our employees are not sufficiently vigilant, we could be adversely affected by having our business and financial systems compromised or made inoperable, 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

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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 economic environment, concerns about the offshore drilling industry and our credit ratings may restrict our access to the credit and debt capital markets in the future and increase the cost of such indebtedness. As a result, our future cash flows and access to capital may be insufficient to meet all of our capital requirements, debt obligations and contractual commitments, and any insufficiency could have an adverse impact on our business.

Certain credit rating agencies have downgraded our credit ratings below investment grade and may further downgrade our credit ratings at any time. A further downgrade in our ratings could have adverse consequences on our business and future prospects, including the following:

• Restrict our ability to access credit and debt capital markets;

• Cause us to refinance or issue debt with less favorable terms and conditions;

• 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.

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company.  In addition, it may be more difficult to bring some types of claims against Rowan plc in courts in the U.K. than it would be to bring similar claims against a U.S. company in a U.S. court.

Our articles of association include mandatory offer provisions that may have the effect of discouraging, delaying or preventing hostile takeovers, including those that might result in a premium being paid over the market price of our shares, and discouraging, delaying or preventing changes in control or management.

Although Rowan plc is not currently subject to the U.K. Takeover Code, certain provisions similar to the mandatory offer provisions and certain other aspects of the U.K. Takeover Code are included in our articles of association. As a result, among other matters, a Rowan plc shareholder, that together with persons acting in concert, acquired 30 percent or more of our issued shares without making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative would be at risk of certain Board sanctions unless they acted with the consent of our Board or the prior approval of the shareholders.  The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association.  The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the consent of our Board before effecting any additional purchases.  In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.

As a result of shareholder approval requirements required under U.K. law, we may have less flexibility than 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 2018 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 2019. 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.

Our business could be negatively affected by the actions of activist shareholders.

Certain of our shareholders may from time to time advance shareholder proposals or otherwise attempt to effect changes or acquire control over our business. Activist campaigns that contest or conflict with our strategic direction could have an adverse effect on our results of operations and financial condition. Responding to proxy contests and other actions by activist shareholders could disrupt our operations, be costly and time-consuming, and divert the attention of our Board and senior management from the pursuit of business strategies. In addition, perceived uncertainties as to our future direction may lead to the perception of a change in the direction of the business, instability or lack of continuity, which may be exploited by our competitors, cause customer and employee concerns, result in the loss of potential business opportunities, or make it more difficult to attract and retain qualified personnel. Such perceived uncertainties could negatively affect the trading price and volatility of our common stock.

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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;

• uncertain impact of regulatory changes arising from an exit from the E.U.;

• 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.

We and Ensco will be subject to various uncertainties and contractual restrictions while the Transaction is pending that could adversely affect each party's business and operations.

In connection with the proposed Transaction, it is possible that some customers, suppliers and other persons with whom we or Ensco have business relationships may delay or defer certain business decisions, or might decide to seek to terminate, change or renegotiate their relationship with us or Ensco as a result of the Transaction, which could negatively affect our or Ensco’s respective financial positions, operating results or cash flows, as well as the market price of our shares and Ensco’s shares, regardless of whether the Transaction is completed.

Under the terms of the Transaction Agreement, we and Ensco are subject to certain restrictions on the conduct of our businesses prior to completing the Transaction, which may adversely affect our and Ensco’s ability to execute certain business strategies. Such limitations could negatively affect each party’s businesses and operations prior to the completion of the Transaction. Furthermore, the process of planning to integrate two businesses and organizations for the post-transaction period may divert management’s attention and resources and could ultimately have an adverse effect on each party. These uncertainties could cause customers, suppliers and others that deal with us or Ensco to seek to change existing business relationships with such party, which in turn could have an adverse effect on the combined company’s ability to realize the anticipated benefits of the Transaction.

We or Ensco may have difficulty attracting, motivating and retaining executives and other employees in light of the Transaction.

Uncertainty about the effect of the Transaction on our employees or Ensco’s employees may impair the companies' ability to attract, retain and motivate personnel until the Transaction is completed. Employee retention may be particularly challenging during the pendency of the Transaction, as employees may feel uncertain about their future roles with the combined organization. In addition, we or Ensco may have to provide additional compensation in order to retain employees. If our employees or Ensco’s employees depart because of issues relating to the uncertainty and difficulty of integration or a desire not to become employees of the combined company, the combined company’s ability to realize the anticipated benefits of the Transaction could be adversely affected.

The Transaction is subject to conditions, including certain conditions that may not be satisfied, and may not be completed on a timely basis, if at all. Failure to complete the Transaction, or significant delays in completing the Transaction, could negatively affect the trading price of our shares and our future business and financial results.

The completion of the Transaction is subject to a number of conditions beyond our and Ensco’s control that may prevent, delay or otherwise materially adversely affect its completion, including the approval of governmental agencies. Neither we nor Ensco can predict whether and when these other conditions will be satisfied.

If the Transaction is not completed, we will be subject to several risks and consequences, including the following:

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• certain damages for which we may be liable to Ensco under the terms and conditions of the Transaction Agreement;

• negative reactions from the financial markets, including declines in the price of our shares due to the fact that current prices may reflect a market assumption that the Transaction will be completed;

• certain significant costs relating to the Transaction, including, in certain circumstances, the payment by us of $15 million for Ensco’s expenses and a termination fee payable by us of $24 million less any previous expense reimbursements; and

• diverted attention of our management to the Transaction rather than our own operations and pursuit of other opportunities that could have been beneficial to us.

We and Ensco will incur substantial transaction fees and costs in connection with the Transaction.

We and Ensco expect to incur a number of non-recurring transaction-related costs associated with completing the Transaction, combining the operations of the two organizations and achieving desired synergies. These fees and costs will be substantial. Non-recurring transaction costs include, but are not limited to, fees paid to legal, financial, accounting and other advisors, retention, severance and other integration-related costs, filing fees and printing costs. Additional unanticipated costs may be incurred in the integration of our business and Ensco’s business. There can be no assurance that the elimination of certain duplicative costs, as well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction-related costs over time. Thus, any net benefit may not be achieved in the near term, the long term or at all.

If completed, the Transaction may not achieve its intended results, and we and Ensco may be unable to successfully integrate our operations. Failure to successfully combine our business and Ensco’s business in the expected time frame may adversely affect the future results of the combined organization and, consequently, the value of Ensco's shares that our shareholders receive as the Transaction consideration.

We and Ensco entered into the Transaction Agreement with the expectation that the Transaction will result in various benefits, including, among other things, expanding our geographic presence and customer base and creating synergies. Achieving the anticipated benefits of the Transaction is subject to a number of uncertainties, including whether the businesses of us and Ensco can be integrated in an efficient and effective manner. Because our shares are being exchanged for Ensco's shares in the Transaction, our stock price may be adversely affected by a decline in Ensco's stock price and any adverse developments in

Ensco's business, either of which may result from a variety of factors beyond our control.

It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of each company's ongoing businesses, processes and systems or inconsistencies in standards, controls, procedures, practices, policies and compensation arrangements, any of which could adversely affect the combined company's ability to achieve the anticipated benefits of the Transaction. The combined company's results of operations could also be adversely affected by any issues attributable to either company's operations that arise or are based on events or actions that occur prior to the completion of the Transaction. The companies may have difficulty addressing possible differences in corporate cultures and management philosophies. The integration process is subject to a number of uncertainties, and no assurance can be given that the anticipated benefits will be realized or, if realized, the timing of their realization. Failure to achieve these anticipated benefits could result in increased costs or decreases in the amount of expected revenues and could adversely affect the combined company's future business, financial condition, operating results and cash flows.

A downgrade in our or our subsidiaries’ credit ratings following the Transaction could impact the combined entity’s access to capital and cost of doing business.

Following the Transaction, rating agencies may re-evaluate our and our subsidiaries’ ratings, and any additional actual or anticipated downgrades in such credit ratings could limit our ability to access credit and capital markets, or to restructure or refinance our indebtedness. As a result of any such downgrades, future financings or refinancings may result in higher borrowing costs and require more restrictive terms and covenants, including obligations to post collateral with third parties, which may further restrict operations and negatively impact liquidity.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

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Completion of the Transaction will trigger change of control or other provisions in certain agreements to which we are a party.

The completion of the Transaction will trigger change of control or other provisions in certain agreements to which we are a party. In particular, pursuant to the indenture governing the 2025 Notes, the combined company will be required to make an offer to purchase all of each holder’s notes at an amount equal to 101% of the aggregate principal amount of such holder’s notes, plus accrued and unpaid interest, if any, if there is a ratings downgrade by both Moody’s Investors Service, Inc. ("Moody's") and S&P Global Rating ("S&P") between the public notice of the Transaction and 60 days after the consummation of the Transaction (or any extended period if either Moody's or S&P publicly announces a possible downgrade). As a result, the combined company could be required to repay up to an aggregate $500 million principal amount of senior notes plus approximately $5 million in associated premiums.

In addition, the completion of the Transaction will constitute a change of control under the Existing Credit Facility and the New Credit Facility. As a result, the commitments will be terminated and the outstanding balances under each of the Existing Credit Facility and the New Credit Facility will be accelerated and become due and payable by us in connection with the completion of the Transaction. As of December 31, 2018, we had no outstanding borrowings under either the Existing Credit Facility and the New Credit Facility.

If a governmental authority asserts objections to the Transaction, we and Ensco may be unable to complete the Transaction or, in order to do so, we and Ensco may be required to comply with material restrictions or satisfy material conditions.

The completion of the Transaction is subject to the condition that there is no order, injunction, decree or other legal restraint by a governmental authority in effect restraining, preventing or prohibiting the Transaction contemplated by the Transaction Agreement. If a governmental authority asserts objections to the Transaction, we or Ensco may be required to divest assets or accept other remedies in order to complete the Transaction. There can be no assurance as to the cost, scope or impact of the actions that may be required to address any governmental authority objections to the Transaction. If we or Ensco takes such actions, it could be detrimental to us or to the combined company following the consummation of the Transaction. Furthermore, these actions could have the effect of delaying or preventing completion of the Transaction or imposing additional costs on or limiting the operating results or cash flows of the combined company following the consummation of the Transaction.

In addition, in some circumstances, a third party could initiate a private action under antitrust laws challenging or seeking to enjoin the Transaction, before or after it is completed. We or Ensco may not prevail and may incur significant costs in defending or settling any action under the antitrust laws.

The Transaction may be completed even though material adverse changes subsequent to the announcement of the Transaction, such as industry-wide changes or other events, may occur.

In general, either party can refuse to complete the Transaction if there is a material adverse change affecting the other party. However, some types of changes do not permit either party to refuse to complete the Transaction, even if such changes would have a material adverse effect on either of the parties. For example, a worsening of our or Ensco’s financial condition or results of operations due to a decrease in commodity prices or general economic conditions would not give the other party the right to refuse to complete the Transaction. If adverse changes occur that affect either party but the parties are still required to complete the Transaction, our share price, business and financial results after the Transaction may suffer.

ITEM 1B. UNRESOLVED STAFF COMMENTS

The Company has no unresolved SEC staff comments.

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ITEM 2. PROPERTIES

Our primary U.S. offices are located in 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, Malaysia, Singapore, Mexico and Turkey.

Drilling Rigs

Following is the principal drilling equipment owned by Rowan and its location at February 13, 2019.

		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	Mexico
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	Turkey
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	US GOM
Rowan Mississippi(1) (5)	240C	375	35,000	2008	Saudi Arabia
Rowan EXL IV (1) (5)	EXL	320	35,000	2011	Saudi Arabia
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) (5)	EXL	350	35,000	2010	Saudi Arabia
Bess Brants (2) (4) (5)	Super 116E	350	30,000	2013	Bahrain
Earnest Dees (2) (4) (5)	Super 116E	350	30,000	2013	Bahrain
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 premium rigs that also have a 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)    Leased to ARO

(6)    Water depths are the maximum "rated" depths as currently outfitted.

(7)    Maximum estimated drilling depth, subject to well characteristics and rig outfitting.

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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 STOCKHOLDERMATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES

Our shares are listed on the NYSE under the symbol “RDC”. 

On February 21, 2019, there were 82 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.

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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, 2018, assuming reinvestment of dividends.

	12/31/2013	12/31/2014	12/31/2015	12/31/2016	12/31/2017	12/31/2018
Rowan	100.00	66.67	49.42	55.08	45.66	24.46
S&P 500 Index	100.00	113.69	115.26	129.05	157.22	150.33
Dow Jones US Oil Equipment & Services Index	100.00	82.78	64.17	81.70	68.05	39.22

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Issuer Purchases of Equity Securities

The following table presents information with respect to acquisitions of our shares for the fourth quarter of 2018:

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, 2018	348	$	18.68	—	$	—
November 1 - 30, 2018	37	$	16.05	—	$	—
December 1 - 31, 2018	141,443	$	8.97	—	$	—
Total	141,828	$	8.99	—
(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 2018.
(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 provides that share repurchases may only be made out of distributable reserves. At our 2018 general meeting of shareholders on May 24, 2018, our shareholders approved new repurchase agreements and counterparties, which approval will remain valid until May of 2023. 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, 2018.

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.

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ITEM 6.  SELECTED FINANCIAL DATA

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

	2018			2017			2016			2015			2014
	(Dollars in millions, except per share amounts)
Operations
Revenue	$	824.8		$	1,282.8		$	1,843.2		$	2,137.0		$	1,824.4
Costs and expenses:
Direct operating costs (excluding items shown below)	682.7			685.0			779.7			980.2			982.8
Depreciation and amortization	388.9			403.7			402.9			391.4			322.6
Selling, general and administrative	96.1			104.6			102.2			114.3			125.1
Gain on sale of assets to unconsolidated subsidiary (1)	(65.8		)	(157.4		)	—			—			—
(Gain) loss on disposals of property and equipment	12.1			9.4			8.7			(7.7		)	(1.7		)
Gain on litigation settlement (2)	—			—			—			—			(20.9		)
Merger and related costs	8.9			—			—			—			—
Material charges and other operating items (3)	—			—			32.9			337.3			574.0
Total costs and expenses	1,122.9			1,045.3			1,326.4			1,815.5			1,981.9
Equity in earnings of unconsolidated subsidiary	10.3			0.9			—			—			—
Income (loss) from operations	(287.8		)	238.4			516.8			321.5			(157.5		)
Other (expense) — net (4)	(111.2		)	(139.1		)	(191.2		)	(163.8		)	(112.1		)
Income (loss) from continuing operations before income taxes	(399.0		)	99.3			325.6			157.7			(269.6		)
Provision (benefit) for income taxes	(51.6		)	26.6			5.0			64.4			(150.7		)
Income (loss) from continuing operations	(347.4		)	72.7			320.6			93.3			(118.9		)
Discontinued operations, net of taxes (5)	—			—			—			—			4.0
Net income (loss)	$	(347.4	)	$	72.7		$	320.6		$	93.3		$	(114.9	)
Basic income (loss) per common share:
Income (loss) from continuing operations	$	(2.74	)	$	0.58		$	2.56		$	0.75		$	(0.96	)
Income (loss) from discontinued operations	—			—			—			—			0.03
Net income (loss)	$	(2.74	)	$	0.58		$	2.56		$	0.75		$	(0.93	)
Diluted income (loss) per common share:
Income (loss) from continuing operations	$	(2.74	)	$	0.57		$	2.55		$	0.75		$	(0.96	)
Income (loss) from discontinued operations	—			—			—			—			0.03
Net income (loss)	$	(2.74	)	$	0.57		$	2.55		$	0.75		$	(0.93	)
Financial Position
Cash and cash equivalents	$	1,026.7		$	1,332.1		$	1,255.5		$	484.2		$	339.2
Property and equipment — net	$	6,201.0		$	6,552.7		$	7,060.0		$	7,405.8		$	7,432.2
Total assets	$	8,117.7		$	8,458.3		$	8,675.6		$	8,347.3		$	8,392.3
Current portion of long-term debt	$	201.2		$	—		$	126.8		$	—		$	—
Long-term debt, less current portion	$	2,309.7		$	2,510.3		$	2,553.4		$	2,692.4		$	2,788.5
Shareholders’ equity (6)	$	5,035.0		$	5,386.1		$	5,113.9		$	4,772.5		$	4,691.4
Statistical Information
Current ratio (7)	2.87			6.06			3.27			2.80			2.82
Debt to capitalization ratio	33		%	32		%	34		%	36		%	37		%
Book value per share of common stock outstanding	$	39.62		$	42.66		$	40.76		$	38.24		$	37.66
Price range of common stock:
High	$	20.70		$	20.50		$	21.68		$	25.13		$	35.17
Low	$	7.97		$	9.02		$	10.67		$	14.63		$	19.50
Cash dividends declared per share	$	—		$	—		$	—		$	0.40		$	0.30

___________________

(1) In 2018 and 2017, the Company recognized a $65.8 million and 157.4 million gain, respectively, 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 millionadjustment 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; and 2014 – $574.0 million of non-cash asset impairment charges.

(4) In 2016, other income (expense), net includes a $31.2 million loss on debt extinguishment.

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(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) 2018 includes (i) a $5.5 million increase to Retained earnings related to the adoption of ASU No. 2014-09 and (ii) a $45.6 million increase to Retained earnings as a reclassification from Accumulated other comprehensive income related to the adoption of ASU No. 2018-02. 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 ANDRESULTS OF OPERATIONS

OUR BUSINESS

We are a global provider of offshore contract drilling services to the oil and gas industry, with a focus on ultra-deepwater drillships and high specification and premium jack-up rigs. Many of our high specification jack-up rigs are also rated for operating in harsh environments. Our fleet operates worldwide, including the US GOM, Mexico, Central and South America, the U.K. and Norwegian sectors of the North Sea, the Middle East and the Mediterranean Sea. We currently operate in three segments: Deepwater, Jack-ups and ARO, our 50/50 joint venture with Saudi Aramco. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 21 self-elevating jack-up rigs and includes the impact of the various arrangements with ARO (see Note 1 and 4 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for more information. The information discussed therein is incorporated by reference into this Part II, Item 7). ARO currently owns a fleet of seven self-elevating jack-up rigs for operation in the Arabian Gulf for Saudi Aramco. ARO has plans to order up to 20 new jack-up rigs over the next 10 years.

As of February 13, 2019, the date of our most recent Fleet Status Report, two of our four drillships were contracted in the US GOM, one was contracted in Mexico and the remaining drillship was marketed without a contract in the US GOM. For our jack-up fleet, we had four rigs under contract in the North Sea, one rig under contract in the Mediterranean Sea, three under contract in Central and South America and two under contract in the US GOM. In the Middle East, we had nine jack-ups leased to ARO to fulfill nine, three-year contracts between Saudi Aramco and ARO, two of which are expected to commence in the first half of 2019. Additionally, we own two jack-up rigs which are cold stacked.

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. Rigs leased to ARO are through bareboat charter agreements whereby substantially all operating costs will be borne by ARO. ARO will contract with the customer, Saudi Aramco, and directly receive related revenue.

Unless the context otherwise requires, the terms "Rowan", Rowan plc", "Company", "we", "us" and "our" are used to refer to Rowan plc and its consolidated subsidiaries. For Rowan plc and its consolidated subsidiaries, intercompany balances and transactions have been eliminated in consolidation.

For information with respect to our revenue and long-lived assets by geographic area, see Note 14 to our consolidated financial statements in Part II, Item 8 of this Annual Report.

Proposed Combination of Rowan Companies plc and Ensco plc

On October 7, 2018, the Company entered into a Transaction Agreement with Ensco plc to effect a "merger-of-equals" transaction (see discussion in "Proposed Combination of Rowan Companies plc and Ensco plc" included in Part I, Item 1. Business of this Annual Report for more information. The information discussed therein is incorporated by reference into this Part II, Item 7).

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 and Note 4 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information.

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Gain on sale of assets to unconsolidated subsidiary

Effective October 1, 2018, we sold the Scooter Yeargain and the Hank Boswell to ARO for total cash consideration of $266.0 million. The book value of these rigs was approximately $200.2 million. As a result of this sale transaction with ARO, we recognized a gain on the disposal of rigs in the amount of $65.8 million in 2018.

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 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, 4 and 15 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information.

Anadarko Early Termination Revenue

During the second quarter of 2018, we recognized $27.8 million of revenue related to an early termination fee from Anadarko Petroleum Corporation (“Anadarko”) pursuant to our drilling contract for the drillship RowanResolute (the “Anadarko Contract”). Termination of the Anadarko Contract became effective on June 1, 2018, and the early termination fee was a lump sum payment for the remainder of the term of the Anadarko Contract, originally scheduled to terminate on August 6, 2018, at a rate of $418,400 per day.

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 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report 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 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information.

CURRENT BUSINESS ENVIRONMENT

Since the industry downturn in late 2014, the cancellation and postponement of drilling programs have resulted in significantly reduced demand for offshore drilling services globally and sharply lower day rates on newly executed contracts. The offshore rig supply and demand imbalance was further exacerbated by the delivery of 263 new jack-ups and 165 new floaters since the beginning of the most recent newbuild cycle, which started in early 2006. As of February 13, 2019, we believe that there remained approximately 77 additional jack-up rigs on order or under construction worldwide for delivery through 2021 (relative to approximately 311 jack-up rigs currently on contract), and 31 floaters on order or under construction worldwide for delivery through 2021 (relative to approximately 125 floater rigs currently on contract). To our knowledge, only one of the jack-up newbuilds has a contract in place and only one floater newbuild has a future contract executed. We expect delivery for many of the newbuilds to be deferred until a recovery in demand is more visible, and some rigs under construction may eventually be cancelled.

Drilling contractors have responded to the downturn by retiring assets, stacking certain idle equipment and deferring newbuild deliveries. Since the beginning of 2014, we estimate that approximately 89 jack-ups and 123 floaters have been removed from the total fleet in various forms of attrition. We have 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 during this period. Of these rigs that were once warm stacked, all but one, a drillship, have been put back to work and are currently contracted but at reduced dayrates. We have reduced day rates on certain drilling contracts, some in exchange for extended contract duration, agreed to certain contract terminations, and taken aggressive steps to reduce operating and support costs. We have also formed ARO, our joint venture with Saudi Aramco, to enhance our long-term competitive position with the world's largest user of jack-up rigs.

Overall utilization for marketed jack-ups has improved by over 10% since early 2017. Marketed utilization for drillships stabilized during much of 2018 and showed signs of improvement during the fourth quarter 2018. The general improvement in crude oil prices since mid-2017, albeit with a decline in the fourth quarter of 2018, combined with customers substantially lowering their break-even costs, has also led to a more favorable backdrop for drilling activity. Demand for jack-ups has increased fairly steadily over this period, and the improvement has particularly favored certain regions such as those with harsh environment conditions where there are fewer capable units. Industry demand for drillships shows recent signs of improvement although mostly for short

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term programs at dayrates that are still near historic lows, especially for near-term commencements. We expect any material improvement in dayrates for drillships will be delayed until a greater percentage of the remaining idle drillship capacity is utilized. By mid-2018, we concluded work on all of our legacy drillship contracts, which were signed at the prior peak of the market cycle, and looking forward, we expect our drillship contracts will be more in-line with current market rates. Our recent success at contracting three of our drillships, albeit for short-term work, in part reflects the general increase in tendering activity and the high quality of our rigs and strong operating performance.

While we have seen some recent improvement in contract awards, given the current offshore rig supply and demand dynamics, we expect the marketing environment to remain competitive across the broad offshore rig market 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 continue improving in advance of the floater market.

As the market stabilizes and improves, 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 active high-specification jack-ups and state-of-the-art ultra-deepwater drillships. We continue to focus on securing backlog, operating efficiency, cost reduction initiatives, and upgrading various systems and data analytics to drive improved drilling performance and predictive maintenance.

BACKLOG

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

	February 13, 2019
	Jack-ups (1) (2)		Deepwater		Total
US GOM	$	11.7	$	79.9	$	91.6
Mexico	—		18.3		18.3
Middle East (1) (2)	265.5		—		265.5
North Sea	184.1		—		184.1
Mediterranean Sea	10.8		—		10.8
Central and South America	64.6		—		64.6
Total backlog	$	536.7	$	98.2	$	634.9
(1) Excludes ARO's revenue backlog.
(2) The total estimated revenue backlog includes $265.5 million of estimated bareboat charter and lease related revenue for nine jack-ups leased to ARO to fulfill contracts between ARO and Saudi Aramco. Substantially all the operating costs for jack-ups leased to ARO through bareboat charter agreements will be borne by ARO.

We estimate our backlog as of February 13, 2019, will be realized as follows (in millions):

Year Ended:	Jack-ups(1) (2)		Deepwater		Total
2019	$	297.8	$	87.6	$	385.4
2020	159.2		10.6		169.8
2021	79.7		—		79.7
2022	—		—		—
2023 and later years	—		—		—
Total backlog	$	536.7	$	98.2	$	634.9
(1) Excludes ARO's revenue backlog.
(2) The total estimated revenue backlog includes $265.5 million of estimated bareboat charter and lease related revenue for nine jack-ups leased to ARO to fulfill contracts between ARO and Saudi Aramco. Substantially all the operating costs for jack-ups leased to ARO through bareboat charter agreements will be borne by ARO.

Our contract backlog represents remaining contractual terms and may not reflect actual revenue due to renegotiations or a number of factors such as rig downtime, out of service time, estimated contract durations, changes in exchange rates for the non-U.S. dollar portion of day rates (the table above is based on rates as of February 13, 2019), contingent demobilization revenue, customer concessions or contract cancellations.

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About 73% of our remaining available rig days in 2019, 44% of available rig days in 2020 and 29% of available rig days in 2021, are included in backlog as revenue producing days as of February 13, 2019, excluding cold-stacked rigs. As of that date, we had two jack-ups that were cold stacked, and one drillship that was marketed without a contract.

Since 2014, we have recognized asset impairment charges on several of our jack-up drilling units as a result of the decline in market conditions and the expectation of future demand and day rates. If our assumptions adversely change, we could be required to recognize additional impairment charges in future periods.

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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 14 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report.

The following table presents certain key performance indicators by rig classification⁽¹⁰⁾:

	Years ended December 31,
	2018			2017			2016
Revenue (in millions):
Deepwater
Day rate revenue	$	155.4		$	465.7		$	824.7
Rebillable revenue (1)	2.7			2.2			2.8
Total Deepwater	$	158.1		$	467.9		$	827.5
Jack-ups
Day rate revenue (2)	$	556.1		$	784.7		$	994.7
Secondment revenue (1)	55.9			9.2			—
Rebillable revenue (1)	15.0			12.0			18.1
Miscellaneous revenue (1)	5.9			1.6			2.9
Total Jack-ups	$	632.9		$	807.5		$	1,015.7
Unallocated
Transition services revenue (1)	$	33.8		$	7.4		$	—
Total revenue	$	824.8		$	1,282.8		$	1,843.2
Revenue-producing days:
Deepwater (3)	442			783			1,238
Jack-ups (4)	4,844			6,144			5,999
Total revenue-producing days (3) (4)	5,286			6,927			7,237
Available days: (5)
Deepwater	1,460			1,460			1,464
Jack-ups	6,751			8,162			8,784
Total available days	8,211			9,622			10,248
Average day rate (in thousands): (6)
Deepwater (3) (7) (8)	$	351.2		$	594.8		$	550.7
Jack-ups	$	114.8		$	127.7		$	165.8
Total fleet (3) (7) (8)	$	134.6		$	180.5		$	231.7
Utilization: (9)
Deepwater (3)	30		%	54		%	85		%
Jack-ups	72		%	75		%	68		%
Total fleet (3)	64		%	72		%	71		%
(1) Rebillable, secondment, miscellaneous and transition services revenue are excluded from the computation of average day rate.
(2) Dayrate revenue includes Bareboat Charter lease and related revenue from ARO of $24.4 million for the year ended December 31, 2018.
(3) 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 the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report). 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.
(4) For rigs leased to ARO, revenue-producing days includes the number of days on hire under Bareboat Charter lease to ARO.

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⁽⁵⁾ 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. In the case of rigs leased to ARO, the number of available days is based on the number of days available for hire under the Bareboat Charter lease to ARO.

⁽⁶⁾ 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, Bareboat Charter lease revenue from ARO and amounts received, such as for rig mobilization, unconstrained demobilization or capital improvements, which are amortized over the expected recognition period of the contract. Revenue attributable to reimbursable expenses is excluded from average day rates.

⁽⁷⁾ For the year ended December 31, 2018, revenue for this calculation includes $27.8 million related to the Anadarko early contract termination fee to which there are no associated revenue-producing days.

⁽⁸⁾ Average day rate for 2016 includes operating days for the Rowan Relentless up to the contract termination, which was 143 days for 2016.

⁽⁹⁾ Utilization is the number of revenue-producing days, including fractional days, divided by the number of available days. For rigs leased to ARO, utilization includes the number of days on hire under Bareboat Charter to ARO divided by the number of available days.

⁽¹⁰⁾ All revenue and KPIs exclude the results from rigs owned by ARO beginning on October 17, 2017, and October 1, 2018, the dates such rigs were sold to ARO.

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 days:

	Years ended December 31,
	2018		2017		2016
Deepwater:
Idle (1)	67.5	%	46.4	%	15.2	%
Out-of-service (2)	1.4	%	—	%	0.1	%
Operational downtime (3)	2.6	%	—	%	0.1	%
Jack-up:
Idle (1)	16.1	%	15.7	%	25.4	%
Out-of-service (2)	11.0	%	8.1	%	5.3	%
Operational downtime (3)	1.6	%	1.3	%	1.4	%
(1) Idle Days – Days 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 – 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 expected recognition period for the drilling contract.
(3) Operational Downtime – 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, and October 1, 2018, the dates such rigs were sold to ARO.

35

2018 Compared to 2017

A summary of our consolidated results of operations follows (in millions):

	Year ended December 31,
	2018			2017			Change			% Change
Deepwater:
Revenue	$	158.1		$	467.9		$	(309.8	)	(66	)%
Operating expenses:
Direct operating costs (excluding items below)	168.6			151.4			17.2			11	%
Depreciation and amortization	108.5			111.6			(3.1		)	(3	)%
Other operating items - expense	1.6			0.1			1.5			n/m
Income (loss) from operations	$	(120.6	)	$	204.8		$	(325.4	)	n/m
Jack-ups:
Revenue	$	632.9		$	807.5		$	(174.6	)	(22	)%
Operating expenses:
Direct operating costs (excluding items below)	514.1			533.6			(19.5		)	(4	)%
Depreciation and amortization	278.3			289.4			(11.1		)	(4	)%
Gain on sale of assets to unconsolidated subsidiary	(65.8		)	(157.4		)	91.6			n/m
Other operating items - expense	5.3			9.3			(4.0		)	n/m
Income (loss) from operations	$	(99.0	)	$	132.6		$	(231.6	)	n/m
ARO:
Revenue	$	348.8		$	48.6		$	300.2		n/m
Operating expenses:
Direct operating costs (excluding items below)	194.0			22.2			171.8			n/m
Depreciation and amortization	67.4			12.9			54.5			n/m
Selling, general and administrative	27.0			6.1			20.9			n/m
Other operating items - (income) expense	1.4			(0.1		)	1.5			n/m
Income from operations	$	59.0		$	7.5		$	51.5		n/m
Unallocated and other:
Revenue	$	33.8		$	7.4		$	26.4		n/m
Operating expenses:
Depreciation and amortization	2.1			2.7			(0.6		)	(22	)%
Selling, general and administrative	96.1			104.6			(8.5		)	(8	)%
Other operating items - expense	5.2			—			5.2			n/m
Merger and related costs	8.9			—			8.9			n/m
Loss from operations	$	(78.5	)	$	(99.9	)	$	21.4		(21	)%
“n/m” - not meaningful.

36

	Year ended December 31,
	2018			2017			Change			% Change
Reportable segments total:
Revenue	$	1,173.6		$	1,331.4
Operating expenses:
Direct operating costs (excluding items below)	876.7			707.2
Depreciation and amortization	456.3			416.6
Selling, general and administrative	123.1			110.7
Gain on sale of assets to unconsolidated subsidiary	(65.8		)	(157.4		)
Other operating items - expense	13.5			9.3
Merger and related costs	8.9			—
Income (loss) from operations	$	(239.1	)	$	245.0
Eliminations and adjustments:
Revenue	$	(348.8	)	$	(48.6	)
Operating expenses:
Direct operating costs (excluding items below)	(194.0		)	(22.2		)
Depreciation and amortization	(67.4		)	(12.9		)
Selling, general and administrative	(27.0		)	(6.1		)
Other operating items - income (expense)	(1.4		)	0.1
Equity in earnings of unconsolidated subsidiary	10.3			0.9
Loss from operations	$	(48.7	)	$	(6.6	)
Total company:
Revenue	$	824.8		$	1,282.8		$	(458.0	)	(36	)%
Direct operating costs (excluding items below)	682.7			685.0			(2.3		)	—	%
Depreciation and amortization	388.9			403.7			(14.8		)	(4	)%
Selling, general and administrative	96.1			104.6			(8.5		)	(8	)%
Gain on sale of assets to unconsolidated subsidiary	(65.8		)	(157.4		)	91.6			n/m
Other operating items - expense	12.1			9.4			2.7			n/m
Merger and related costs	8.9			—			8.9			n/m
Equity in earnings of unconsolidated subsidiary	10.3			0.9			9.4			n/m
Income (loss) from operations	$	(287.8	)	$	238.4		$	(526.2	)	n/m
Other (expense), net	(111.2		)	(139.1		)	27.9			(20	)%
Income (loss) before income taxes	(399.0		)	99.3			(498.3		)	n/m
Provision (benefit) for income taxes	(51.6		)	26.6			(78.2		)	n/m
Net Income (loss)	$	(347.4	)	$	72.7		$	(420.1	)	n/m
“n/m” - not meaningful.

37

Revenue

Consolidated. The decrease in consolidated revenue is described below.

Deepwater. The net changes in revenue for 2018, compared to 2017, are set forth below (in millions):

	Increase (decrease)
Fewer revenue-producing days	$	(224.6	)
Lower average drillship day rates	(84.9		)
Rowan Reliance acceleration (1)	(28.6		)
Rowan Resolute-Anadarko early contract termination fee	27.8
Higher reimbursable revenue	0.5
Decrease	$	(309.8	)
(1) 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.

Jack-ups. The net changes in revenue for 2018, compared to 2017, are set forth below (in millions):

	Increase (decrease)
ARO related - decrease due to sale of assets to ARO	$	(99.3	)
ARO related - increase in ARO related secondment reimbursables	46.7
ARO related - increase due to idle rigs leased to ARO	3.5
Lower average jack-up day rates (1)	(51.3		)
Fewer revenue-producing days	(81.5		)
Higher other revenue	7.3
Decrease	$	(174.6	)
(1) The decrease is primarily due to five of the jack-ups leased to ARO through Bareboat Charters a portion of the year ended December 31, 2018, whereby substantially all operating costs will be borne by ARO. This is compared to those five jack-ups being contracted directly to Saudi Aramco for a dayrate during the comparable period, whereby all of the operating costs were borne by the Company. The reduction in rate (Bareboat Charter rate compared to Dayrate) contributed to a decrease in Revenue of approximately $42.3 million. Additionally, the EXL IV and EXL I were leased to ARO through Bareboat Charters, but were idle during 2017. These rigs contributed $3.5 million in revenue in 2018.

Unallocated. Revenue related to transition services provided to ARO increased as a result of ARO operating a full year in 2018 compared to commencing operations on October 17, 2017 for the comparable period (see Note 1 and Note 4 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report).

Direct operating costs

Consolidated. The decrease in consolidated direct operating costs is described below.

Deepwater. The net changes in direct operating costs for 2018, compared to 2017, are set forth below (in millions):

	Increase (decrease)
Increase in drillship direct operating expenses (1)	$	33.8
Higher reimbursable costs	0.5
Decrease due to idle drillships	(15.0		)
Reduction in shorebase costs and other	(2.1		)
Increase	$	17.2
(1) Primarily due to ramp up and non-recoverable preparation costs.

38

Jack-ups. The net changes in direct operating costs for 2018, compared to 2017, are set forth below (in millions):

	Increase (decrease)
ARO related - decrease due to sale of assets to ARO	$	(62.3	)
ARO related - decrease due to rigs leased to ARO	(24.3		)
ARO related - increase to secondment reimbursable costs	46.7
ARO related - management fee	25.7
Decrease due to idle or cold-stacked rigs	(18.9		)
Reduction in shorebase costs and other	(18.5		)
Ramp up costs, non-recoverable preparation costs, repairs and maintenance expenses for Bess Brants, Earnest Dees, EXL I and EXL IV for lease to ARO	24.7
Increase in jack-up direct operating expense	4.4
Higher reimbursable costs	3.0
Decrease	$	(19.5	)

Selling, General and Administrative

The decrease in Selling, general and administrative expenses was primarily due to lower personnel costs.

Gain on sale of assets to unconsolidated subsidiary

We recognized a gain of $65.8 million and $157.4 million in 2018 and 2017, respectively, on the sale of assets to ARO. See Notes 1, 4 and 15 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information.

Merger and related costs

We recognized $8.9 million of expense, primarily legal and other professional service fees, related to our proposed merger with Ensco.

Other operating items

In 2018, we had a loss on disposals of property and equipment of $12.1 million compared to a loss of $9.4 million in 2017.

Equity in earnings of unconsolidated subsidiary

Equity in earnings of unconsolidated subsidiary increased largely as a result of ARO operating a full year in 2018 compared to commencing operations on October 17, 2017, for the comparable period.

Other expense, net

The decrease in Other expense, net, is primarily due to the following:

• $10.8 million increase in interest income from ARO note receivable primarily due to balances outstanding a full year in 2018 compared to a partial year in 2017, the period from October 17, 2017 to December 31, 2017, (see Note 4 of the "Consolidated Financial Statements" in Part II, Item 8 of this Annual Report for additional information);

• $6.9 million increase in interest income on cash balances due to higher interest rates.

• Benefit of $15.2 million in 2018 from pension and other postretirement benefit plans net periodic cost, exclusive of service cost compared to an expense of $0.1 million in 2017. The benefit in 2018 was primarily due to a pension plan curtailment gain of $11.4 million in the second quarter of 2018. The 2017 period included a $5.8 million settlement loss related to an annuity purchase.

Partially offsetting these items,

• Increase in net foreign currency exchange losses of $3.0 million; and

• Gain on the early extinguishment of debt in 2017 of $1.7 million.

39

Provision (benefit) for income taxes

In 2018, we recognized an income tax benefit of $51.6 million on pretax loss of $399.0 million. The 2018 tax benefit primarily includes $68.4 million from the reversal of a valuation allowance on U.S. deferred tax assets, $10.2 million of adjustments for filed tax returns, and $9.3 million reduction in accrued unrecognized tax benefits due to a lapse in statutes of limitation partially offset by $32.4 million of tax expense for current year operations and $2.9 million of additional unrecognized tax benefits related to potential audit settlement and transfer pricing.

In 2017, we recognized an income tax provision of $26.6 million on pretax income of $99.3 million. The 2017 tax provision primarily included $28.7 million of tax expense for 2017 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.

40

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			222.4		(71.0		)	(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		$	490.0	$	(285.2	)	(58	)%
Jack-ups:
Revenue	$	807.5		$	1,015.7	$	(208.2	)	(20	)%
Operating expenses:
Direct operating costs (excluding items below)	533.6			557.3		(23.7		)	(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