UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the year ended December 31, 20142017 |
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| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from __________ to __________ |
Commission File Number: 1-5491
Rowan Companies plc
(Exact name of registrant as specified in its charter)
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| 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:
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| Title of each class | Name of each exchange on which registered |
| Class A ordinary shares, $0.125 par value | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes þ No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No þ
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer” and, “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 $3.9$1.3 billion as of June 30, 2014,2017, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange Composite Tape of $31.93$10.24 per share.
The number of Class A ordinary shares, $0.125 par value, outstanding at January 31, 2015February 21, 2018, excludingwas 126,267,762, which excludes 1,848,973 shares held by the Company'san affiliated employee benefit trust, was 124,569,727.trust.
DOCUMENTS INCORPORATED BY REFERENCE
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| Document | Part of Form 10-K |
Portions of the Proxy Statement for the 20152018 Annual General Meeting of Shareholders | Part III, Items 10-14 |
FORWARD-LOOKING STATEMENTS
Statements contained in this report, including in the documents incorporated by reference herein, that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Forward-looking statements include words or phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “could,” “may,” “might,” “should,” “will,” “forecast,” “potential,” "outlook,"“outlook,” “scheduled,” “predict,” “will be,” “will continue,” “will likely result,” and similar words and specifically include statements regarding expected financial and operating performance; dividend andpayments; share repurchases; growthrepurchases or repayment of debt; business strategies; expected utilization, day rates, revenues,revenue, operating expenses, contract terms, contract backlog and fleet status; benefits of our joint venture with Saudi Aramco; capital expenditures,expenditures; tax rates and positions,positions; impairments; insurance coverages,coverages; access to financing and funding sources;sources, including borrowings under our credit facility; the availability, delivery, mobilization, contract commencement, relocation or other movement of rigs and the timing thereof; future rig construction, (including construction in progress and completion thereof), enhancement, upgrade or repair and costs and timing thereof; the suitability of rigs for future contracts; general market, business and industry conditions, trends and outlook; rig demand; future operations; the impact of increasing regulatory requirements and complexity; expected contributions from our new rigs and our entry into the ultra-deepwater market;requirements; divestiture of selected assets; expense management; the likely outcome of legal proceedings or insurance or other claimsproceedings; the impact of competition and consolidation in the industry; the timing thereof; activity levels in the offshore drilling market;of acquisitions, dispositions and other business transactions; customer drilling programs;financial position; and commodity prices. Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:
prices of oil and natural gas and industry expectations about future prices;
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 rigs and reactivation of rigs;
units;
variable levels of drilling activity and expenditures in the energy industry, whether as a result of actions by OPEC, global capital markets and liquidity, emergence of alternate energy sources, prices of oil and natural gas or otherwise, which may result in decreased demand and/or cause us to idle or stack, sell or scrap additional rigs;
possible termination, suspension, renegotiation or cancellation of drilling permitcontracts (with or without cause) as a result of general and operations delays, moratoria or suspensions, new and future regulatory, legislative or permitting requirements (including requirements related to certification and testingindustry economic conditions, distressed financial condition of blowout preventers and other equipment or otherwise impacting operations), future lease sales, changes in laws, rules and regulations that have or may impose increased financial responsibility, additional oil spill contingency plan requirements and other governmental actions that may result in claims ofour customers, force majeure,mechanical difficulties, delays, labor disturbances, strikes, performance or otherwise adversely affectother reasons; payment or operational delays by our existing drilling contracts;customers; or restructuring or insolvency of significant customers;
changes or delays in actual contract commencement dates, contract option exercises, contract revenue and contract awards;
governmental regulatory, legislativeour ability to enter into, and permitting requirements affectingthe terms of, future drilling operationscontracts for drilling units whose contracts are expiring and drilling units currently idled or compliance obligations in the areas in which our rigs operate;
tax matters, including our effective tax rates, tax positions, results of audits, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;
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 limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to weather conditions, work stoppages or otherwise, and the limited availability or high cost of insurance coverage for certain offshore perils or associated removal of wreckage or debris and other losses;
regulatory, legislative or permitting requirements affecting drilling operations and other compliance obligations in the areas in which our rigs operate;
tax matters, including our effective tax rates, tax positions, results of audits, tax disputes, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;
our ability to realize the expected benefits of our joint venture with Saudi Aramco, including our ability to fund any required capital contributions, and increased risks of concentrated operations in the Middle East;
access to spare parts, equipment and personnel to maintain, upgradeservice and serviceupgrade our fleet;
possible cancellation or suspension of drilling contracts as a result of economic conditions in the industry, force majeure, mechanical difficulties, delays, performance or other reasons;
potential cost overruns and other risks inherent to shipyard rig construction, repair, inspections or enhancement,upgrade of drilling units, unexpected delays in rig and equipment delivery and engineering or design issues, following shipyard delivery,delays in acceptance by our customers, or delays in the dates our rigsdrilling units will enter a shipyard, be transported and delivered, enter service or return to service;
changes or delays in actual contract commencement dates; contract terminations, contract extensions, contract option exercises, contract revenues, contract awards; the termination of contracts or renegotiation of contract terms by customers or payment or operational delays by our customers;
potential cost overruns or delays in delivery of our remaining drillships under construction, including delays in leaving the shipyard, delays or other issues relating to customer acceptance or readiness to drill;
operating hazards, including environmental or other liabilities, risks, expenses or losses, whether related to well-control issues, or stormcollisions, groundings, blowouts, fires, explosions, weather or hurricane delays or damage, losses or liabilities (including wreckage or debris removal), collisions, or otherwise;
our ability to attract and retain highly skilled personnel on commercially reasonable terms, whether due to competition, from other contract drillers,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 armed hostilities or other crises in oil or natural gas producing areas in which we operate, which may result in expropriation, nationalization, confiscation, damage or deprivation of assets, extended business interruptions, suspended operations, or claims by our customerssuspension and/or termination of acontracts and payment disputes based on force majeure situation and payment disputes;events;
cyber-breaches of our corporate or offshore control networks;
terrorism, piracy, cyber-breaches, outbreaks of any diseaseepidemics or epidemic and other related travel restrictions political instability, hostilities, actswhich may result in business interruptions or shortages of war, nationalization, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in any of our areas of operations;
available labor;
the outcome of legal proceedings, or other claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, any purported renegotiation, nullification, cancellation or breach of contracts with customers or other parties, and any failure to negotiate or complete definitive contracts following announcements of receipt of letters of intent;
parties;
potential for additional long-lived 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;
impacts of any global financialvolatility in currency exchange rates and limitations on our ability to use or economic downturn;
convert illiquid currencies;
effects of accounting changes and adoption of accounting policies;
potential return to shareholders in the form of dividends and share repurchases;
costs and uncertainties associated with our redomestication, or changes in laws that could reduce or eliminate the anticipated benefits of the transaction;
potential unplanned expenditures and funding requirements, including investments in pension plans and other benefit plans;
economic volatility and
political, legal and tax uncertainties following the Brexit vote in the U.K. and any subsequent referendum in Scotland to seek independence from the U.K.;
other important factors described from time to time in the reports filed by us with the Securities and Exchange CommissionSEC and the New York Stock Exchange.NYSE.
Should one or more of these risks or uncertainties materialize or should our underlying assumptions prove incorrect, actual results may vary materially from those indicated.
All forward-looking statements contained in this Annual Report on Form 10-K speak only as of the date of this documentreport and are expressly qualified in their entirety by such factors. We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Annual Report on Form 10-K, or to reflect the occurrence of unanticipated events, except as required by applicable law.
Other relevant factors are included in Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K.
GLOSSARY OF TERMS
The following frequently used abbreviations or acronyms are used in this Annual Report on Form 10-K as defined below:
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| 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 |
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| BSEE | | U.S. Bureau of Safety and Environmental Enforcement |
| Cobalt | | Cobalt International Energy, L.P. |
| Company Compensation Committee | | Compensation committee of the board of directors of the Company |
| Directors RSUs | | Directors Deferred Restricted Share Units |
| Directors ND RSUs | | Directors Non-Deferred Restricted Share Units |
| E.U. | | European Union |
| EBT | | Employee benefit trust of the Company |
| Exchange Act | | Securities Exchange Act of 1934 |
| FASB | | Financial Accounting Standards Board |
| FCPA | | U.S. Foreign Corrupt Practices Act |
| FCX | | Freeport-McMoRan Inc. |
| FMOG | | Freeport-McMoRan Oil and Gas LLC |
| HPHT | | High-pressure/high-temperature |
| IMO | | International Maritime Organization |
| IRS | | U.S. Internal Revenue Service |
| MARPOL 73/78 | | International Convention for the Prevention of Pollution from Ships, 1973 as modified by the Protocol of 1978 |
| NOLs | | Net Operating Loss Carryforwards |
| NYSE | | The New York Stock Exchange |
| OPEC | | Organization of Petroleum Exporting Countries |
| P-Units | | Performance Units |
| Plan | | Amended and Restated 2013 Rowan Companies plc Incentive Plan, dated May 25, 2017 |
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| RCI | | Rowan Companies Inc., a subsidiary of the Company |
| Retiree Medical Plan | | Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc. |
| Revolving Credit Facility | | The Company's revolving credit facility, which matures in January 2021 |
| Rowan plc | | Rowan Companies plc |
| Rowan SERP | | Restoration Plan of Rowan Companies, Inc. |
| RSAs | | Restricted Share Awards |
| RSUs | | Restricted Share Units |
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| Abbreviation/Acronym | | Definition |
| SARs | | Share Appreciation Rights |
| Saudi Aramco | | Saudi Arabian Oil Company |
| SEC | | The United States Securities and Exchange Commission |
| SEMS | | Safety and environmental management system |
| Senior Notes | | The 2019 Notes, 2022 Notes, 2024 Notes, 2025 Notes, 2042 Notes and 2044 Notes, collectively |
| Subject Notes | | The 2017 Notes, 2019 Notes, 2022 Notes and the 2024 Notes, collectively |
| TSR | | Total Shareholder Return |
| U.K. | | United Kingdom |
| U.S. | | United States |
| U.S. Tax Act | | 2017 Tax Cuts and Jobs Act |
| UK Bribery Act | | U.K. Bribery Act 2010 |
| US GAAP | | Accounting principles generally accepted in the United States of America |
| US GOM | | United States Gulf of Mexico |
| USD | | U.S. Dollar |
| WTI | | West Texas Intermediate |
PART I
ITEM 1. BUSINESS
Overview
On May 4, 2012, Rowan Companies plc is a public limited company incorporated under the laws of England and Wales (Rowan plc), becameand listed on the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies and our place of incorporation was effectively changed from Delaware to the United Kingdom. We remain subject to the Securities and Exchange Commission (SEC) reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable listing standards of the New York Stock Exchange (NYSE), and we continue to report our consolidated financial results in U.S. dollars and in accordance with United States generally accepted accounting principles (US GAAP). We must also comply with additional reporting requirements under English law.NYSE. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values
of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the terms “Rowan,” “Rowan plc,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-Ksubsidiaries, unless the context otherwise requires. Intercompany balances and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 (the Exchange Act) are made available free of charge on our website at www.rowancompanies.com as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. Information contained on or accessible from our website is not incorporated by reference into this Form 10-K and should not be considered a part of this report or any other filing that we make with the SEC.
Overview
transactions have been eliminated in consolidation.
We are a global provider of offshore contract drilling services to the oil and gas contract drilling services utilizingindustry, with a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, one of which is currently under construction. Prior to 2009, our primary focus had been on high-specification and premium jack-up rigs which our customers use for exploratory and development drillingultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and associated drilling services. In 2009Jack-ups; however, we embarked on a new strategic plan that included divesting non-core assetsnow operate in three segments: Deepwater, Jack-ups and investing in ultra-deepwater assets with a goal of balancing earnings from jack-ups and deepwater rigs over the long term. In 2011 we completed the sales of our manufacturing and land drilling businesses, and in 2011 and 2012 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction ofARO. The Deepwater segment includes four ultra-deepwater drillships. InThe Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2014 we took delivery2018 (see Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the firstvarious arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of these drillships, the this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan Renaissance, which commenced drilling operations in April 2014. The Rowan Resolute was delivered in July 2014 and commenced operations in October 2014. The Rowan Reliance was delivered in November 2014 and commenced operations in February 2015. The Rowan Relentless is scheduledSaudi Aramco that owns a fleet of five self-elevating jack-up rigs for delivery in late March 2015 and expected to commence operationsoperation in the third quarter of 2015. All four drillships are under contract.
We conduct offshore drilling operations in various markets throughout the worldArabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the United States Gulf of Mexico (US GOM), United Kingdom (U.K.)US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East West and North Africa, Southeast Asia and Trinidad. Our revenues
As of February 13, 2018, the date of our most recent Fleet Status Report, one of our four drillships was under contract in the US GOM. We had three jack-up rigs under contract in the North Sea, seven under contract in the Middle East, three under contract in Trinidad and one under contract in the US GOM. Additionally, we had five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our equipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
For information with respect to our revenue, operating income and assets by operating segment, and revenue and long-lived assets by geographic area, are presentedsee Note 13 to our consolidated financial statements in Note 12 of Notes to Consolidated Financial Statements inPart II, Item 8 of this Annual Report on Form 10-K.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. For the year ended December 31, 2014, we generated revenues of $1.8 billionadditional information see "ARO Joint Venture" in Note 1 and an operating loss of $167 million, comparedNote 3 to revenues of $1.6 billion and operating income of $332 millionour consolidated financial statements in 2013. Operating loss for 2014 includes noncash asset impairment charges totaling $574 million. Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” inPart II, Item 78 of this Annual Report on Form 10-K.
The information discussed therein is incorporated by reference into this Part I, Item 1.
Drilling Fleet
Our jack-ups are capable of drilling wells to maximum depths ranging from 25,000 to 40,000 feetWe believe our high-specification and in maximum water depths ranging from 250 to 550 feet, depending on rig sizepremium jack-up fleet and location. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean floor, and the hull is jacked up to the elevation required to drill the well. Our ultra-deepwater drillships are capable of drilling wells to maximum depths of 40,000 feet and in maximum water depths of 12,000 feet.
We have aggressively grown our jack-up fleet in recent years to better serve the needs of the industry and are particularly well positioned to serve the nicheworldwide market, including requirements for high-pressure/high-temperature (HPHT) wells. AllHPHT wells in harsh and benign locations. As of February 13, 2018, our rigs feature top-drive drilling systems, solids-control equipment, AC power and mud pumps that accelerate the drilling process. Our drilling fleet consists of the following:
Four ultra-deepwater drillships;
Three ultra-deepwater drillships delivered in 2014Seventeen high-specification jack-up rigs; and currently operating under contract plus one ultra-deepwater drillship that is currently under construction and scheduled for delivery in late March 2015;
Nineteen high-specification cantileverSix premium jack-up rigs, including one Gorilla class rig, three N-Class rigs, four enhanced Super Gorilla class rigs, four Tarzan Class rigs, three 240C class rigs, and four EXL class rigs, as described below. rigs.
We use the term “high-specification” to describe jack-ups with a hook-load capacity of at least two million pounds.
Eight premium cantilever jack-up rigs, including two Gorilla class rigspounds and six 116-C class rigs. We use the term “premium” to denote independent-leg cantilever jack-ups that can operate in at least 300 feet of water in benign environments.
Three conventional or slot jack-up rigs with skid-off capability, all of which are cold-stacked.
Ultra-Deepwater Drillships –Our ultra-deepwater drillships are self-propelled vessels equipped with computer-controlled dynamic-positioning thruster systems, which allow them to maintain position without anchors through the use ofusing their onboard propulsion and station-keeping systems. Drillships have greater variable deck loading capacity than semisubmersible rigs, enabling them to carry more supplies on board and, thus, making them better suited for drilling in deep water in remote locations. Our drillships are equipped with two drilling stations within a single derrick, allowing the drillships to perform preparatory activities off-line and potentially simultaneous
drilling tasks during some partscertain stages of the well,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 well 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 simultaneous deployment of subsea equipment.equipment simultaneous to drilling station operations. The sum total of these and other advanced features make the drillships very attractive to our customers.
Cantilever jack-ups can extend a portion of the sub-structure containing the drilling equipment over fixed production platforms to perform drilling operations with a minimum of interruption to production. Our conventional jack-ups use “skid-off” technology, which allows the rig floor drilling equipment to be “skidded” out over the top of a fixed platform, enabling these slot type jack-up rigs to be used on drilling assignments that would otherwise require a cantilever jack-up or platform rig.
Jack-up Rigs–Our three Gorilla class rigs, designed in the early 1980s as a heavier-duty class of jack-up rig,jack-ups are capable of operatingdrilling wells to maximum depths ranging from 25,000 to 40,000 feet and in maximum water depths up to 328 feet in extreme hostile environments (winds up to 100 miles per hour and seas up to 90 feet) such as the North Sea. The Rowan Gorilla II and III can drill to 30,000 feet, and the Rowan Gorilla IV is equipped to drill to 35,000 feet.
Three of our four Super Gorilla class rigs were delivered during the periodranging from 1998 to 2002 and are enhanced versions of our Gorilla class rigs that can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water south of the 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents. The Bob Palmer, which was delivered in 2003, is the fourth Super Gorilla class rig, is an enhanced version of the Super Gorilla class jack-up designated a Super Gorilla XL. With713 feet of leg, 139 feet more than the Super Gorillas, and 30 percent larger spud cans, the Bob Palmer can operate in water depths300 to 550 feet, in normally benign environments likedepending on rig size, location and outfitting. All of our high-specification rigs are equipped with or can readily accommodate the US GOMhigh-pressure circulation and pressure control equipment that is necessary for HPHT operations. Each of our jack-ups is designed with a hull that is fully equipped to serve as a drilling platform supported by three independently elevating legs. The rig is towed to the drilling site where the legs are lowered into and penetrate the ocean floor, and the Middle East or inhull raises itself out of the water depths to 400 feet in hostile environments such as the North Sea.
Our four Tarzan Class rigs were delivered during the period from 2004 to 2008 and are specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our three 240C class rigs were designed for HPHT drilling in water depths upthe elevation required to 400 feet with hook-load capacity of 2.5 million pounds. The Rowan Mississippidrill the well using a self-contained rack and the pinion system.Ralph Coffman were added to the fleet in 2008 and 2009, respectively, and the Joe Douglas was added to the fleet in 2011.
Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet with hook-load capacity of two million pounds. The first three EXL class rigs were delivered in 2010, and the Rowan EXL IV was delivered in 2011.
Our three N-Class rigs are capable of drilling upin water depths to 35,000435 feet in harsh environments such as the North Sea and in maximum water depths of approximately 450 feet depending on location.location and outfitting. The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously. Our first
Three of our four N-ClassSuper Gorilla class rigs can be equipped for simultaneous drilling and production operations. They can operate year-round in 400 feet of water in harsh environments such as the North Sea. The Bob Palmer, our fourth Super Gorilla class rig, is an enhanced version of the Super Gorilla class jack-up designated as Super Gorilla XL. The Bob Palmer can operate in water depths up to 550 feet in normally benign environments like the US GOM and the Middle East or in water depths up to 400 feet in harsh environments such as the North Sea.
Our three 240C class rigs were designed for HPHT drilling in water depths up to 400 feet in benign environments, depending on rig size, location and outfitting, and are equipped with a hook-load capacity of 2.5 million pounds. The rigs are also capable of operating in harsh environments at reduced water depths compared to their benign environment ratings.
Our four EXL class rigs enable HPHT drilling in water depths up to 350 feet and are equipped with a hook-load capacity of two million pounds.
We recently purchased two Super 116E class rigs. These are premium rigs capable of drilling in water depths up to 350 feet and are equipped with a hook-load capacity of 1.5 million pounds.
Our two remaining Tarzan Class rigs are specifically designed for deep-well, HPHT drilling in up to 300 feet of water in benign environments.
Our four remaining 116C class rigs are premium rigs capable of operating in water depths up to 300 feet in benign environments. Rowan Vikinghas three of these rigs under contract directly with Saudi Aramco that are managed by ARO. The fourth rig is cold-stacked.
Our one remaining Gorilla class rig, the Rowan Gorilla IV, was delivereddesigned as a heavier-duty class of jack-up rig capable of operating in 2010, andwater depths to 450 feet in benign environments.
In November 2017, we sold one of our older rigs in our jack-up fleet, the Rowan StavangerCecil Provine, under an agreement that prohibits its future use as a drilling unit. In October 2017, we also sold one premium and two high-specification jack-ups to ARO. See Rowan NorwayNote 1 were deliveredto our consolidated financial statements in 2011.Part II, Item 8 of this Annual Report on Form 10-K.
See Part I, Item 2, “Properties,” of this Annual Report on Form 10-K for additional information regarding our fleet.
Our operations are subject to many uncertainties and hazards. See Part I, Item 1A, “Risk Factors,” of this Annual Report on Form 10-K for additional information.
Contracts
Our drilling contracts generally provide for a fixed amount of compensation per day (day rate), and are either “well-to-well,” “multiple-well” or "fixed-term" generally ranging from one month to several years. Well-to-well contracts are typically cancellable by either party upon completion of drilling. Fixed-term contracts usually contain a termination provision such that either party may terminate if drilling operations are suspended for extended periods as a result of events of force majeure. While many fixed-term contracts are for relatively short periods of three months or less, many others are for one or more years, and all can continue for periods longer than the original terms. Well-to-well contracts can be extended over multiple series of wells. Many drilling contracts
contain renewal or extension provisions exercisable at the option of the customer at mutually agreeable rates. ManySome of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization. We recognize certain lump-sum fees and related expenses over the primary contract term. We recognize reimbursement of certain costs as revenuesrevenue and expenses
at the time they are incurred. Our contracts for work in foreign countries generally provide for payment in United States (U.S.) dollarsUSD except for amounts required by applicable law to be paid in the local currency or amounts required to meet local expenses.
A number of factors affect our ability to obtain contracts at profitable rates within a given area.region. Such factors, which are discussed further under “Competition” in this Part I, Item 1 of this Annual Report on Form 10-K and in "Risk Factors"“Risk Factors” included in Part I, Item 1A of this Annual Report on Form 10-K include among other things,the global economic climate, the price of oil and gas which can affect our customers' drilling budgets, over- or under-supply of drilling units, location and availability of competitive equipment, the suitability of equipment for the project, comparative operating cost of the equipment, competence of drilling personnel and other competitive factors. Profitability may also depend on receiving adequate compensation for the cost of moving equipment to drilling locations.
During periods of weak demand and declining day rates, we have historically entered into contracts at lower rates in an attemptorder to keep our rigs working. At times, however, market conditions have forced us to "cold-stack""warm-stack" rigs rather than maketo reduce costs during extended periods between contracts. We currently have three ultra-deepwater drillships and five jack-ups warm stacked. We have also cold-stacked certain of our idle older rigs to reduce cost further and have ultimately sold six such rigs over the substantial improvements required to secure ongoing work. As of February 19, 2015, we hadlast three cold-stacked rigs inyears, the US GOM.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 $5.1$456.2 million at February 13, 2018, down from approximately $1.7 billion at February 19, 2015, up slightly from approximately $5.0 billion at February 20, 2014.14, 2017. Our backlog excludes any backlog associated with ARO Drilling. See “Outlook” in Management’s"Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources" in Part II, Item 7 of this Annual Report on Form 10-K for further information with respect to our backlog.
Competition
The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including supply and demand for drilling units, price, rig capability, operating and safety performance, local content requirements and reputation.
In the jack-up drilling market, we compete with numerous offshore drilling contractors that together have 545463 marketed jack-up rigs available worldwide as of February 16, 2015.13, 2018, with an additional 91 units that are under construction or on order. (We define marketed rigs as all rigs that are not cold-stacked.) We estimate that 6973 delivered and marketed jack-ups, or 1316 percent of the world’s existingmarketed jack-up fleet, are high-specification, including our 19Rowan's 16 high-specification rigs. Newbuild deliveries of jack-ups in recent years have increased the pool of rigs competing for contracts in many areas in which we operate, putting significant downward pressure on utilization and day rates. As of February 16, 2015, there were approximately 132 jack-up rigs under construction worldwide for delivery through 2017 (24 percent of the current jack-up fleet), including 53 that are considered high-specification (77 percent of the current high-specification fleet). Approximately 22 of these jack-up rigs, which are not contracted, are scheduled for delivery in 2015. Utilization and day rates in certain regions are expected to come under additional pressure as these rigs enter the worldwide fleet.
At February 16, 2015,13, 2018, there were 119 drillships operating201 marketed floaters (drillships and semi-submersibles) worldwide, plus another 57with an additional 42 units that are under construction or on order for delivery through 2020, including our fourth drillship under construction.order. We estimate that 84,103 of these floaters, or approximately 7151 percent of the world’s existing drillshipmarketed fleet, are capable of drilling in water depths of 10,000 feet or more, but only an estimated 35 floaters, or approximately 17 percent of the world's marketed fleet, have 2,500,000 pound hook-load capability and nearly allare 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 those247 newbuild jack-ups and 163 newbuild floaters delivered since early 2006. The addition of newbuild units, combined with numerous rigs having rolled off contracts in past months, has continued to increase competition, putting additional downward pressure on day rates and utilization. Of the approximately 91 jack-up rigs under construction willworldwide scheduled for delivery through 2020 (28% of the currently utilized jack-up fleet of approximately 328 rigs), approximately 28 are considered high-specification (38% of the delivered high-specification fleet). Currently, there are approximately 58 competitive newbuild jack-up rigs scheduled for delivery during 2018, and none of them have 10,000-foot water depth capabilities. Drillship utilization and day ratescontracts in place. For the floater market there are expected to comeapproximately 42 floaters under additional pressure as newly constructed drillships enterconstruction worldwide for delivery through 2021 (28% of the market.
currently utilized floater fleet of approximately 150 rigs). Following the negotiated delivery delays on several units into future years, there are approximately 21 competitive newbuild floaters scheduled for delivery during 2018, with only 6 having contracts.
Based on the number of rigs as tabulated by IHS-Petrodata, we are the nintheighth largest offshore drilling contractor in the world and the sixthfifth largest jack-up rig operator.contractor. Based on the most recent publicly available information,market capitalization, we are the sixthfourth largest publicly traded pure play offshore drilling contractor ranked by revenues.driller. Some of our competitors have greater financial and other resources and may be more able to make technological improvements to existing equipment or replace equipment that becomes obsolete. In addition, those contractors with larger and more diversified drilling fleets may be better positioned to withstand unfavorable market conditions.
We market our drilling services to present and potential customers, including large international energy companies, smaller independent energy companies and foreign government-owned or government-controlled energy companies. See “Management’s “Management’s
Governmental Regulation
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation. In addition, the U.K., the U.S. and other countries in which we operate have regulationsthose 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 offshore waters in some circumstances,operations and in certain jurisdictions we must document financial responsibility.
Generally,liquidity. In many of our drilling contracts, we are indemnified under our drilling contracts for pollution, well damage and environmental damage, except in certain cases of pollution emanating above the surface of water from spills of pollutants emanating from our drilling rigs. This indemnity includes all costs associated with regaining control of a wild well, removal and disposal of pollutants, environmental remediation
and claims by third parties for damages. SuchHowever, such contractual indemnification provisions may not however, adequately protect us for several reasons including: (a)such as (i) the contractual indemnity provisions may require us to assume a portioncertain types or amounts of the liability; (b)(ii) our customers may not have the financial resources necessary to honor the contractual indemnity provisions; and (c)or (iii) the contractual indemnity provisions may be unenforceable under applicable law.
Our customers often require us to assume responsibility for pollution damages wherewhen we are at fault. We seek to limit our liability exposureto 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 $5$50 million of costs related to an incident resulting in wellbore pollution due to our negligence, with the customer assuming responsibility for all costs in excess of $5 million.that amount. We can provide no assurance that we will be able to negotiate indemnities and/or limitation of liability provisions for all of our contracts or that such indemnification and/or limitation of liability provisions can be enforced or will be sufficient. Our customers may challenge the validity or enforceability of the indemnity provision for several reasons, including but not limited to applicable law, judicial decisions, the language of the indemnity provision, reasons of public policy, degree of fault and/or the circumstances resulting in the pollution.
In the event of an incident resulting in wellbore pollution andwhere we are liable for all or a customer who is unable or unwilling to honor its indemnity obligation,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. IfSuch 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, there could be a material adverse effect on our results of operations, financial positionsignificant.
The jurisdictions in which we operate have various regulations and cash flows.
Pursuantrequirements with which we must comply. For example, pursuant to the U.S. Clean Water Act, a National Pollutant Discharge Elimination Permit (NPDES permit)("NPDES") permit is required for discharges into the US GOM. As a contract driller in the US GOM, we operate in accordance with the NPDES permit regardless of the holder. According to the NPDES permit, theThe permit holder is the designated responsible party and is thus responsible for any environmental impacts that would occur in the event of the discharge of any unpermitted substance, including a fuel spill or oil leak from an offshore installation such as a mobile drilling unit.
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 UKU.K. Offshore Directive, which comes into force July 19, 2015, we will beare required to have an approved Oil Pollution Emergency Plan (OPEP)("OPEP") for each of our drilling unitsunit operating in UKU.K. waters. The UK Offshore Directive also specifies additional regulations related to safety, licensing, environmental protection, emergency response and liability.liability with which we comply.
Additionally, pursuant to the International Maritime Organization (IMO),IMO MARPOL 73/78, we are required to have a Shipboard Oil Pollution Emergency Plan (SOPEP)("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 annuallyin 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. The drills include participation of key personnel, spill response contractors and representatives of governmental agencies. For operations anywhere in the United States,world including in the U.S., our SOPEPs are subject to review and approval by various organizations including the United States Coast Guard, the EPA and the Bureau of Safety and Environmental Enforcement (BSEE), and are recertified every five years by the American Bureau of Shipping,Flag State, or a Recognized Organization under the IMO.
acting on behalf of Flag State.
As the designated responsible party, thean operator has the primary responsibility for spill response, including having contractual arrangements in place with emergency spill response organizations to supplement any onboard spill response equipment. Pursuant to our SOPEPs, we have certain resources and supplies onboard our rigs which would be useddrilling units to mitigate the impact of an incident until an emergency spill response organization couldcan deploy its resources. However, we also have an agreement with an emergency spill response organization should we have an incident that exceeds the scope of our onboard spill response equipment.
Our primary spill response provider has been in business since 1994 andthe U.S. specializes in helping industries prevent and clean up oil and other hydrocarbon spills throughout the Gulf Coast, with response centers in Texas and Louisiana with 24-hour response capabilities and equipment.spills. Our provider has represented it holds all necessary licenses, certifications and permits to respond to environmental emergencies in the
US GOM and maintains contactscontracts with other response resources and organizationorganizations outside the US GOM. Our provider has significant spill response resources to meet the needs of its customers.
We believe we have adequate equipment and third-party resources available to us to respond to an emergency spill; however, we can provide no assurance that adequate resources will be available should multiple concurrent spills occur. Other foreign jurisdictions in which we operate have similar regulations and requirements to which we comply.
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 Ocean EnergyOffshore Operations Committee, the Oil Companies International Marine Forum, the Center for Offshore Safety Institute, and the British Rig Owners Association, which are intended to improve safety and protectprotection of the environment.
the other jurisdictions in which we operate are subject to regulation with respect to well design, casing and cementing and well control procedures, as well as rules requiring operators to systematically identify risks and establish safeguards against those risks through a comprehensive SEMS. Any serious oil and gas industry related event heightens governmental and environmental concerns and may lead to legislative proposals being introduced which may materially limit or prohibit offshore drilling in certain areas. New regulations may be implemented, including rules regarding drilling systems and equipment, such as blowout preventer and well-control systems and lifesaving systems, as well as rules regarding employee training, engaging personnel in safety management and requiring third-party audits of SEMS programs.
Except as discussed above, we do not believe regulatoryRegulatory compliance has and may continue to materially affectedimpact our capital expenditures and earnings, or competitive positionparticularly in the event of an environmental incident. Given the state-of-the-art design of our drillships and high specification of our jack-up fleet, we believe we are well positioned competitively to date, although such measures increase drilling costsour peers to be able to comply with current and may adversely affect drilling operations. Further regulations may reasonably be anticipated, but any effects on our drilling operations cannot be accurately predicted at this time.
We operate in areas where regulatory requirements govern the protection of employee occupational health and working environments.
In addition to regulations that directly affect our operations, regulations associated with the production and transportation of oil and gas affect our customers and thereby could potentially impact demand for our services.
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.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.
costs upon renewal.
Employees
At December 31, 2014,2017, we had 4,051approximately 2,800 employees worldwide, compared to 3,499approximately 2,900 and 3,1193,500 at December 31, 20132016 and 2012, respectively.2015, respectively, and approximately 330 independent contractors. Certain of our employees and contractors in international markets,various regions, such as Trinidad Norway and Angola,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
CustomersIn 2017, Saudi Aramco, Anadarko, and Cobalt accounted for 29%, 17% and 14%, respectively, of consolidated revenue. Saudi Aramco revenue was derived from our Jack-ups segment, and Anadarko and Cobalt revenue was derived from our Deepwater segment.
Reports filed with or furnished to the SEC
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act are made available free of charge on our website
One customer, Saudi Aramco, accounted for 10%at www.rowan.com as soon as reasonably practicable after we electronically file such material with, or morefurnish it to, the SEC. Information contained on or accessible from our website is not incorporated by reference into this Annual Report on Form 10-K and should not be considered a part of our consolidated revenues, contributing approximately 24% of consolidated revenues in 2014.this report or any other filing that we make with the SEC.
ITEM 1A. RISK FACTORS
You should consider carefullyThere 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 following risk factors, in addition to the other information contained and incorporated by reference in this Form 10-K, before deciding to invest inonly risks facing our equity or debt securities.
Company.
Our business depends on the level of activity in the offshore oil and gas industry, which is significantly affected by volatiledeclines in oil or gas prices and reduced demand for oil and gas prices and other factors beyond our control.
products.
Our business depends heavily on a variety of economic and political factors and the level of oil and gas exploration, development and production and demand for drilling services in offshore areasactivity worldwide. Demand for our drilling services is vulnerable toSustained declines that are typically associated with depressed oil and natural gas prices. Even the perceived risk of a decline in oil or natural gas prices, may causecombined with market expectations of a prolonged weakened global market, have caused oil and gas companies to significantly reduce their spending, in which caseexploration, development and production activities, thereby decreasing demand for ouroffshore drilling services could decrease and our drilling revenues may be adversely affected byleading to lower rig utilization and/orand day rates.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. As a result of the significant decline in oil
and gas prices over the last half of 2014, many oil and gas operators have announced significant reductions in their capital expenditure budgets for 2015 and beyond, which we expect will, in turn, reduce the demand and day rates for offshore drilling units worldwide.
Demand for our drilling services also depends on additionalmany factors that are beyond our control, including:
worldwide demand for and prices of oil and natural gas;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;companies and their ability to raise capital;
the willingness and ability of the Organization of Petroleum Exporting Countries (OPEC)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;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;
expectations regarding future energy prices;
environmental and other laws and regulations;
policies of various governments regarding exploration and development of oil and natural gas reserves;
nationalization of assets or workforce and/or confiscation;confiscation of assets;
worldwide tax policies;policies and treaties;
political and military conflicts in oil-producing areas and the effects of terrorism;
advances in explorationincreased supply of oil and gas from onshore development technology such as unconventionaland relative cost of offshore drilling versus onshore oil and the development of shale resources;gas production;
the development and exploitation of alternative fuels and energy sources;sources including the growing demand, often government-mandated, for electric powered vehicles; and
merger, divestiture, restructuring and consolidation of our customer base,customers and competitors and their assets.
consolidationAdverse developments affecting the industry as a result of one or more of these factors, including any further decline in oil or gas prices or the failure of oil or gas prices to increase, a global recession, continued declines in demand for oil and gas products, increased oversupply of drilling units, and increased regulation of drilling and production, would adversely affect our competitors.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. In addition to depressedDepressed oil and gas prices and an oversupply of drilling units may leadhave led to a reductionfurther reductions in rig utilization and day rates, and, therefore,which may materially impact our profitability.
Our ability to meet our cash flow obligations will dependdepends on our ability to secure ongoing work for our drilling units at sufficient day rates. As of February 19, 2015,13, 2018, we had 12nine jack-up drilling units without contracts (including two cold-stacked and two recently purchased jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs); eleven with contract terms ending in 2015,2018; and 4 drilling unitsthree with contract terms ending in 2016. We cannot predict the2019; and three of our four drillships without contracts; one of our drillships has a contract ending in 2018. Given current market conditions, future level of demand orfor offshore drilling units and day rates may continue to remain at low levels, possibly for our drilling units or future conditions in the oil and gas industry.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 existing and futurenewbuild drilling units, has increased significantly due to heightened construction of newcombined with the decrease in demand for offshore drilling services, has led to an oversupply of drilling units during the last few years.and further declines in utilization and day rates that is expected to continue for some time. According to industry sources, there were 545 jack-ups and 119 drillships in the463 marketed jack-up rigs worldwide fleets as of February 16, 2015, and13, 2018, an additional 132 jack-ups91 units that are under construction or on order and 57 drillships were201 marketed floaters (drillships and semi-submersible) worldwide, with an additional 42 units that are under construction or on order. This significant increase in construction activity has resulted in an oversupply of drilling units, which in turn, has caused a subsequent(We define marketed rigs as all rigs that are not cold-stacked.) A continued decline in utilization and day rates which decline is expected to continue for an extended period of time. This overcapacity, combined with the decline in oil and gas prices and reductions in capital expenditure budgets by oil and gas operators, is expected to intensify competition and result in lower day rates and/or inability to contractwould further impact our drilling units. Lower utilization and day rates could adversely affect our revenuesrevenue and profitability.
A further decline in the market for contract drilling services could result in additional asset impairment charges.
In 2014, weWe recognized asset impairment charges on our jack-up drilling units aggregating $566approximately $330 million (orin 2015 and $34 million in 2016, or approximately 7%4% and 0.5%, respectively, of our total assets) on our twelve oldest jack-up rigs.fixed asset carrying values. Prolonged periods of low utilization and day rates, the cold-stacking of idle assets, or the sale of assets below their then carrying value could result in the recognition of additional impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable. See “Impairment of Long-lived Assets” in Note 2 of Notes to Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K for information regarding impairment charges recognized in 2013 and 2014.
additional information.
We are subject to operating risks that could result in environmental damage, property loss, personal injury, death, business interruptions and other losses.
Our drilling operations are subject to many operational hazards such as blowouts, explosions, fires, collisions, punch-throughs (i.e., when one leg of a jack-up rig breaks through the hard crust of the ocean floor, placing stress on the other legs), mechanical or technological failures, navigation errors, or equipment defects that could increase the likelihood of accidents. Accidents can result in:
serious damage to or destruction of property and equipment;
personal injury or death;
costly delays or cancellations of drilling operations;
interruption or cessation of day rate revenue;
uncompensated downtime;
reduced day rates;
significant impairment of producing wells, leased properties, pipelines or underground geological formations;
damage to fisheries and pollution of the marine and coastal environment; and
fines and penalties.
Our drilling operations are also subject to marine hazards, whether at drilling sites or while equipment is under tow, such as a vessel capsizing, sinking, colliding or grounding. In addition, raising and lowering jack-up rigs and drilling into high-pressure formations are complex, hazardous activities, and we periodically encounter problems. Any ongoing change in weather or sea patterns or climate conditions could increase the adverse impact of marine hazards.
In past years, we have experienced some of the types of incidents described above, including high-pressure drilling accidents resulting in lost or damaged formations and punch-throughs and towing accidents resulting in lost or damaged equipment.equipment and high-pressure drilling accidents resulting in lost or damaged formations. Any future such events could result in operating losses and have a significantmaterial impact on our business.
The global nature of our operations involves additional risks, particularly in certain foreign jurisdictions.
In recent years,Our operations are diversified geographically although we have significantly diversified our operations internationally.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 exchangeconvertibility and repatriation risk,restrictions, security threats including terrorism, piracy, and the risk of asset expropriation. Political unrest and regulatory restrictions in our areas ofcould halt operations could potentially delay current or planned projects or could impact us in other unforeseen ways.
ways, especially in areas of concentrated presence (see Note 13 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K). Many countries have regulations or policies currently in effect requiring or rewarding the participation of local companies and individuals in the petroleum relatedpetroleum-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 ownershipco-ownership of our drilling units, in whole or in part, by domestichome country companies or citizens and /or require reflagging of our drilling units under the flag of the home country. The governments of many of these foreign countries have become increasingly active in requiring higher levels of local participation which may increase our costs and risks of operating in these regions, thereby limiting our ability to enter into, relocate from, or compete in these regions.
In addition, our inability to obtain visas and work permits for our employees in foreignthe 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 foreign areascertain 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.
In order to reduce the impactAlthough we are a U.K. company, a significant majority of exchange rate fluctuations, we generally require customer payments to beour revenue and expenses are transacted in U.S. dollars and try to limit non-U.S. currency holdings to the extent they are needed to pay liabilities denominatedUSD, which is our functional currency. However, in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive some portion of payment in the local currency. In such instances, we may beWe are exposed to devaluation and otherforeign 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 loss. Inrate risk, we attempt to limit foreign currency holdings to the event we terminate operationsextent they are needed to pay liabilities denominated in such countries we may not be able to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where we hold approximately $15.2 million in Egyptian pounds, based on exchange rates in effect at January 31, 2015.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 repatriate such fundscontrols over the repatriation of income or capital. For more information, see “Assets and Liabilities Measured at Fair Value on a Recurring Basis” in the future.
Note 7 to our Consolidated Financial Statements in Part II, Item 8 of this Annual Report on Form 10-K. The offshore drilling industry is highly competitive and cyclical, with intense price competition.
OurThe offshore contract drilling markets areindustry is a highly competitive withand cyclical business characterized by numerous participants, nonecompetitors, high capital and operating costs and evolving capability of which has a dominant market share. Some of our competitors may have greater financial or other resources than we do.newer rigs. Drilling contracts are often awarded on a competitive-bid basis, and intense price competition, is frequentlyrig availability, location and suitability, experience of the primary factorworkforce, efficiency, safety performance record, technical capability and condition of equipment, operating integrity, reputation, industry standing, and client relations are all factors in determining which qualified contractor is awarded the job. 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 there have been periods of high demand and short supply of rigs and high day rates, followed by periodscyclical. 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 lowgas prices and reduced worldwide drilling activity. These conditions have intensified the competition in the industry and put significant downward pressure on day rates. The current worldwide fleet overcapacity and anticipated delivery ofAs a significant number of newbuilds over the next five years will further increase the supply of rigs and intensify competition and pressure day rates. Weresult, we may be unable to secure profitable contracts for our drilling units, we may have to reducecontract our dayrigs at substantially lower rates orfor 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 couldwould adversely affect our operating results, cash flows and cash flows.
financial position.
We willmay experience reduced profitability if our customers terminate or seek to renegotiate our drilling contracts, and our backlog of contractsdrilling revenue may not be ultimatelyfully 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 are cancelablemay be canceled by the customer without penalty upon the occurrence of events beyond our control such as the loss or destruction of the rig,drilling unit, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, andequipment. While most of our contracts require the customer to pay a termination fee in the event of a cancelation without cause. Not all of our contracts require the customer to make an early termination payment upon cancellation. Earlycancellation without cause, early termination payments may not fully compensate us for the loss of the contract and could result in the rigdrilling unit becoming idle or cold-stacked for an extended period of time. During periods of depressed market conditions, we are subject to the increased risk of our customers seeking to terminate their contracts, including through claims of non-performance, or to renegotiate the terms, including day rates and payment options, of existing contracts.
In addition, our drilling contracts subject us to counterparty risks. The ability of our counterparties to perform their obligations under a contract depend on a number of factors beyond our control, including among other things, general economic conditions, the condition of the offshore drilling industry, market prices for oil and gas, the overall financial condition of the counterparty, the day rates received and the level of profitability necessary to maintain drilling activities. In addition, in a depressed market, our customers may no longer need a drilling rig that is currently under contract or may be able to obtain a comparable drilling unit at a lower day rate. If we or our customers are unable to perform under existing contracts for any reason or replace terminated contracts with new contracts underhaving less favorable terms, our backlog of estimated revenues from drilling contractsrevenue would decline, and may have a material adverse effect onadversely affecting our financial results.
We must make substantial capital and operating expenditures to build, 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 our capital expenditure requirements. We can provide no assurance that we will have access to adequate or economical sources of capital to fund ournecessary capital expenditures.
Construction upgrades, enhancements, conversions, mobilizations and repairs of rigs and drillships are subject to risks, including delays and cost overruns, which could have an adverse impact on our financial position, results of operations and cash flows.
We have one remaining ultra-deepwater drillship under construction at Hyundai Heavy Industries Co. Ltd.'s shipyard in Ulsan, South Korea scheduled for delivery in late March 2015. Although there is certain insurance coverage and financial and bank guarantees associated with the drillship construction contract, in the event Hyundai is, for any reason, unable to perform under its agreement, there may be a material adverse effect on our results of operations, financial condition and cash flows.
From time to time in the future, we may also undertake additional new construction projects. In addition, we may make significant upgrade, refurbishment and repair expenditures for our fleet from time to time, particularly as our drilling units age.
Initial operations of new drilling units and mobilization of existing units often result in delays and other complications that could result in significant unexpected costs, uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts.
Some of the costs associated with construction projects, upgrades, enhancements, conversions, mobilizations and repairs of drilling units could be unplanned and are subject to risks of cost overruns or delays as a result of numerous factors, including the following:
shipyard unavailability;
shortages of equipment, materials or skilled labor for completion of repairs or upgrades to our equipment; unscheduled delays in the delivery or cost increases of materials and equipment or in shipyard construction;
failure of equipment to meet, design, quality or performance standards;
loss of or damage to essential equipment while in transit;
financial or operating difficulties experienced by equipment vendors or the shipyard;
unanticipated actual or purported change orders;
local customs strikes or related work slowdowns that could delay importation of equipment or materials;
engineering problems, including those relating to the commissioning of newly designed equipment;
design or engineering changes;
latent damages or deterioration to the hull, equipment and machinery in excess of engineering estimates and assumptions;
work stoppages;
client acceptance delays;
weather interference, storm damage or other events of force majeure;
disputes with shipyards and suppliers;
inability or unwillingness of shipyards and suppliers to honor warranty obligations;
long lead-times for replacement of equipment;
shipyard failures and difficulties;
failure of third-party equipment vendors or service providers;
unanticipated cost increases, including relating to raw materials used in construction of our drilling units; and
difficulty in obtaining necessary permits or approvals or in meeting permit or approval conditions.
These factors may contribute to cost variations and delays in the delivery of our ultra-deepwater newbuild drillship or upgrade projects. Delays in the delivery of the drillship or other drilling units or the inability to complete construction in accordance with their design specifications may, in some circumstances, result in a delay in contract commencement, resulting in a loss of revenue
to us, and may also cause customers to renegotiate, terminate or shorten the term of a drilling contract pursuant to applicable late delivery clauses. In the event of termination of one of these contracts, we may not be able to secure a replacement contract on as favorable terms or at all. Additionally, capital expenditures for upgrades, refurbishment and construction projects could materially exceed our planned capital expenditures. Moreover, our drilling units that may undergo upgrade, refurbishment or repair may not earn a day rate during the periods they are out of service. In addition, in the event of a shipyard failure or other difficulty, we may be unable to enforce certain provisions under our newbuild contracts such as our contractual rights to recover amounts paid as installments under such contracts. Furthermore, the inability or unwillingness of shipyards and suppliers to honor warranty obligations may result in additional costs to us. The occurrence of any of these events may have a material adverse effect on our results of operations, financial position or cash flows.
We have and will likely continue to have certain customer concentrations, and the loss of a significant customer could have a material adversewould adversely impact on our financial results.
One customer, Saudi Aramco,A concentration of customers increases the risks associated with any possible (i) termination or nonperformance of drilling contracts, (ii) failure to renew contracts or award new contracts, or (iii) reduction of our customers' drilling programs. In 2017, three customers accounted for 24%60% of our 2014 consolidated revenues.revenue (Saudi Aramco - 29%; Anadarko - 17%; Cobalt - 14%). The loss or material reduction of business from a significant customer couldwould have a materialan 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 extent that we may be heavily dependent on any single customer,overall financial condition of the counterparty. Should a significant counterparty fail to honor its obligations under an agreement with us, we could be subject to the risks faced by that customer to the extent that such risks impede the customer's ability to continue operating and make timely payments to us. In addition, due to the high day rate and long-term of our drillship contracts, a loss of any of our drillship customers maysustain losses, which could have a material adverse impacteffect on our business, financial condition and results of operations and cash flows.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, futureapprovals. Future changes to these permits or approvals or any adverse change in the interpretation of existing permits and approvals.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 significantmaterial 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 (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE),BSEE, have implemented significant environmental and safety regulations applicable to drilling operations in the US GOM. These regulations have at times adversely impacted the ability of our customers to obtain necessary permits and approval on a timely basis and/or to continue operations uninterrupted under existing permits.
We may not realize the expected benefits of the ARO joint venture and it may introduce additional risks to our business.
In November 2016, Rowan and Saudi Aramco announced plans to form a 50/50 joint venture with Rowan and Saudi Aramco each selling existing drilling units and contributing capital as the foundation of the new company. The new entity, ARO, commenced operations on October 17, 2017, and is expected to add up to 20 newbuild jack-up rigs to its fleet over ten years commencing as early as 2021. There can be no assurance that the new jack-up rigs will begin operations as anticipated or we will realize the expected return on our investment. We may also experience difficulty jointly managing the venture, and integrating our existing employees, business systems, technologies and services with those of Saudi Aramco in order to operate the joint venture efficiently. Further, in the event ARO has insufficient cash from operations or is unable to obtain third party financing, we may periodically be required to make additional capital contributions to ARO, up to a maximum aggregate contribution of $1.25 billion, which could affect our liquidity position. As a result of these risks, it may take longer than expected for us to realize the expected returns from ARO or such returns may ultimately be less than anticipated. Additionally, if we are unable to make any required contributions, our ownership in ARO could be diluted which could hinder our ability to effectively manage ARO and harm our operating results or financial condition.
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. OperationsFor 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 revenuesrevenue associated with downtime required to implement regulatory requirements.
In the aftermath of the Macondo well blowout in 2010 and the subsequent investigation into the causes of the event, new rules were implemented for oilOil and gas operations in the US GOM and in many of the international locations in which we operate including new standards forare 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.
Governments around the world are beginning to adopt laws and regulations regarding climate change. Lawmakers and regulators in the U.S., the U.K. and other jurisdictions where we operate have focused increasingly on restricting and reporting the emission of carbon dioxide, methane and other “greenhouse” gases that may contribute to warming of the Earth’s atmosphere and other climatic changes. This may result in new environmental regulations that may unfavorably impact us, our suppliers and our customers. We may be exposed to risks related to new laws, regulations, treaties or international agreements pertaining to climate change, greenhouse gases, carbon emissions or energy use that could decrease the use of oil or natural gas, thus reducing demand for hydrocarbon-based fuel and our drilling services. Governments may also pass laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy, which may reduce demand for oil and natural gas and our drilling services. Such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have a negative impact on our business, and could adversely affect our operations by limiting drilling opportunities.
In addition, the offshore drilling industry is highly dependent on demand for services from the oil and gas industry and accordingly, regulations of the production and transportation of oil and gas generally could impact demand for our services.
Regulation of greenhouse gases and climate change could have a negative impact on our business.
Governments around the world are increasingly focused on enacting laws and regulations regarding climate change and regulation of greenhouse gases. Lawmakers and regulators in the jurisdictions where we operate have proposed or enacted regulations requiring reporting of greenhouse gas emissions and the restriction thereof. In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues and impose reductions of hydrocarbon-based fuels. Laws or regulations incentivizing or mandating the use of alternative energy sources such as wind power and solar energy have also been enacted in certain jurisdictions. Numerous large cities globally and a few countries have mandated conversion from internal combustion engine powered vehicles to electric-powered vehicles and placed restrictions on non-public transportation, thereby reducing future demand for oil which could have a material impact on our business. Laws, regulations, treaties and international agreements related to greenhouse gases and climate change may unfavorably impact our business, our suppliers and our customers, and result in increased compliance costs, operating restrictions and could reduce drilling in the offshore oil and gas industry, all of which would have a material adverse impact on our business.
Our drilling units are subject to damage or destruction by severe weather, and our drilling operations may be affected by severe weather conditions.
Our drilling rigs are located in areas that frequently experience hurricanes and other forms of severe weather conditions. These conditions can cause damage or destruction to our drilling units. Further, high winds and turbulent seas can cause us to suspend operations on drilling units for significant periods of time. Even if our drilling units are not damaged or lost due to severe weather, we may experience disruptions in our operations due to evacuations, reduced ability to transport personnel or necessary supplies to the drilling unit, or damage to our customers’ platforms and other related facilities. Additionally, our customers may not choose not to contract our rigs for use during hurricane season, particularly in the US GOM. Future severe weather could result in the loss
or damage to our rigs or curtailment of our operations, which could adversely affect our financial position, results of operations and cash flows.
We are currently self-insured with respect to physical damage due to named windstorms in the US GOM.
Hurricanes (or named windstorms) have caused tremendous damage to drilling and production equipment and facilities throughout the US GOM in recent years, and insurance companies have incurred substantial losses as a result. Accordingly, insurance companies have substantially reduced the levels of available coverage for named windstorms in the US GOM and have dramatically increased the price of such coverage. Coverage for potential liabilities to third parties associated with property damage and personal injuries, as well as coverage for environmental liabilities and removal of wreckage and debris associated with these named windstorm losses, has also been limited.
As a result of the increased cost and reduced availability, we do not maintain named windstorm physical damage coverage on any of our rigs located in the US GOM. Our coverage for liabilities (including removal of wreck) arising out of a US GOM named windstorm are subject to a self-insured retention of $200 million per occurrence. Losses due to future US GOM named windstorms not covered by insurance could adversely affect our financial position, results of operations and cash flows.
Taxing authorities may challenge our tax positions, and we may not be able to realize expected benefits.
We are subject to tax laws, regulations and treaties in many jurisdictions. Changes to these laws or interpretations could affect the taxes we pay in various jurisdictions. Our tax positions are subject to audit by relevant tax authorities who may disagree with our interpretations or assessments of the effects of tax laws, treaties, or regulations, or their applicability to our corporate structure or certain of our transactions we have undertaken. We could therefore incur material amounts of unrecorded income tax cost 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 are frequentlyhave been legislative proposals in the U.S. that attemptattempted to treat companies that have undertaken similar transactions as U.S. corporations subject to U.S. taxes or to limit the tax deductions or tax credits available to U.S. subsidiaries of these corporations. The realization of the expected tax benefits of our redomestication could be impacted by changes in tax laws, tax treaties or tax regulations or the interpretation or enforcement thereof or differing interpretation or enforcement of applicable law by the IRS or other tax authorities. Changes in our effective tax rates as determined from time to time, the inability to realize anticipated tax benefits, or the imposition of additional taxes could have a material impact on our results of operations, financial position and cash flows. Our future effective tax rates could be adversely affected by changes in the valuation of our deferred tax assets and liabilities, the ultimate repatriation of earnings from RCI’sthe non-U.S. subsidiaries toof RCI, a wholly owned, indirect subsidiary of the Company, or by changes in applicable regulations and accounting principles.
Changes in our recorded tax estimates (including estimated reserves for uncertain tax positions) may have a material impact on our results of operations, financial position and cash flows. We do not provide for deferred income taxes on certain undistributed earnings of our non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is our policy and intention to permanently reinvest earnings of non-U.S. subsidiariesNo subsidiary of RCI outside the U.S. Should the non-U.S. subsidiaries ofhas a plan to distribute earnings to RCI makein a distribution from thesemanner that would cause those earnings we mayto be subject to U.S., U.K. or other local country taxation.
On December 22, 2017, the U.S. government enacted tax legislation commonly referred to as the U.S. Tax Act. The U.S. Tax Act significantly changes U.S. corporate income tax laws including but not limited to (i) reducing the U.S. corporate income tax rate from 35% to 21% starting in 2018 (ii) requiring a one-time transition tax on mandatory deemed repatriation of certain unremitted non-U.S. earnings as of December 31, 2017, (iii) changing how non-U.S. subsidiaries are taxed in the U.S. as of January 1, 2017, (iv) eliminating the carryback abilities and establishing an 80% limitation on the annual utilization of net operating losses after December 31, 2017, (v) establishing new limitations on interest deductions as of January 1, 2018 and (vi) requiring additional U.S. income taxes.tax on certain payments by U.S. subsidiaries to non-U.S. subsidiaries if such payments are subject to reduced rates of U.S. withholding tax under a treaty after December 31, 2017. As we do not have all the necessary information to analyze all effects of this tax reform, our financial statements include provisional amounts, which we believe represents a reasonable estimate of the accounting implications of this tax reform.
The U.S. Tax Act requires complex computations to be performed that were not previously provided in U.S. tax law, significant judgments to be made in interpretation of the U.S. Tax Act, and the preparation and analysis of information not previously relevant or regularly produced. As such, the application of accounting guidance for such items is currently uncertain. As a result, we have provided a provisional estimate on the effect of the U.S. Tax Act in our financial statements. As additional regulatory guidance is issued by the applicable taxing authorities, as accounting treatment is clarified, as we perform additional analysis on the application of the law, and as we refine estimates in calculating the effect, our final analysis, which will be recorded in the period completed, may be different from our current provisional amounts.
Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.
Our operations are subject to political and economic risks and uncertainties, including instability resulting from civil unrest, political demonstrations, mass strikes, or an escalation or additional outbreak of armed hostilities or other crises in oil or natural gas producing areas, which may result in extended business interruptions, suspended operations and danger to our employees, or result in claims by our customers of a force majeure situation and payment disputes. Additionally, we are subject to risks of terrorism, piracy, political instability, hostilities, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in many of our areas of operations.
MostOperating and maintenance costs of our contracts are fixed-price contracts,drilling units may be significant and changes in customer requirements, increased regulatory requirements and increases in ouroperating costs or price levels in general could have an adverse effect on the profitability of thoseour 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. Our long-term contractsGiven current market conditions, we may not be atable to negotiate day rates lower than current prevailing rates,sufficient to cover increased or unanticipated costs. Our operating expenses and therefore unable to benefit from the higher prevailing rates. Long-term contracts may alsomaintenance costs can be at day rates higher than prevailing rates, and our revenues may decline at the end of such favorable contracts. Many of our operating costs are unpredictable and can vary baseddepend on events beyond our control, including increaseda variety of factors including: crew costs, costs of provisions, equipment, insurance, maintenance and repairs, customer and regulatory requirements, and increased labor and other costs. Operators and regulatorsshipyard costs, many of which are requiring higher standards than in the past, including more robust back-up redundancy systems.beyond our control. Our profit margins willmay therefore vary over the terms of our contracts, as a result of applicable day rates and operating costs. If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.
Our 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 10%6.8% of our available rig days in 2014 and 2013.2017. Operating revenue may fluctuate as rigs are recontracted at prevailing market rates upon termination of a function of changes in day rates,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 usedretained to prepare the rig for its next contract. During times of reduced activity, reductions in costs may not be immediate as portions of thesome crew members may be required to prepare our rigs for stacking.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.
Shortages of significant partsWe may have difficulty obtaining or equipment, supplier capacity constraints, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenues and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment, parts, components and sub-systems used in our drilling operations exposes us to volatilitymaintaining insurance in the quality, pricesfuture, and availability of such items, as well as poor customer service in general. Certain high specification parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production
disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenues by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs.
Somesome of our operating riskslosses may not be covered by insurance.
We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution, reservoir damage and other damages and losses. Ourtypes 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 is subject to deductibles and self-insured retentions which must be met prior toon any recovery. Additionally,of our insurance is subject to exclusions and limitations, and wedrilling units located in the US GOM.
We can provide no assurance that suchour insurance coverage will adequately protect us against liability from potential consequences and damages.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 a material adverse effectaffects on our financial position, results of operations and cash flows.
Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence. This coverage does not include damage arising from a US GOM named windstorm, for which we are self-insured.
We maintain insurance policies providing coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability), automobile liability and aviation liability, and these policies are subject to various deductibles and underlying limits. In addition, we maintain excess liability coverage with an annual aggregate limit of $700 million subject to a self-insured retention of $10 million except in cases of liabilities (including removal of wreck) arising out of US GOM named windstorms, which are subject to a self-insured retention of $200 million per occurrence.
Our rig physical damage and liability insurance renews each June. We can provide no assurance we will be able to secure coverage of a similar nature with similar limits at comparable costs.
Our contractual indemnification provisions may not be sufficient to cover our liabilities.
Our drilling contracts provide for varying levels of indemnification and allocation of liabilities between our customers and usthe 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 against liabilities varies from contract to contract based on market conditions and customer requirements existing when the contract was negotiated.negotiated, and recovery is dependent on the customer's financial condition. Our drilling contracts generally indemnify us for injuries and death of our customers’ employees and loss or damage to our customers’ property. Our service agreements generally indemnify us for injuries and death of our service providers’ employees. However, the enforceability of our indemnities may be subject to differing interpretations, or further limited or prohibited under applicable law, or by contract, particularly in cases of gross negligence, willful misconduct, punitive damages or punitive fines and/or penalties. For example, in 2012 a U.S. District Court in the Eastern District of Louisiana invalidated certain contractual indemnities for punitive damages and for civil penalties in a drilling contract governed by U.S. maritime law as a matter of public policy. We could therefore be liable for certain liabilities even in cases where we have contractual indemnification rights. Notwithstanding a contractual indemnity from a customer, there can be no assurance that our customers will be financially able to indemnify us or will otherwise honor their contractual indemnity obligations. The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from or unenforceable under contractual indemnification obligations could have a material adverse effect onwould adversely affect our financial position, results of operations and cash flows.
Our information technology systems are subject to cybersecurity risks and threats.
We depend heavily on technologies, systems and networks that we manage, and others that are managed by our third-party service and equipment providers or customers, to conduct our business and operations. Cybersecurity risks and threats to such systems continue to grow and may be difficult to anticipate, prevent, identify or mitigate. If any of our, our service providers' or our customers' security systems prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our companies’, employees’, vendors’ or customers’ confidential or proprietary information altered, lost or stolen, or our (or our customers’) business operations, 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 obtaincomply 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 business in eachoperations. In the past, during periods of the areas of our operations. To the extent thathigh demand for drilling services and the size of theincreasing worldwide industry fleet increase (including due to the impact of newly constructed rigs),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 arise, creatingresult in our loss of qualified personnel to competitors, impair the timeliness and quality of our work and create upward pressure on wages and difficulty in staffing and servicing our rigs, which could, in turn, adversely affect our results of operations. In addition, the entrance of new participants into the offshore drilling market would cause further competition for qualified and experienced personnel as these entities seekcosts. If we are unable to hire personnel with expertise in the offshore drilling industry. The heightened competition forretain or train skilled personnel, could adversely impact our financial position, results of operations and cash flows by limiting our operations or further increasing our costs.
We are involved in litigation and legal proceedings from time to time that could have a negative effect on us if determined adversely.
We are, from time to time, involved in various legal proceedings, which may include, among other things, contract dispute,disputes, personal injury, environmental, toxic tort, employment, tax and securities litigation, governmental investigations or proceedings, and litigation that arises in the ordinary course of our business. Although we intend to defend any of these matters vigorously, we cannot predict with certainty the outcome or effect of any claim or other litigation matter. Our profitability may be adversely affected by the outcome of claims or contract disputes, including any inability to collect receivables or resolve significant contractual or day rate disputes, and any purported nullification, cancellation or breach of contracts with customers or other parties. Litigation may have an adverse effect on us because of potential negative outcomes, the costs associated with defending the lawsuits, the diversion of resources, reputational damage, and other factors.
A downgradeDowngrades in theour credit ratings of our debt could restrictmay 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 increaseother factors affecting our interest costs.
We currently have investment gradeoperations, as well as our credit ratings, which are subject to review and change by the rating agencies from time to time. There can be no assurance that any particular rating assigned to us will remain in effect for any given period of time or that a rating will not be changed or withdrawn by a rating agency. If ratings for our debt fall below investment grade, our access to the debt capital markets could become restricted.ratings. Tightening in the credit markets and the reduced level of liquidity in many financial markets due to turmoil in the financialcurrent economic environment, concerns about the offshore drilling industry and banking industries could also affectour credit ratings may restrict our access to the credit and debt capital markets or the price we pay to issue debt. Our revolving credit facility includes an increase in interest rates if the ratings for our debt are downgraded. Further, an increase in the levelfuture 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 indebtedness may increase our vulnerability to adverse general economiccapital requirements, debt obligations and industry conditionscontractual commitments, and may affect our ability to obtain additional financing.
We have entered into intercompany loan agreements that could affect our business, financial position, and ability to enter into financial transactions, including the payment of dividends.
In connection with our restructuring, Rowan plc and its subsidiaries have entered into intercompany debt arrangements which contain negative covenants that limit our ability to, among other things:
Create liens
Incur other indebtedness or guarantee other indebtedness
Make dividends or other distributions of cash or property
Repurchase or redeem shares
Make investments
Change the nature of our business or operations
Redeem indebtedness
Merge or consolidate or enter into transactions with affiliates
Sell assets including capital shares of subsidiaries
Enter into agreements that restrict dividends from subsidiaries
The agreements also contain affirmative covenants such as mandatory prepayments upon consolidated excess cash balances or material dispositions and other customary events of default, including a cross-default upon the acceleration due to default of any other debt in a principal amount in excess of one million dollars. In addition, debtor subsidiaries are required to maintain adequate total equity and adequate debt-to-equity ratios as identified in each such agreement.
If an event of default has occurred and is continuing and has not been cured or waived by the lending subsidiary, then the payment of any intercompany indebtedness could be accelerated, and such paymentinsufficiency could have an adverse impact on our ability to pay dividends or make other capital allocations.business.
We depend heavily upon the securityCertain credit rating agencies have downgraded our credit ratings below investment grade and reliability ofmay further downgrade our technology systems and those ofcredit ratings at any time. A further downgrade in our service providers, and such systems are subject to cybersecurity risks and threats.
We depend heavilyratings could have adverse consequences on technologies, systems and networks that we manage, and others that are managed by our third-party service and equipment providers, to conduct our business and operations. Cybersecurity risksfuture prospects, including the following:
Restrict our ability to access credit and threatsdebt capital markets;
Cause us to such systems continuerefinance or issue debt with less favorable terms and conditions;
Negatively impact current and prospective customers’ willingness to grow in sophisticated ways that avoid detectiontransact business with us;
Impose additional insurance, guarantee and may be difficultcollateral requirements; or
Limit our access to anticipate, prevent or mitigate. If anybank and third-party guarantees, surety bonds and letters of our or our service or equipment providers’ security systems for protecting against cybersecurity breaches or failures prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our companies’, employees’, vendors’ or customers’ confidential or proprietary information altered, lost or stolen, or our (or our customers’) business operations or safety
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.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.
Transocean holds U.S. and other patents for dual activity drilling equipment and has pursued litigation against several other offshore drilling contractors. Transocean could choose to sue us or our customers for infringing its patents if it believes that we are using technology covered by its patent on our drillships, and we could be forced to modify our drillships and/or pay royalties to Transocean in the event that a Court were to find that any Transocean patents are infringed.
Failure to comply with anti-corruption and anti-bribery laws could result in fines, criminal penalties and drilling contract terminations and could have an adverse impact on our business.
The U.S. Foreign Corrupt Practices Act (FCPA), the U.K. Bribery Act 2010 (UK Bribery Act) and similar laws in other jurisdictions generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We have operated and may in the future operate in parts of the world where strict compliance with anti-corruption and anti-bribery laws may conflict with local customs and practices. Any failure to comply with the FCPA, UK Bribery Act, or other anti-corruption laws due to our own acts or omissions or the acts or omissions of others, including our partners, agents or vendors, could subject us to civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial position, results of operations or cash flows. We could also face fines, sanctions and other penalties from authorities in the relevant foreign jurisdictions, including prohibition of our participation in or curtailment of business operations in those jurisdictions and the seizure of drilling units or other assets.
Unionization efforts and labor regulations in certain countries in which we operate could materially increase our costs or limit our flexibility.
Certain of our employees and contractors in international markets,various regions such as Trinidad Norway and Angola,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 revenuesrevenue or limit our operations.
Supplier capacity constraints or shortages in parts or equipment, supplier production disruptions, supplier quality and sourcing issues or price increases could increase our operating costs, decrease our revenue and adversely impact our operations.
Our reliance on third-party suppliers, manufacturers and service providers to secure equipment used in our drilling operations could expose us to volatility in the quality, price and availability of such items. Certain specialized parts and equipment we use in our operations may be available only from a single or small number of suppliers. A disruption in the deliveries from such third-party suppliers, capacity constraints, production disruptions, price increases, defects or quality-control issues, recalls or other decreased availability or servicing of parts and equipment could adversely affect our ability to meet our commitments to customers, adversely impact our operations and revenue by resulting in uncompensated downtime, reduced day rates or the cancellation or termination of contracts, or increase our operating costs. Our reliance on one or more of these third-party suppliers could further exacerbate such issues.
The enforcement of civil liabilities against Rowan plc may be more difficult.
Because Rowan plc is a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against Rowan plc in U.S. courts than would be the case for U.S. judgments obtained against a U.S. company. In addition, it may be more difficult to bring some types of claims against Rowan plc in courts in the U.K. than it would be to bring similar claims against a U.S. company in a U.S. court.
Our articles of association include mandatory offer provisions that may have the effect of discouraging, delaying or preventing hostile takeovers, including those that might result in a premium being paid over the market price of our shares, and discouraging, delaying or preventing changes in control or management.
Although Rowan plc is not currently subject to the U.K. Takeover Code, certain provisions similar to the mandatory offer provisions and certain other aspects of the U.K. Takeover Code are included in our articles of association. As a result, among other matters, except with the consent of our Board or the prior approval of the shareholders, a Rowan plc shareholder, that together with persons acting in concert, would be at risk of certain Board sanctions if they acquired 30 percent or more of our issued shares without
making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative.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 increased shareholder approval requirements required under U.K. law, we may have less flexibility as a U.K. public limited company than as a Delaware corporation with respect to certain aspects of capital management.
Under DelawareUnlike most U.S. state corporate law, directors may issue, without further stockholder approval, any shares authorized in a company’s certificate of incorporation that are not already issued or reserved. Delaware law also provides substantial flexibility in establishing the terms of preferred shares. However, English law provides that a board of directors may generally only allot shares with the prior authorization of shareholders;shareholders, which such authorization must state the maximum amount of shares that may be allotted and may only beextend for a maximum period of five years.
English law also generally provides shareholders with preemptive rights when new shares are issued for cash while Delaware law does not. However, it is possible forunless such rights are waived by the articles of association, or shareholders in a general meeting, to exclude preemptive rights for a maximum period of up to five years from the date of adoption of the exclusion.
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, by special resolution (i.e., 75 percent of votes cast), which approval lastsmay only extend for a maximum period of five years.
PriorAt our 2017 annual general meeting of shareholders, our Board was authorized to the redomestication, resolutions were adopted to authorize the allotment ofallot a certain amount of shares, exclude certain preemptive rights in shares for cash offerings and permiteffect off market purchases, in each case without further shareholder approval, butapproval. However, these authorizations will expire in 2017May 2018. As such, we will be unable to issue new shares or repurchase shares unless furtherand 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 prior to the expiration date.
We cannot assure you that situations will not arise where U.K. shareholder approval requirements for the extension or expansion of any of these actions would deprive our shareholders of substantial capital management benefits.
We have incurred higher costs(such as a result ofshare buyback) if the redomesticationcompany has sufficient distributable reserves and meets certain net asset requirements. If we expectdo not have sufficient distributable reserves or cannot meet the net asset requirements, we may be limited in our ability to continuetimely pay dividends and effect other distributions to do so.
our shareholders.
The redomestication has resulted in an increase in someU.K.’s referendum to exit from the E.U. will have uncertain effects and could adversely impact our business, results of our ongoing expensesoperations and increased compliance costs with regulatory requirements. Some costs, including those relatedfinancial condition.
On June 23, 2016, the U.K. voted to financial reporting requirementsexit from the E.U. (commonly referred to as Brexit). The terms of Brexit and governance, such as holding management, board and shareholder meetingsthe resulting U.K./E.U. relationship are uncertain for companies doing business both in the U.K., are higher than would 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 caseU.K. Risks related to Brexit that we may encounter include:
adverse impact on macroeconomic growth and oil and gas demand;
continued volatility in currencies including the British pound and USD that may impact our financial results;
reduced demand for our services in the U.K. and globally;
increased costs of doing business in the U.K. and in the North Sea;
increased regulatory costs and challenges for operating our business in the North Sea;
volatile capital and debt markets, and access to other sources of capital;
risks related to our global tax structure and the tax treaties upon which we rely;
business uncertainty resulting from prolonged political negotiations; and
uncertain stability of the E.U. and global economy if we had remained a U.S. company. Additionally, we have incurred and expect to continue to incur higher professional fees and other costs to comply with U.K. corporate securities and tax laws.countries exit the E.U.
ITEM 1B. UNRESOLVED STAFF COMMENTS
The Company has no unresolved SEC staff comments.
ITEM 2. PROPERTIES
Our primary U.S. offices are located in 140,314 square feet of leased space in two office towers in Houston, Texas. Additionally, we own or lease other office, maintenance and warehouse facilities in Texas, Scotland,the U.S., Saudi Arabia Qatar,(primarily for ARO operations), Norway, Scotland, Trinidad, Norway, South Korea, Indonesia,Bahrain, Dubai, Luxembourg and Malaysia.
Egypt.
Drilling Rigs
Following areis the principal drilling equipment owned by usRowan and theirits location at February 19, 2015. Water depths are the "rated" water depths; actual water depths may vary depending on operating location:13, 2018.
|
| | | | | |
| | | Depth (feet) | | |
| Rig Name/Type | Class Name | Water (6) | Drilling (7) | Year of Shipyard Delivery | Location |
| | | | | | |
| Ultra-Deepwater Drillships: | | | | | |
| Rowan Renaissance | Gusto MSC P10,000 | 12,000 | 40,000 | 2014 | US GOM |
| Rowan Resolute | Gusto MSC P10,000 | 12,000 | 40,000 | 2014 | US GOM |
| Rowan Reliance | Gusto MSC P10,000 | 12,000 | 40,000 | 2014 | US GOM |
| Rowan Relentless | Gusto MSC P10,000 | 12,000 | 40,000 | 2015 | US GOM |
| | | | | | |
| Jack-ups: | | | | | |
Rowan Norway (1) | N-Class | 400 | 35,000 | 2011 | U.K. |
Rowan Stavanger (1) | N-Class | 400 | 35,000 | 2011 | Norway |
Rowan Viking (1) | N-Class | 435 | 35,000 | 2010 | Norway |
Bob Palmer (1) (5) | Super Gorilla XL | 475 | 35,000 | 2003 | Saudi Arabia |
Rowan Gorilla VII (1) | Super Gorilla | 400 | 35,000 | 2001 | U.K. |
Rowan Gorilla VI (1) | Super Gorilla | 400 | 35,000 | 2000 | Trinidad |
Rowan Gorilla V (1) | Super Gorilla | 400 | 35,000 | 1998 | U.K. |
Joe Douglas (1) | 240C | 350 | 35,000 | 2012 | Trinidad |
Ralph Coffman (1) | 240C | 350 | 35,000 | 2009 | In-transit to US GOM |
Rowan Mississippi (1) (5) | 240C | 375 | 35,000 | 2008 | Saudi Arabia |
Rowan EXL IV (1) | EXL | 320 | 35,000 | 2011 | Bahrain |
Rowan EXL III (1) | EXL | 350 | 35,000 | 2010 | US GOM |
Rowan EXL II (1) | EXL | 350 | 35,000 | 2010 | Trinidad |
Rowan EXL I (1) | EXL | 350 | 35,000 | 2010 | Bahrain |
P-59 (2) (4) | Super 116E | 350 | 30,000 | 2013 | Brazil |
P-60 (2) (4) | Super 116E | 350 | 30,000 | 2013 | Brazil |
Hank Boswell (1) (5) | Tarzan | 300 | 35,000 | 2006 | Saudi Arabia |
Scooter Yeargain (1) (5) | Tarzan | 300 | 35,000 | 2004 | Saudi Arabia |
Rowan California (2)(3) | 116C | 300 | 25,000 | 1983 | Bahrain |
Arch Rowan (2) (5) | 116C | 300 | 25,000 | 1981 | Saudi Arabia |
Charles Rowan (2) (5) | 116C | 300 | 25,000 | 1981 | Saudi Arabia |
Rowan Middletown (2) (5) | 116C | 300 | 25,000 | 1980 | Saudi Arabia |
Rowan Gorilla IV (1) (3) | Gorilla | 450 | 30,000 | 1986 | US GOM |
|
| | | | | |
| | | Depth (feet)(1) | | |
| Rig Name | Class Name/Type | Water | Drilling | Year in service/ significant refurbishment | Location |
| | | | | | |
| Ultra-Deepwater Drillships: | | | | | |
| Rowan Renaissance | Gusto MSC P10,000 | 12,000 | 40,000 | 2014 | West Africa |
| Rowan Resolute | Gusto MSC P10,000 | 12,000 | 40,000 | 2014 | US GOM |
| Rowan Reliance | Gusto MSC P10,000 | 12,000 | 40,000 | 2015 | US GOM |
| Rowan Relentless (under construction) | Gusto MSC P10,000 | 12,000 | 40,000 | 2015 (est.) | Shipyard |
| | | | | | |
High-Specification Jack-ups: (2) | | | | | |
Rowan Norway (3) | N-Class | 400 | 35,000 | 2011 | Norway |
Rowan Stavanger (3) | N-Class | 400 | 35,000 | 2011 | U.K. North Sea |
Rowan Viking (3) | N-Class | 400 | 35,000 | 2011 | Norway |
Rowan EXL IV (3) | EXL | 350 | 40,000 | 2011 | Malaysia |
Rowan EXL III (3) | EXL | 350 | 40,000 | 2011 | US GOM |
Rowan EXL II (3) | EXL | 350 | 35,000 | 2011 | Trinidad |
Rowan EXL I (3) | EXL | 350 | 35,000 | 2010 | Malaysia |
Joe Douglas (3) | 240C | 375 | 35,000 | 2012 | US GOM |
Ralph Coffman (3) | 240C | 375 | 35,000 | 2009 | Tunisia |
Rowan Mississippi (3) | 240C | 375 | 35,000 | 2008 | Middle East |
J.P. Bussell (3) | Tarzan | 300 | 35,000 | 2008 | Malaysia |
Hank Boswell (3) | Tarzan | 300 | 35,000 | 2006 | Middle East |
Bob Keller (3) | Tarzan | 300 | 35,000 | 2005 | Middle East |
Scooter Yeargain (3) | Tarzan | 300 | 35,000 | 2004 | Middle East |
Bob Palmer (3) | Super Gorilla XL | 490 | 35,000 | 2003 | Middle East |
Rowan Gorilla VII (4) | Super Gorilla | 450 | 35,000 | 2002 | U.K. North Sea |
Rowan Gorilla VI (4) | Super Gorilla | 450 | 35,000 | 2000 | Norway |
Rowan Gorilla V (4) | Super Gorilla | 400 | 35,000 | 1998 | U.K. North Sea |
Rowan Gorilla IV (3) | Gorilla | 450 | 35,000 | 1986 | US GOM |
| | | | | | |
Premium Jack-ups: (5) | | | | | |
Rowan Gorilla III (3) | Gorilla | 450 | 30,000 | 1984 | Trinidad |
Rowan Gorilla II (3) | Gorilla | 480 | 30,000 | 1984 | Indonesia |
Rowan California (3) | 116C | 300 | 25,000 | 1983 | Middle East |
Cecil Provine (3) | 116C | 300 | 30,000 | 1982 | US GOM |
Gilbert Rowe (3) | 116C | 300 | 30,000 | 1981/2013 | Middle East |
Arch Rowan (3) | 116C | 350 | 30,000 | 1981 | Middle East |
Charles Rowan (3) | 116C | 350 | 30,000 | 1981 | Middle East |
Rowan Middletown (3) | 116C | 300 | 30,000 | 1980 | Middle East |
| | | | | | |
Conventional Jack-ups: (6) | | | | | |
| Rowan Juneau | Slot | 250 | 30,000 | 1977 | US GOM |
| Rowan Alaska | Slot | 350 | 25,000 | 1975 | US GOM |
Rowan Louisiana (3) | Slot | 350 | 30,000 | 1975/2006 | US GOM |
(1) Indicates rated water and drilling depths.
(2) High-specification rigs are those that havejack-up, which is defined as having hook-load capacity of at least two million pounds.
(3) Unit(2) Premium jack-up, which is equipped with three mud pumps.
(4) Unit is equipped with four mud pumps.
(5) Premium jack-ups aredefined as an independent leg, cantilevered rigsrig capable of operating in water depths of 300 feet or more.
(3) Currently cold-stacked.
(4) Purchased in January 2018 and not yet placed in service.
(5) Managed by ARO.
(6) UnitsWater depths are equipped with skid-off capability, which is described under “Drilling Fleet” in Item 1, Business. The Rowan Juneau,Rowan Alaska the maximum "rated" depths as currently outfitted.
(7) Maximum estimated drilling depth, subject to well characteristics and Rowan Louisiana are currently cold-stacked.rig outfitting.
ITEM 3. LEGAL PROCEEDINGS
We are involved in various routine legal proceedings incidental to our businesses and are vigorously defendingdefend our position in all such matters. WeAlthough the outcome of such proceedings cannot be predicted with certainty, we believe there are no known contingencies, claims or lawsuits that couldwill have a material adverse effect on our financial position, results of operations or cash flows.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions and ages of the executive officers of the Company as of March 2, 2015, are listed below. Our executive officers are appointed by the Board of Directors and serve at the discretion of the Board of Directors. There are no family relationships among these officers, nor any arrangements or understandings between any officer and any other person pursuant to which the officer was selected.
|
| | |
Name | Position | Age |
| | |
W. Matt Ralls | Executive Chairman | 65 |
Thomas P. Burke | President and Chief Executive Officer | 47 |
Stephen M. Butz | Executive Vice President, Chief Financial Officer and Treasurer | 43 |
Mark A. Keller | Executive Vice President, Business Development | 62 |
Melanie M. Trent | Executive Vice President, General Counsel, Chief Administrative Officer and Company Secretary | 50 |
Gregory M. Hatfield | Vice President and Controller | 45 |
Mr. Ralls was appointed Executive Chairman of the Board in April 2014. Prior to that time, Mr. Ralls served as President and Chief Executive Officer and a director since January 2009 until his retirement as Chief Executive Officer in April 2014. Mr. Ralls currently serves as a director of Cabot Oil & Gas Corporation and Superior Energy Services.
Dr. Burke was appointed Chief Executive Officer and elected a director of the Company in April 2014. He served as Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Dr. Burke first joined the Company in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011.
Mr. Butz became Executive Vice President, Chief Financial Officer and Treasurer upon joining the Company in December 2014. Prior to that time, Mr. Butz served as Executive Vice President and Chief Financial Officer at Hercules Offshore, Inc. He was Senior Vice President and Chief Financial Officer from 2010 to 2013 and held a number of other key positions since joining Hercules Offshore in 2005, including Director of Corporate Development and Vice President, Finance and Treasurer.
Since January 2007, Mr. Keller’s principal occupation has been Executive Vice President, Business Development.
Ms. Trent became Executive Vice President and General Counsel in September 2014. Prior to that time, Ms. Trent served as Senior Vice President, Chief Administrative Officer and Company Secretary since July 2011. From March 2010 to July 2011, she served as Vice President and Corporate Secretary. Ms. Trent has served as Corporate Secretary since she joined the Company in 2005.
Mr. Hatfield has served as Vice President and Controller since March 2010. From May 2005 to March 2010, he served as Controller.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON STOCK, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Our shares are listed on the NYSE under the symbol “RDC.” The following table sets forth the high and low sales prices of our shares for each quarterly period within the two most recent years as reported byon the NYSE Consolidated Transaction Reporting System.
for the periods indicated.
| | | | | 2014 | | 2013 | | 2017 | | 2016 |
| Quarter | | High | | Low | | High | | Low | | High | | Low | | High | | Low |
| First | | $ | 35.17 |
| | $ | 31.13 |
| | $ | 36.85 |
| | $ | 31.55 |
| | $ | 20.50 |
| | $ | 14.05 |
| | $ | 18.43 |
| | $ | 10.67 |
|
| Second | | 33.78 |
| | 29.50 |
| | 36.51 |
| | 30.21 |
| | 15.96 |
| | 10.04 |
| | 19.94 |
| | 14.58 |
|
| Third | | 32.16 |
| | 24.96 |
| | 38.65 |
| | 33.86 |
| | 13.07 |
| | 9.02 |
| | 19.06 |
| | 12.00 |
|
| Fourth | | 25.63 |
| | 19.50 |
| | 37.81 |
| | 32.75 |
| | 15.79 |
| | 12.35 |
| | 21.68 |
| | 13.02 |
|
On January 31, 2015,February 21, 2018, there were 7572 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.
The following table sets forth the per share quarterly cash dividends declared during the two most recent fiscal years. No dividends were declared in 2013.
|
| | | | |
Quarter | | 2014 |
First | | $ | — |
|
Second | | 0.10 |
|
Third | | 0.10 |
|
Fourth | | 0.10 |
|
OnIn January 29, 2015, the2016, our Board of Directors approved a quarterly cashdiscontinued dividend of $0.10 per share payable on March 3, 2015, to shareholders of record at the close of business on February 9, 2015.payments.
The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment & Services Index, and the S&P 500 Index for the five-year period ended December 31, 2014,2017, assuming reinvestment of dividends.
| | | | 12/31/2009 | | 12/31/2010 | | 12/31/2011 | | 12/31/2012 | | 12/31/2013 | | 12/31/2014 | | 12/31/2012 | | 12/31/2013 | | 12/31/2014 | | 12/31/2015 | | 12/31/2016 | | 12/31/2017 |
| Rowan | 100.00 |
| | 154.20 |
| | 133.97 |
| | 138.12 |
| | 156.18 |
| | 104.13 |
| | 100.00 |
| | 113.08 |
| | 75.39 |
| | 55.89 |
| | 62.28 |
| | 51.63 |
|
| S&P 500 Index | 100.00 |
| | 115.06 |
| | 117.49 |
| | 136.30 |
| | 180.44 |
| | 205.14 |
| | 100.00 |
| | 132.39 |
| | 150.51 |
| | 152.59 |
| | 170.84 |
| | 208.14 |
|
| Dow Jones US Oil Equipment & Services Index | 100.00 |
| | 127.34 |
| | 111.51 |
| | 111.88 |
| | 143.66 |
| | 118.91 |
| | 100.00 |
| | 128.41 |
| | 106.29 |
| | 82.40 |
| | 104.91 |
| | 87.38 |
|
Issuer Purchases of Equity Securities
The following table summarizespresents information with respect to acquisitions of our shares for the fourth quarter of 2014:
2017:
|
| | | | | | | | | | | | | | |
| Month ended | | Total number of shares purchased 1 | | Average price paid per share 1 | | Total number of shares purchased as part of publicly announced plans or programs2 | | Approximate dollar value of shares that may yet be purchased under the plans or programs2 |
| Balance forward | | | | | | | | $ | — |
|
| October 31, 2014 | | 4,642 |
| | $ | 22.57 |
| | — |
| | — |
|
| November 30, 2014 | | 1,678 |
| | $ | 23.84 |
| | — |
| | — |
|
| December 31, 2014 | | 1,792 |
| | $ | 22.16 |
| | — |
| | — |
|
| Total | | 8,112 |
| | $ | 22.74 |
| | — |
| | |
|
| | | | | | | | | |
| | | | | | | | | |
1 The total number of shares acquired includes shares acquired from employees by an affiliated employee benefit trust upon forfeiture of nonvested awards or in satisfaction of tax withholding requirements and shares purchased, if any, pursuant to a publicly announced share repurchase program. The price paid for shares acquired as a result of forfeitures is the par value of $0.125 per share. The price paid for shares acquired in satisfaction of withholding taxes is the share price on the date of the transaction. There were no shares repurchased under any share repurchase program during the fourth quarter of 2014.
|
2 The ability to make share repurchases is subject to the discretion of the Board of Directors and the limitations set forth in the Companies Act, which generally provide that share repurchases may only be made out of distributable reserves. In addition, U.K. law also generally prohibits a company from repurchasing its own shares through “off market purchases” without the prior approval of shareholders, which approval lasts for a maximum period of five years. Prior to and in connection with the redomestication, the Company obtained approval to purchase its own shares. To effect such repurchases, the Company entered into a purchase agreement with a specified dealer in July 2012, pursuant to which the Company may purchase up to a maximum of 50,000,000 shares over a five-year period, subject to an annual cap of 10% of the shares outstanding at the beginning of each applicable year. Subject to Board approval, share repurchases may be commenced or suspended from time to time without prior notice and, in accordance with the shareholder approval and U.K. law, any shares repurchased by the Company will be cancelled. The authority to repurchase shares terminates in April 2017 unless otherwise reapproved by the Company’s shareholders prior to that time. U.K. law prohibits the Company from purchasing its shares in the open market because they are not traded on a recognized investment exchange in the U.K.
|
|
| | | | | | | | | | | | | | |
| Month ended | | Total number of shares purchased (1) | | Average price paid per share (1) | | Total number of shares purchased as part of publicly announced plans or programs (2) | | Approximate dollar value of shares that may yet be purchased under the plans or programs (2) |
| October 1 - 31, 2017 | | 1,996 |
| | $ | 12.71 |
| | — |
| | $ | — |
|
| November 1 - 30, 2017 | | 168 |
| | $ | 13.90 |
| | — |
| | $ | — |
|
| December 1 - 31, 2017 | | 7,996 |
| | $ | 14.99 |
| | — |
| | $ | — |
|
| Total | | 10,160 |
| | $ | 14.52 |
| | — |
| | |
|
| | | | | | | | | |
| (1) The total number of shares acquired includes shares acquired from employees by an affiliated EBT in satisfaction of tax withholding requirements. The price paid for shares acquired in satisfaction of withholding taxes is the share price on the date of the transaction. There were no shares repurchased under any share repurchase program during the fourth quarter of 2017. |
| (2) The ability to make share repurchases is subject to the discretion of our Board and the limitations set forth in the U.K. Companies Act of 2006, which generally provide that share repurchases may only be made out of distributable reserves. At our 2017 general meeting of shareholders on May 25, 2017, our shareholders approved new repurchase agreements and counterparties, which approval will remain valid until May of 2022. Our Board has authority to commence or suspend share repurchase programs from time to time without prior notice pursuant to these approved repurchase agreements. There are no share repurchase programs outstanding at December 31, 2017. |
ITEM 6. SELECTED FINANCIAL DATA
Selected financial data for each of the last five years is presented below:
| | | | 2014 | | 2013 | | 2012 | | 2011 | | 2010 | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (Dollars in thousands, except per share amounts) | (Dollars in millions, except per share amounts) |
| Operations | | | | | | | | | | | | | | | | | | |
| Revenues | $ | 1,824,383 |
| | $ | 1,579,284 |
| | $ | 1,392,607 |
| | $ | 939,229 |
| | $ | 1,017,705 |
| |
| Revenue | | $ | 1,282.8 |
| | $ | 1,843.2 |
| | $ | 2,137.0 |
| | $ | 1,824.4 |
| | $ | 1,579.3 |
|
| Costs and expenses: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items shown below) | 991,340 |
| | 860,893 |
| | 752,173 |
| | 508,066 |
| | 416,832 |
| 684.8 |
| | 778.2 |
| | 993.1 |
| | 991.3 |
| | 860.9 |
|
| Depreciation and amortization | 322,641 |
| | 271,008 |
| | 247,900 |
| | 183,903 |
| | 138,301 |
| 403.7 |
| | 402.9 |
| | 391.4 |
| | 322.6 |
| | 271.0 |
|
| Selling, general and administrative | 125,834 |
| | 131,373 |
| | 99,712 |
| | 88,278 |
| | 78,658 |
| 104.9 |
| | 102.1 |
| | 115.8 |
| | 125.8 |
| | 131.3 |
|
Gain on sale of assets to unconsolidated subsidiary (1) | | (157.4 | ) | | — |
| | — |
| | — |
| | — |
|
| (Gain) loss on disposals of property and equipment | (1,778 | ) | | (20,119 | ) | | (2,502 | ) | | (1,577 | ) | | 402 |
| 9.4 |
| | 8.7 |
| | (7.7 | ) | | (1.7 | ) | | (20.1 | ) |
Litigation settlement (1) | (20,875 | ) | | — |
| | (4,700 | ) | | 6,100 |
| | — |
| |
Material charges and other operating expenses (2) | 573,950 |
| | 4,453 |
| | 44,972 |
| | 4,876 |
| | 5,250 |
| |
Gain on litigation settlement (2) | | — |
| | — |
| | — |
| | (20.9 | ) | | — |
|
Material charges and other operating items (3) | | — |
| | 32.9 |
| | 337.3 |
| | 574.0 |
| | 4.5 |
|
| Total costs and expenses | 1,991,112 |
| | 1,247,608 |
| | 1,137,555 |
| | 789,646 |
| | 639,443 |
| 1,045.4 |
| | 1,324.8 |
| | 1,829.9 |
| | 1,991.1 |
| | 1,247.6 |
|
| Equity in earnings from unconsolidated subsidiary | | 0.9 |
| | — |
| | — |
| | — |
| | — |
|
| Income (loss) from operations | (166,729 | ) | | 331,676 |
| | 255,052 |
| | 149,583 |
| | 378,262 |
| 238.3 |
| | 518.4 |
| | 307.1 |
| | (166.7 | ) | | 331.7 |
|
| Other income (expense) — net | (102,878 | ) | | (70,437 | ) | | (71,582 | ) | | (19,503 | ) | | (18,727 | ) | |
| Income (loss) from continuing operations, before income taxes | (269,607 | ) | | 261,239 |
| | 183,470 |
| | 130,080 |
| | 359,535 |
| |
Other income (expense) — net (4) | | (139.0 | ) | | (192.8 | ) | | (149.4 | ) | | (102.9 | ) | | (70.5 | ) |
| Income (loss) from continuing operations before income taxes | | 99.3 |
| | 325.6 |
| | 157.7 |
| | (269.6 | ) | | 261.2 |
|
| Provision (benefit) for income taxes | (150,732 | ) | | 8,663 |
| | (19,829 | ) | | (5,659 | ) | | 91,934 |
| 26.6 |
| | 5.0 |
| | 64.4 |
| | (150.7 | ) | | 8.6 |
|
| Income (loss) from continuing operations | (118,875 | ) | | 252,576 |
| | 203,299 |
| | 135,739 |
| | 267,601 |
| 72.7 |
| | 320.6 |
| | 93.3 |
| | (118.9 | ) | | 252.6 |
|
Discontinued operations, net of taxes (3) | 4,023 |
| | — |
| | (22,697 | ) | | 601,102 |
| | 12,394 |
| |
Discontinued operations, net of taxes (5) | | — |
| | — |
| | — |
| | 4.0 |
| | — |
|
| Net income (loss) | $ | (114,852 | ) | | $ | 252,576 |
| | $ | 180,602 |
| | $ | 736,841 |
| | $ | 279,995 |
| $ | 72.7 |
| | $ | 320.6 |
| | $ | 93.3 |
| | $ | (114.9 | ) | | $ | 252.6 |
|
| Basic income (loss) per common share: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Income (loss) from continuing operations | $ | (0.96 | ) | | $ | 2.04 |
| | $ | 1.65 |
| | $ | 1.09 |
| | $ | 2.29 |
| $ | 0.58 |
| | $ | 2.56 |
| | $ | 0.75 |
| | $ | (0.96 | ) | | $ | 2.04 |
|
| Income (loss) from discontinued operations | 0.03 |
| | — |
| | (0.18 | ) | | 4.80 |
| | 0.10 |
| — |
| | — |
| | — |
| | 0.03 |
| | — |
|
| Net income (loss) | $ | (0.93 | ) | | $ | 2.04 |
| | $ | 1.47 |
| | $ | 5.89 |
| | $ | 2.39 |
| $ | 0.58 |
| | $ | 2.56 |
| | $ | 0.75 |
| | $ | (0.93 | ) | | $ | 2.04 |
|
| Diluted income (loss) per common share: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Income (loss) from continuing operations | $ | (0.96 | ) | | $ | 2.03 |
| | $ | 1.64 |
| | $ | 1.07 |
| | $ | 2.25 |
| $ | 0.57 |
| | $ | 2.55 |
| | $ | 0.75 |
| | $ | (0.96 | ) | | $ | 2.03 |
|
| Income (loss) from discontinued operations | 0.03 |
| | — |
| | (0.18 | ) | | 4.76 |
| | 0.11 |
| — |
| | — |
| | — |
| | 0.03 |
| | — |
|
| Net income (loss) | $ | (0.93 | ) | | $ | 2.03 |
| | $ | 1.46 |
| | $ | 5.83 |
| | $ | 2.36 |
| $ | 0.57 |
| | $ | 2.55 |
| | $ | 0.75 |
| | $ | (0.93 | ) | | $ | 2.03 |
|
| | | | | | | | | | | |
| Financial Position | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | 339,154 |
| | $ | 1,092,844 |
| | $ | 1,024,008 |
| | $ | 438,853 |
| | $ | 437,479 |
| $ | 1,332.1 |
| | $ | 1,255.5 |
| | $ | 484.2 |
| | $ | 339.2 |
| | $ | 1,092.8 |
|
| Property, plant and equipment — net | $ | 7,432,212 |
| | $ | 6,385,755 |
| | $ | 6,071,729 |
| | $ | 5,678,713 |
| | $ | 4,344,522 |
| |
| Property and equipment — net | | $ | 6,552.7 |
| | $ | 7,060.0 |
| | $ | 7,405.8 |
| | $ | 7,432.2 |
| | $ | 6,385.8 |
|
| Total assets | $ | 8,411,192 |
| | $ | 7,975,761 |
| | $ | 7,699,487 |
| | $ | 6,597,845 |
| | $ | 6,217,457 |
| $ | 8,458.3 |
| | $ | 8,675.6 |
| | $ | 8,347.3 |
| | $ | 8,392.3 |
| | $ | 7,975.8 |
|
| Current portion of long-term debt | | $ | — |
| | $ | 126.8 |
| | $ | — |
| | $ | — |
| | $ | — |
|
| Long-term debt, less current portion | $ | 2,807,324 |
| | $ | 2,008,700 |
| | $ | 2,009,598 |
| | $ | 1,089,335 |
| | $ | 1,133,745 |
| $ | 2,510.3 |
| | $ | 2,553.4 |
| | $ | 2,692.4 |
| | $ | 2,788.5 |
| | $ | 2,008.7 |
|
| Shareholders’ equity | $ | 4,691,399 |
| | $ | 4,893,761 |
| | $ | 4,531,724 |
| | $ | 4,325,987 |
| | $ | 3,752,310 |
| |
| | | | | | | | | | | |
Shareholders’ equity (6) | | $ | 5,386.1 |
| | $ | 5,113.9 |
| | $ | 4,772.5 |
| | $ | 4,691.4 |
| | $ | 4,893.8 |
|
| Statistical Information | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
Current ratio (4) | 2.82 |
| | 4.50 |
| | 5.61 |
| | 2.46 |
| | 2.88 |
| |
Current ratio (7) | | 6.06 |
| | 3.27 |
| | 2.80 |
| | 2.82 |
| | 4.50 |
|
| Debt to capitalization ratio | 37 | % | | 29 | % | | 31 | % |
| 20 | % |
| 23 | % | 32 | % | | 34 | % | | 36 | % |
| 37 | % |
| 29 | % |
| Book value per share of common stock outstanding | 37.66 |
| | 39.39 |
| | 36.48 |
| | 35.01 |
| | 29.71 |
| $ | 42.66 |
| | $ | 40.76 |
| | $ | 38.24 |
| | $ | 37.66 |
| | $ | 39.39 |
|
| Price range of common stock: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| High | 35.17 |
| | 38.65 |
| | 39.40 |
| | 44.83 |
| | 35.39 |
| $ | 20.50 |
| | $ | 21.68 |
| | $ | 25.13 |
| | $ | 35.17 |
| | $ | 38.65 |
|
| Low | 19.50 |
| | 30.21 |
| | 28.62 |
| | 28.13 |
| | 20.44 |
| $ | 9.02 |
| | $ | 10.67 |
| | $ | 14.63 |
| | $ | 19.50 |
| | $ | 30.21 |
|
| | | | | | | | | | | |
| Cash dividends declared per share | $ | 0.30 |
| | $ | — |
| | $ | — |
| | $ | — |
| | $ | — |
| $ | — |
| | $ | — |
| | $ | 0.40 |
| | $ | 0.30 |
| | $ | — |
|
___________________
| |
| (1) | In 2017, the Company recognized a $157.4 million gain on the sale of assets to ARO. |
| |
| (2) | LitigationGain 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; 2012 – a $4.7 million gain for cash received in connection with a legal settlement; 2011 – a $6.1 million payment to settle a lawsuit in connection with the Company’s obligation under a charter agreement for the Rowan Halifax..
|
| |
(2)(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; 2014 – $574.0 million of noncashnon-cash asset impairment charges; and 2013 – $4.5 million of noncashnon-cash asset impairment charges; 2012 – $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the Rowan EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee; 2011 – $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee; and 2010 – the cost of terminating the Company’s agency agreement in Mexico.charges. |
| |
(3)(4) | In 2016, other income (expense), net includes $31.2 million loss on debt extinguishment. |
| |
| (5) | In 2011, the Company sold its manufacturing and land drilling operations, which were classified as discontinued operations. Operating results for manufacturingIn 2014, we sold a land rig retained from the sale and land drilling have been reclassified to discontinued operations for each year presented.recognized a $4.0 million gain, net of tax. |
| |
(4)(6) | 2017 includes a $206.6 million increase to Retained earnings related to the adoption of ASU No. 2016-16. |
| |
| (7) | Current ratio excludes assets and liabilities of discontinued operations. |
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
OVERVIEW
OUR BUSINESS
Rowan Companies plc isWe are a global provider of offshore contract drilling services to the oil and gas contract drilling servicesindustry, with a focus on high-specification and premium jack-up rigs and high-specification ultra-deepwater drillships, whichdrillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and Jack-ups; however, we now operate in three segments: Deepwater, Jack-ups and ARO. The Deepwater segment includes four ultra-deepwater drillships. The Jack-ups segment is composed of 23 self-elevating jack-up rigs, including two LeTourneau Super 116E jack-up rigs purchased in January 2018 (see Note 19 to our customers useconsolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K) and the impact of the various arrangements with ARO (see Note 1 and 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). The ARO segment is a 50/50 joint venture with Rowan and Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for both exploratory and development drilling.During 2014, we took delivery of three newly constructed drillships: the Rowan Renaissance, which commenced drilling operations offshore West Africa in April 2014; the Rowan Resolute, which commenced operationsoperation in the US GOM in October 2014; and the Rowan Reliance, which commenced operations inArabian Gulf for Saudi Aramco. Our fleet operates worldwide, including the US GOM, in February 2015. Our fourth drillship, the Rowan Relentless, is scheduled for delivery in late March 2015 and is expected to commence operations in the US GOM in the third quarter of 2015.
As of February 19, 2015, the date of our most recent Fleet Status Report, we had six jack-ups in the North Sea, ten in the Middle East, seven in the US GOM (including three cold-stacked rigs), two in Trinidad, three in Malaysia, and one in each of Tunisia and Indonesia. At February 19, 2015, our backlog totaled $5.1 billion compared to $5.0 billion at this time last year.
Revenues for 2014 increased by 16% to $1.824 billion from $1.579 billion in 2013 primarily due to the addition of the Rowan Renaissance and Rowan Resolute. Fleet utilization improved to 82% in 2014 from 81% and 77% in 2013 and 2012, respectively, and fleet average day rates improved to $190,629 in 2014 from $170,912 and $156,306 in 2013 and 2012. Out-of-service days totaled approximately 10% of available rig days in 2014 and 2013, down from 12% in 2012 as a result of decreased shipyard time and fewer rig mobilizations in 2014 and 2013 compared to 2012. We define out-of-service days as those days when a rig is (or planned to be) out of service and is not able to earn revenue. Operational downtime, which is the unbillable time attributable to equipment breakdowns or procedural failures, was approximately 1% of in-service days in 2014 and 2013, down from 2% in 2012.
Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling rigs over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized a noncash asset impairment charge in the fourth quarter of 2014 in the amount of $565.7 million.
RESULTS OF OPERATIONS
Our profitability is primarily a function of our ability to keep our rigs under contract earning operating day rates, offset by any downtime while a rig is under contract. The Company typically receives a reduced day rate or no day rate during periods of downtime. Our ability to obtain contracts for our rigs and the day rates received are primarily determined by the level of oil and gas exploration and development expenditures, which are heavily influenced by trends in oil and natural gas prices and the availability of competitive equipment. When drilling markets are strengthening, day rates generally lag the upward trend in rig utilization, and day rate increases can be more significant as fleet utilization approaches 90% or more. When drilling markets are weakening, contractors often reduce day rates in an effort to maintain fleet utilization. Both rig utilization and day rates have historically declined much faster than they have risen.
As a result of the dramatic decline in oil and gas prices over the last half of 2014, many oil and gas operators have significantly reduced their capital expenditure budgets for 2015. In addition, the offshore drilling market is currently experiencing an oversupply of drilling units as newbuilds enter the market. In the current environment, we may have difficulty securing new drilling contracts; we may be forced to enter into contracts at unattractive day rates; customers may seek to renegotiate or terminate existing contracts; and we may have difficulty selling older rigs. We currently have a mix of short- and long-term contracts and are unable to predict the duration of the current market condition or its financial effects on the Company.
Current Operations and Markets
Worldwide demand for offshore drilling services is inherently volatile and has historically varied among geographic markets, as has the supply of competitive equipment. Exploration and development expenditures can be impacted by many local factors, such as political and regulatory policies, seasonal weather patterns, lease expirations, new oil and gas discoveries and reservoir depletion. Over time, the level and expected direction of oil and natural gas prices are the principal determinants of drilling activity, and oil and gas prices are ultimately a function of the supply of and demand for those commodities.
We currently operate in the U.K. and Norwegian sectors of the North Sea, the Middle East US GOM, West and North Africa, Southeast Asia and Trinidad.
As demand shifts among geographic areas,of February 13, 2018, the Company may from time to time relocatedate of our most recent Fleet Status Report, one of our four ultra-deepwater drillships was under contract in the US GOM. We had three jack-up rigs from one major geographic area to another. The relocation of rigs is a significant undertaking, and often interrupts revenues and cash flows for several months, particularly when equipment upgrades are involved. Thus, major relocations are typically carried out only when the likelihood of higher long-term returns outweighs the short-term costs.
The North Sea is a mature, harsh-environment offshore drilling market that has long been dominated by major oil and gas companies operating within a highly regulated environment. Project lead times are often lengthy, and drilling assignments, which typically require ultra-premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years. Drilling activity and day ratesunder contract in the North Sea, move slowly in response to market conditions, and generally follow trends in oil prices. As of February 16, 2015, industry utilization for jack-up rigs in the North Sea was 98%, and we had six rigs in the U.K. and Norwegian sectors with expectedseven under contract completion dates ranging from 2015 through 2018.
The Middle East is a market in which we have had a significant presence in recent years. As of February 16, 2015, industry utilization in the Middle East, for jack-up rigs was 85%, and we had nine rigsthree under contract in Saudi ArabiaTrinidad and one under contract in Qatar. Fourthe US GOM. Additionally, we had an additional five marketed jack-up rigs and three marketed drillships without contracts as well as two cold-stacked jack-up rigs and two jack-ups which have not yet been placed in service for Rowan, the two LeTourneau Super 116E jack-up rigs purchased in January 2018.
We contract our drilling rigs, related equipment and work crews primarily on a “day rate” basis. Under day rate contracts, we generally receive a fixed amount per day for each day we are performing drilling or related services. In addition, our customers may pay all or a portion of the cost of moving our tenequipment and personnel to and from the well site. Contracts generally range in duration from one month to multiple years.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 and commenced operations on October 17, 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information. Gain on sale of assets to unconsolidated subsidiary
On October 17, 2017, pursuant to an Asset Transfer and Contribution Agreement with ARO, we agreed to sell three rigs working there havecontracts estimated to completeARO: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets for a total cash consideration of $357.7 million. The book value of these assets was approximately $200.3 million. As a result of this sale transaction with ARO, we recognized a gain on the disposal of rig assets in 2015, five have contracts estimatedthe amount of $157.4 million in 2017. See Notes 1, 3 and 14 to complete fromour consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information. Customer Contract Termination Amendment
On September 15, 2016, through 2018,we amended our contract with Cobalt, for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information. Customer Contract Termination and one has aSettlement
On May 23, 2016, we reached an agreement with FMOG and its parent company, FCX, in connection with the drilling contract estimatedfor the drillship Rowan Relentless, which was scheduled to completeterminate in 2024.June 2017. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information.
The US GOM jack-upCURRENT BUSINESS ENVIRONMENT
Commodity prices have broadly improved over the past six months and industry sentiment is more favorable. However, the business environment for offshore drillers continues to be challenging due to a decrease in operators' offshore capital expenditures for the third year in a row, and an imbalance of offshore rig supply and demand, resulting in downward pressure on utilization and day rates.
Over the past three years, the cancellation and postponement of drilling market is highly fragmented among many participants, many of which are independent operators whoseprograms have resulted in significantly reduced demand for offshore drilling activities may be highly dependent on near-term operating cash flows. A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options. Long-term contracts for jack-up rigsservices globally. Additionally, the 247 new jack-ups and 163 new floaters that have been relatively rare,delivered since the beginning of the current newbuild cycle in early 2006 have exacerbated the supply and generally are available onlydemand imbalance. Since the industry downturn, contractors have responded by retiring assets, stacking certain idle equipment and deferring newbuild deliveries. Since the beginning of 2014, we estimate that approximately 50 jack-ups and 101 floaters have been removed from the major integrated oil companies and a fewtotal fleet in various forms of the larger independent operators. Jack-up drilling demand and day rates in the US GOM have tended to move quickly and generally follow trends in natural gas prices. Demand in the shallower waters of the US GOM has been weak over the last few years and at almost record lows currentlyattrition. Partly as a result of these actions, overall marketed utilization, for both jack-ups and floaters, appears to have stabilized. However, excessive levels of idle capacity continue to pressure day rates.
Further, as of February 13, 2018, there were 91 additional jack-up rigs on order or under construction worldwide for delivery through 2020 (relative to approximately 328 jack-up rigs currently on contract), and 42 floaters on order or under construction worldwide for delivery through 2021 (relative to approximately 150 floater rigs currently on contract). Only 14 floaters currently on order or under construction have contracts secured for their future delivery dates. To our knowledge, none of the availabilityjack-up newbuilds have contracts in place. We expect several of natural gasthese rigs may eventually be cancelled and low prices.many others will likely continue to be deferred until a recovery in demand is visible.
In response to market conditions over the past three years, we have reduced day rates on certain drilling contracts, some in exchange for extended contract duration, agreed to certain contract terminations, sold six of our oldest jack-ups, cold-stacked two of our older jack-ups, and have had as many as six warm stacked jack-ups and three warm stacked ultra-deepwater drillships. As of February 16, 2015, industry utilization for jack-up rigs in the US GOM was 27%,13, 2018, five jack-ups and we had seven jack-up rigs there – two under contracts estimated to complete in 2015, one under contract estimated to complete in 2016, one that was idle, and three that were cold-stacked.
A number of newbuild rigs have entered the Southeast Asia market recently due to its proximity to construction shipyards. We currently have one rig operating in Malaysia through the end of 2015 and one rig operating in Indonesia that is contracted for work in Malaysia from approximately April through July 2015. In addition, we have two idle rigs in Malaysia. Industry utilization for jack-up rigs in Southeast Asia was 81% at February 16, 2015. We expect the Southeast Asia market to weaken through 2015 due to an oversupply of rigs in the area.
The ultra-deepwater drilling market consists of semisubmersibles and drillships with a rated water depth of 7,500 feet or greater (“ultra-deepwater rigs”). As of February 24, 2015, there were a total of 162 units in this category, including Rowan’s three ultra-deepwater drillships with a worldwide utilization rate of 89%. There were an additional 68 ultra-deepwater rigsmarketed and not under construction, including Rowan’s fourth drillship, scheduledcontract.
While we have seen some recent improvement in tender activity, given the current offshore rig supply and demand dynamics, we expect the marketing environment to remain extremely competitive across the broad offshore rig market for delivery over the next five years. The major ultra-deepwater drillingfew years until a more pronounced recovery in offshore rig demand materializes. Due to the short cycle nature of the shallow water markets, in the world are the US GOM, South America and West Africa. The highest specification deepwater rigs, such as those owned by Rowan, can obtain work at better rates than lower specification rigs, as drilling requirements have become more stringent, particularly in the post-Macondo environment. In down markets, the highest specification rigs typically displace lower specification rigs, although at reduced rates. Most ultra-deepwater rigs are committed many monthswe expect jack-up demand to improve in advance of the floater market.
Despite the challenging business environment, we believe that we are strategically well-positioned to take advantage of the next up-cycle given our financial condition, solid operational reputation, and modern fleet of high-specification jack-ups and state-of-the-art ultra-deepwater drillships. While challenging market conditions persist, we continue to focus on operating efficiencies, cost cutting initiatives, upgrade of various systems and data analytics to drive improved drilling performance and predictive maintenance.
RESULTS OF OPERATIONS
We analyze the extensive planning and high costs associated with ultra-deepwater projects. Contracts are usually long term, but sublets are common within a company’s contract window. Threefinancial results of each of our drillshipsoperating segments. The operating segments presented are contracted into 2017, and one is contracted into early 2018.
consistent with our reportable segments discussed in TableNote 13 of Contents
Key Performance Measuresour consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K.
The following table presents certain key performance measuresindicators by rig classification:
classification(7):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| | | | | | |
| Revenues (in thousands): | | | | | |
| Ultra-deepwater drillships | $ | 170,502 |
| | $ | — |
| | $ | — |
|
High specification jack-ups(1) | 1,244,289 |
| | 1,251,641 |
| | 1,134,795 |
|
Premium jack-ups(2) | 319,812 |
| | 261,937 |
| | 194,942 |
|
| Conventional jack-ups | 34,668 |
| | 29,241 |
| | 26,531 |
|
| Subtotal - Day rate revenues | $ | 1,769,271 |
| | $ | 1,542,819 |
| | $ | 1,356,268 |
|
Other revenues(3) | 55,113 |
| | 36,465 |
| | 36,339 |
|
| Total revenues | $ | 1,824,384 |
| | $ | 1,579,284 |
| | $ | 1,392,607 |
|
| | | | | | |
| Revenue-producing days: | | | | | |
| Ultra-deepwater drillships | 262 |
| | — |
| | — |
|
| High specification jack-ups | 5,980 |
| | 6,297 |
| | 6,253 |
|
| Premium jack-ups | 2,728 |
| | 2,442 |
| | 2,059 |
|
| Conventional jack-ups | 311 |
| | 288 |
| | 365 |
|
| Total revenue-producing days | 9,281 |
| | 9,027 |
| | 8,677 |
|
| | | | | | |
Average day rate: (4) | |
| | |
| | |
|
| Ultra-deepwater drillships | $ | 650,356 |
| | $ | — |
| | $ | — |
|
| High specification jack-ups | $ | 208,071 |
| | $ | 198,781 |
| | $ | 181,480 |
|
| Premium jack-ups | $ | 117,245 |
| | $ | 107,245 |
| | $ | 94,678 |
|
| Conventional jack-ups | $ | 111,398 |
| | $ | 101,662 |
| | $ | 72,688 |
|
| Total fleet | $ | 190,629 |
| | $ | 170,912 |
| | $ | 156,306 |
|
| | | | | | |
Utilization: (5) | | | | | |
| Ultra-deepwater drillships | 80 | % | | — | % | | — | % |
| High specification jack-ups | 86 | % | | 91 | % | | 91 | % |
| Premium jack-ups | 93 | % | | 79 | % | | 63 | % |
| Conventional jack-ups | 28 | % | | 26 | % | | 33 | % |
| Total fleet | 82 | % | | 81 | % | | 77 | % |
| | | | | | |
| (1) We define high-specification jack-ups as those that have hook-load capacity of at least two million pounds. |
| (2) We define premium jack-ups as those cantilevered rigs capable of operating in water depths of 300 feet or more. |
| (3) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate. |
| (4) Average day rate is computed by dividing day rate revenues by the number of revenue-producing days, including fractional days. Day rate revenues include the contractual rates and amounts received in lump sum, such as for rig mobilization or capital improvements, which are amortized over the initial term of the contract. Revenues attributable to reimbursable expenses are excluded from average day rates. Total revenue-producing days may not sum due to rounding. |
| (5) Utilization is the number of revenue-producing days, including fractional days, divided by the aggregate number of calendar days in the period, or, with respect to new rigs entering service, the number of calendar days in the period from the date the rig was placed in service. |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Revenue (in millions): | | | | | |
| Deepwater | | | | | |
| Day rate revenue | $ | 465.7 |
| | $ | 824.7 |
| | $ | 730.8 |
|
Rebillable revenue (1) | 2.2 |
| | 2.8 |
| | 17.0 |
|
| Total Deepwater | $ | 467.9 |
| | $ | 827.5 |
| | $ | 747.8 |
|
| | | | | | |
| Jack-ups | | | | | |
| Day rate revenue | $ | 784.7 |
| | $ | 994.7 |
| | $ | 1,361.3 |
|
Secondment revenue (1) | 9.2 |
| | — |
| | — |
|
Rebillable revenue (1) | 12.0 |
| | 18.1 |
| | 26.0 |
|
Miscellaneous revenue (1) | 1.6 |
| | 2.9 |
| | 1.9 |
|
| Total Jack-ups | $ | 807.5 |
| | $ | 1,015.7 |
| | $ | 1,389.2 |
|
| | | | | | |
| Unallocated | | | | | |
Transition services revenue (1) | $ | 7.4 |
| | $ | — |
| | $ | — |
|
| | | | | | |
| Total revenue | $ | 1,282.8 |
| | $ | 1,843.2 |
| | $ | 2,137.0 |
|
| | | | | | |
Revenue-producing days: (2) | | | | | |
| Deepwater | 783 |
| | 1,238 |
| | 1,178 |
|
| Jack-ups | 6,144 |
| | 5,999 |
| | 7,852 |
|
| Total revenue-producing days | 6,927 |
| | 7,237 |
| | 9,030 |
|
| | | | | | |
Available days: (3) | | | |
| | |
|
| Deepwater | 1,460 |
| | 1,464 |
| | 1,263 |
|
| Jack-ups | 8,162 |
| | 8,784 |
| | 9,558 |
|
| Total available days | 9,622 |
| | 10,248 |
| | 10,821 |
|
| | | | | | |
Average day rate (in thousands): (4) | |
| | |
| | |
|
Deepwater (2) (5) | $ | 594.8 |
| | $ | 550.7 |
| | $ | 620.5 |
|
| Jack-ups | $ | 127.7 |
| | $ | 165.8 |
| | $ | 173.4 |
|
Total fleet (2) (5) | $ | 180.5 |
| | $ | 231.7 |
| | $ | 231.7 |
|
| | | | | | |
Utilization: (2) (6) | | | | | |
| Deepwater | 54 | % | | 85 | % | | 93 | % |
| Jack-ups | 75 | % | | 68 | % | | 82 | % |
| Total fleet | 72 | % | | 71 | % | | 83 | % |
| | | | | | |
| (1) Rebillable, secondment, miscellaneous and transition services revenue is excluded from the computation of average day rate. |
(2) Revenue-producing days for the year ended December 31, 2017, includes 125 days for the Deepwater drillship Rowan Reliance when it was not operating. The drillship did not operate in the third and fourth quarter of 2017, but was available for Cobalt through November 2, 2017 per the 2016 contract amendment (See Note 1 of "Notes to Consolidated Financial Statements" in Item 8 of this Annual Report on Form 10-K). Revenue of $70 million, previously deferred in 2016, was recognized during the year ended December 31, 2017 related to these days for which the rig was available to Cobalt but was not operating as well as the recognition of any remaining deferred revenue at November 2, 2017 as Cobalt did not exercise their right to use the rig. |
| (3) Available days are defined as the aggregate number of calendar days (excluding days for which a rig is cold-stacked) in the period, or, with respect to new rigs entering service, the number of calendar days in the period from the date the rig was placed in service. |
| (4) Average day rate is computed by dividing day rate revenue by the number of revenue-producing days, including fractional days. Day rate revenue includes the contractual rates and amounts received in lump sum, such as for rig mobilization or capital improvements, which are amortized over the initial term of the contract. Revenue attributable to reimbursable expenses is excluded from average day rates. |
(5) Average day rate for 2016 includes operating days for the Rowan Relentless up to the contract termination which was 143 days for 2016. |
| (6) Utilization is the number of revenue-producing days, including fractional days, divided by the number of available days. |
| (7) All revenue and KPIs exclude the results from rigs owned by ARO beginning on October 17, 2017, the date the rigs were sold to ARO. |
The following information is presented by geographic area:
table sets forth an analysis of time that our rigs were idle or out-of-service as a percentage of available days (which excludes cold-stacked rigs) and time that our rigs experienced operational downtime and are off-rate as a percentage of revenue-producing day:
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Revenues (in thousands): | | | | | |
| North Sea | $ | 483,389 |
| | $ | 480,442 |
| | $ | 491,459 |
|
Middle East (1) | 496,504 |
| | 432,739 |
| | 400,359 |
|
| US GOM | 274,983 |
| | 236,712 |
| | 206,348 |
|
| Southeast Asia | 211,667 |
| | 208,702 |
| | 135,943 |
|
| West Africa | 137,277 |
| | — |
| | — |
|
Other international(2) | 165,451 |
| | 184,224 |
| | 122,159 |
|
| Subtotal - Day rate revenues | 1,769,271 |
| | 1,542,819 |
| | 1,356,268 |
|
Other revenues(3) | 55,113 |
| | 36,465 |
| | 36,339 |
|
| Total revenues | $ | 1,824,384 |
| | $ | 1,579,284 |
| | $ | 1,392,607 |
|
| | | | | | |
| Revenue-producing days: | |
| | |
| | |
|
| North Sea | 1,668 |
| | 1,777 |
| | 2,074 |
|
| Middle East | 3,516 |
| | 3,171 |
| | 3,010 |
|
| US GOM | 1,651 |
| | 1,708 |
| | 1,706 |
|
| Southeast Asia | 1,352 |
| | 1,291 |
| | 994 |
|
| West Africa | 213 |
| | — |
| | — |
|
| Other international | 881 |
| | 1,080 |
| | 893 |
|
| Total revenue-producing days | 9,281 |
| | 9,027 |
| | 8,677 |
|
| | | | | | |
Average day rate:(4) | |
| | |
| | |
|
| North Sea | $ | 289,760 |
| | $ | 270,378 |
| | $ | 236,962 |
|
| Middle East | $ | 141,198 |
| | $ | 136,481 |
| | $ | 133,010 |
|
| US GOM | $ | 166,587 |
| | $ | 138,550 |
| | $ | 120,954 |
|
| Southeast Asia | $ | 156,572 |
| | $ | 161,694 |
| | $ | 136,764 |
|
| West Africa | $ | 645,757 |
| | $ | — |
| | $ | — |
|
| Other international | $ | 187,706 |
| | $ | 170,627 |
| | $ | 136,796 |
|
| Total fleet | $ | 190,629 |
| | $ | 170,912 |
| | $ | 156,306 |
|
| | | | | | |
Utilization:(5) | |
| | |
| | |
|
| North Sea | 76 | % | | 81 | % | | 94 | % |
| Middle East | 96 | % | | 83 | % | | 75 | % |
| US GOM | 63 | % | | 67 | % | | 59 | % |
| Southeast Asia | 93 | % | | 88 | % | | 79 | % |
| West Africa | 84 | % | | — | % | | — | % |
| Other international | 75 | % | | 99 | % | | 94 | % |
| Total fleet | 82 | % | | 81 | % | | 77 | % |
| | | | | | |
| (1) Our rigs operating in the Middle East are located in Saudi Arabia and Qatar. |
| (2) "Other international" includes revenues from Trinidad and Egypt in 2012 through 2014 and Morocco and Tunisia in 2014. |
| (3) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate. |
| (4) Average day rate is computed by dividing day rate revenues by the number of revenue-producing days, including fractional days. Day rate revenues include the contractual rates and amounts received in lump sum, such as for rig mobilization or capital improvements, which are amortized over the initial term of the contract. Revenues attributable to reimbursable expenses are excluded from average day rates. Total revenue-producing days may not sum due to rounding. |
(5) Utilization is the number of revenue-producing days, including fractional days, divided by the aggregate number of calendar days in the period, or, with respect to new rigs entering service, the number of calendar days in the period from the date the rig was placed in service.
|
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Deepwater: | | | | | |
Idle (1) | 46.4 | % | | 15.2 | % | | — | % |
Out-of-service (2) | — | % | | 0.1 | % | | — | % |
Operational downtime (3) | — | % | | 0.1 | % | | 6.7 | % |
| | | | | | |
| Jack-up: | | | | | |
Idle (1) | 15.7 | % | | 25.4 | % | | 13.5 | % |
Out-of-service (2) | 8.1 | % | | 5.3 | % | | 3.3 | % |
Operational downtime (3) | 1.3 | % | | 1.4 | % | | 1.2 | % |
| | | | | | |
| (1) Idle Days – We define idle days as the time a rig is not under contract and is available to work. Idle days exclude cold-stacked rigs, which are not marketed. |
| (2) Out-of-Service Days – We define out-of-service days as those days when a rig is (or is planned to be) out of service and is not able to earn revenue. The Company may be compensated for certain out-of-service days, such as for shipyard stays or for rig transit periods preceding a contract; however, recognition of any such compensation is deferred and recognized over the primary term of the drilling contract. |
| (3) Operational Downtime – We define operational downtime as the unbillable time when a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures. |
| (4) All revenue and utilization metrics exclude the results from rigs owned by ARO beginning on October 17, 2017, the date the rigs were sold to ARO. |
20142017 Compared to 20132016
Our operatingA summary of our consolidated results for the years ended December 31, 2014 and 2013 are highlighted below (dollars in millions):
|
| | | | | | | | | | | | | |
| | 2014 | | 2013 |
| | Amount | | % of Revenues | | Amount | | % of Revenues |
| Revenues | $ | 1,824.4 |
| | 100 | % | | $ | 1,579.3 |
| | 100 | % |
| Direct operating costs (excluding items below) | (991.4 | ) | | -54 | % | | (860.9 | ) | | -55 | % |
| Depreciation expense | (322.6 | ) | | -18 | % | | (271.0 | ) | | -17 | % |
| Selling, general and administrative expenses | (125.8 | ) | | -7 | % | | (131.3 | ) | | -8 | % |
| Net gain on property disposals | 1.8 |
| | 0 | % | | 20.1 |
| | 1 | % |
| Litigation settlement | 20.9 |
| | -2 | % | | — |
| | — | % |
| Material charges and other operating expenses | (574.0 | ) | | -31 | % | | (4.5 | ) | | — | % |
| Operating income (loss) | $ | (166.7 | ) | | -9 | % | | $ | 331.7 |
| | 21 | % |
Revenues for 2014 increased by $245.1 million or 16% compared to 2013 as a result of the followingoperations follows (in millions):
|
| | | |
| | Increase (decrease) |
| | |
Addition of the Rowan Renaissance and Rowan Resolute | $ | 170.5 |
|
| Higher average day rates for existing rigs | 57.3 |
|
| Revenues for reimbursable costs | 17.6 |
|
| Other, net | (0.3 | ) |
| Net increase | $ | 245.1 |
|
|
| | | | | | | | | | | | | | |
| | Year ended December 31, | | | | |
| | 2017 | | 2016 | | Change | | % Change |
| Deepwater: | | | | | | | |
| Revenue | $ | 467.9 |
| | $ | 827.5 |
| | $ | (359.6 | ) | | (43 | )% |
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 151.4 |
| | 222.0 |
| | (70.6 | ) | | (32 | )% |
| Depreciation and amortization | 111.6 |
| | 115.0 |
| | (3.4 | ) | | (3 | )% |
| Other operating items - expense | 0.1 |
| | 0.1 |
| | — |
| | n/m |
|
| Income from operations | $ | 204.8 |
| | $ | 490.4 |
| | $ | (285.6 | ) | | (58 | )% |
| | | | | | | | |
| Jack-ups: | | | | | | | |
| Revenue | $ | 807.5 |
| | $ | 1,015.7 |
| | $ | (208.2 | ) | | (20 | )% |
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 533.4 |
| | 556.2 |
| | (22.8 | ) | | (4 | )% |
| Depreciation and amortization | 289.4 |
| | 282.6 |
| | 6.8 |
| | 2 | % |
| Gain on sale of assets to unconsolidated subsidiary | (157.4 | ) | | — |
| | (157.4 | ) | | n/m |
|
| Other operating items - expense | 9.3 |
| | 40.9 |
| | (31.6 | ) | | n/m |
|
| Income from operations | $ | 132.8 |
| | $ | 136.0 |
| | $ | (3.2 | ) | | (2 | )% |
| | | | | | | | |
| ARO: | | | | | | | |
| Revenue | $ | 48.6 |
| | $ | — |
| |
|
| | |
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 22.2 |
| | — |
| |
|
| | |
| Depreciation and amortization | 12.9 |
| | — |
| |
|
| | |
| Selling, general and administrative | 6.1 |
| | — |
| |
|
| | |
| Other operating items - income | (0.1 | ) | | — |
| |
|
| | |
| Income from operations | $ | 7.5 |
| | $ | — |
| |
|
| | |
| | | | | | | | |
| Unallocated and other: | | | | | | | |
| Revenue | $ | 7.4 |
| | $ | — |
| | $ | 7.4 |
| | n/m |
|
| Operating expenses: | | | | | | | |
| Depreciation and amortization | 2.7 |
| | 5.3 |
| | (2.6 | ) | | (49 | )% |
| Selling, general and administrative | 104.9 |
| | 102.1 |
| | 2.8 |
| | 3 | % |
| Other operating items - expense | — |
| | 0.6 |
| | (0.6 | ) | | n/m |
|
| Loss from operations | $ | (100.2 | ) | | $ | (108.0 | ) | | $ | 7.8 |
| | (7 | )% |
| | | | | | | | |
| “n/m” - not meaningful. | | | | | | | |
Operating costs other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses for 2014 increased by $130.4 million or 15% over the prior year, as a result of the following (in millions):
|
| | | |
| | Increase |
| | |
Addition of the Rowan Renaissance and Rowan Resolute | $ | 62.0 |
|
| Higher costs due to rigs in shipyard | 29.7 |
|
| Expansion of foreign shorebases | 15.8 |
|
| Reimbursable costs | 17.6 |
|
| Other, net | 5.3 |
|
| Net increase | $ | 130.4 |
|
|
| | | | | | | | | | | | | | |
| | Year ended December 31, | | | | |
| | 2017 | | 2016 | | Change | | % Change |
| Reportable segments total: | | | | | | | |
| Revenue | $ | 1,331.4 |
| | $ | 1,843.2 |
| |
|
| |
|
|
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 707.0 |
| | 778.2 |
| |
|
| |
|
|
| Depreciation and amortization | 416.6 |
| | 402.9 |
| |
|
| |
|
|
| Selling, general and administrative | 111.0 |
| | 102.1 |
| |
|
| |
|
|
| Gain on sale of assets to unconsolidated subsidiary | (157.4 | ) | | — |
| |
|
| |
|
|
| Other operating items - expense | 9.3 |
| | 41.6 |
| |
|
| |
|
|
| Income from operations | $ | 244.9 |
| | $ | 518.4 |
| |
|
| |
|
|
| | | | | | | | |
| Eliminations and adjustments: | | | | | | | |
| Revenue | $ | (48.6 | ) | | $ | — |
| |
|
| |
|
|
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | (22.2 | ) | | — |
| |
|
| |
|
|
| Depreciation and amortization | (12.9 | ) | | — |
| |
|
| |
|
|
| Selling, general and administrative | (6.1 | ) | | — |
| |
|
| | |
| Other operating items - income | 0.1 |
| | — |
| |
|
| | |
| Equity in earnings of unconsolidated subsidiary | $ | 0.9 |
| | $ | — |
| |
|
| | |
| Loss from operations | $ | (6.6 | ) | | $ | — |
| |
|
| |
|
|
| | | | | | | | |
| Total company: | | | | | | | |
| Revenue | $ | 1,282.8 |
| | $ | 1,843.2 |
| | $ | (560.4 | ) | | (30 | )% |
| Direct operating costs (excluding items below) | 684.8 |
| | 778.2 |
| | (93.4 | ) | | (12 | )% |
| Depreciation and amortization | 403.7 |
| | 402.9 |
| | 0.8 |
| | — | % |
| Selling, general and administrative | 104.9 |
| | 102.1 |
| | 2.8 |
| | 3 | % |
| Gain on sale of assets to unconsolidated subsidiary | (157.4 | ) | | — |
| | (157.4 | ) | | n/m |
|
| Other operating items - expense | 9.4 |
| | 41.6 |
| | (32.2 | ) | | n/m |
|
| Equity in earnings of unconsolidated subsidiary | 0.9 |
| | — |
| | 0.9 |
| | n/m |
|
| Income from operations | $ | 238.3 |
| | $ | 518.4 |
| | $ | (280.1 | ) | | (54 | )% |
| Other (expense), net | (139.0 | ) | | (192.8 | ) | | 53.8 |
| | (28 | )% |
| Income before income taxes | 99.3 |
| | 325.6 |
| | (226.3 | ) | | (70 | )% |
| Provision for income taxes | 26.6 |
| | 5.0 |
| | 21.6 |
| | n/m |
|
| Net Income | $ | 72.7 |
| | $ | 320.6 |
| | $ | (247.9 | ) | | (77 | )% |
| | | | | | | | |
| “n/m” - not meaningful. | | | | | | | |
For purposes
Revenue
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
| Fewer operating days | $ | (277.1 | ) |
Prior year Contract Termination for Rowan Relentless and related items | (142.7 | ) |
| Lower reimbursable revenue | (0.6 | ) |
| Higher drillship day rates (a) | 60.8 |
|
| Decrease | $ | (359.6 | ) |
| | |
(a) Higher average drillship day rates resulted largely from the blend and extend arrangement for the Rowan Resolute. In addition, in November 2017 the Company accelerated the recognition of approximately $29 million in previously deferred revenue for the Rowan Reliance (to which no operating days were associated) as Cobalt did not exercise their right to use the rig. These increases were partially offset by a decrease for the Rowan Reliance due to lower average day rates in 2017 compared to 2016. |
Jack-ups. An analysis of the net changes in revenue for 2017, compared to 2016, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
| Lower jack-up day rates | $ | (244.2 | ) |
| Decrease due to sale of assets to ARO | (12.6 | ) |
| Lower reimbursable revenue | (6.1 | ) |
| Lower other revenue | (1.3 | ) |
| Increased operating days | 46.8 |
|
| Increase in ARO related secondment reimbursables | 9.2 |
|
| Decrease | $ | (208.2 | ) |
Unallocated. From October 17, 2017 to December 31, 2017, we recorded $7.4 million of revenue related to transition services provided to ARO (see Note 1 and Note 3 to our consolidated financial statements in Part II, Item 8 of this discussion, we define ourAnnual Report on Form 10-K).
Direct operating margin as revenuescosts
Consolidated. The decrease in excess ofconsolidated direct operating costs other than depreciation, selling, generalis described below.
Deepwater. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
|
| | | |
| | Decrease |
| Decrease due to idle drillships | $ | (44.8 | ) |
| Reduction in shore base costs and other | (17.6 | ) |
| Reduction in drillship direct operating expenses | (7.6 | ) |
| Lower reimbursable costs | (0.6 | ) |
| Decrease | $ | (70.6 | ) |
Jack-ups. An analysis of the net changes in direct operating costs for 2017, compared to 2016, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
| Decrease due to idle or cold-stacked rigs | $ | (21.5 | ) |
| Decrease due to sale of assets to ARO | (7.8 | ) |
| Lower reimbursable costs | (6.1 | ) |
| Reduction in shore base costs and other | (2.1 | ) |
| Increase in ARO related secondment reimbursable costs | 9.2 |
|
| ARO management fee | 7.8 |
|
| Reduction in jack-up direct operating expenses | (2.3 | ) |
| Decrease | $ | (22.8 | ) |
Gain on sale of assets to unconsolidated subsidiary
We recognized a gain of $157.4 million on the sale of assets to ARO. See Notes 1, 3 and administrative expenses, gains or14 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K for additional information. Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
In 2017, we had a loss on disposals of property and equipment of $9.4 million compared to a loss of $8.7 million in 2016.
Other expense, net
The decrease in Other expense, net, is primarily due to a $1.7 million gain on the early extinguishment of debt in 2017 compared to a net loss on the early extinguishment of debt of $31.2 million in 2016. Interest income increased in 2017 primarily due to higher cash balances in 2017 as compared to 2016, and $2.1 million of interest income related to the note receivable from ARO (see Note 3 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). Additionally, our foreign currency exchange losses on asset disposals, litigation settlement, and material charges and other operating expenses. Operating margin as we have defined it is a non-GAAP financial measure. The impact on operating margin of those excluded items are discussed separately below and have been excluded solelydecreased to simplify the discussion. Operating margin, as defined, increased$0.4 million in 2017 compared to approximately 46%$9.7 million in 2014 from 45% in 2013. Depreciation increased by $51.6 million or 19% over 20132016 primarily due to the additiondevaluation of the drillships.
Selling, general and administrative expenses decreased by $5.5 million or 4% primarily due to fewer professional services and fees for corporate restructuring, initiatives related to the Company's internationalization and entry into the ultra-deepwater market; and to lower equity compensation expense resulting from fair market adjustments to certain share-based awards recorded under the liability method of accounting.
Net gain on property disposalsEgyptian pound in 2013 included a $19.1 million gain resulting from the sale of the Rowan Paris, one of the Company's older rigs, for approximately $40.0 million in cash.
In 2014, the Company settled its litigation with the owners and operators of a tanker that collided with the Rowan EXL I in 2012 and received $20.9 million in cash as compensation for damages incurred in 2012 for repair costs to and loss of use of the rig. Such amount was recognized in operating income in 2014.2016.
Long-lived assets are required to be reviewedProvision for impairment whenever circumstances indicate their carrying values may not be recoverable. Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling rigs over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up drilling units were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized a noncash asset impairment charge of $565.7 million in the fourth quarter of 2014. Material charges for 2014 also included an $8.3 million noncash impairment charge on a Company aircraft, which we sold later in 2014 at an immaterial loss. Material charges and other operating expenses for 2013 consisted of a $4.5 million noncash asset impairment charge on a dock and maintenance facility.
income taxes
In 2014,2017, we recognized an income tax benefitprovision of $150.7$26.6 million on pretax income of $99.3 million. The 2017 tax provision primarily includes $28.7 million of tax expense for current year operations, $20.5 million of tax expense due to an increase in the valuation allowance assessed on deferred tax assets, and a $269.6partial offset by a $27.3 million pretax loss from continuing operations, as comparedreduction in accrued unrecognized tax benefits due to a lapse in statutes of limitation and an audit settlement.
In 2016, we recognized an income tax provision of $8.7$5.0 million on $261.2 million of pretax income from continuing operations in 2013.of $325.6 million. The benefit in 20142016 tax provision was primarily due to the acceleration of previously deferred intercompany gains and losses associated with impaired assets,2016 operations offset by the amortization of deferred intercompany gains and losses and deferred tax benefit as a result of 2016 restructuring.
2016 Compared to 2015
A summary of our consolidated results of operations follows (in millions):
|
| | | | | | | | | | | | | | |
| | Year ended December 31, | | | | |
| | 2016 | | 2015 | | Change | | % Change |
| Deepwater: | | | | | | | |
| Revenue | $ | 827.5 |
| | $ | 747.8 |
| | $ | 79.7 |
| | 11 | % |
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 222.0 |
| | 276.6 |
| | (54.6 | ) | | (20 | )% |
| Depreciation and amortization | 115.0 |
| | 94.6 |
| | 20.4 |
| | 22 | % |
| Other operating items - expense | 0.1 |
| | — |
| | 0.1 |
| | n/m |
|
| Income from operations | $ | 490.4 |
| | $ | 376.6 |
| | $ | 113.8 |
| | 30 | % |
| | | | | | | | |
| Jack-ups: | | | | | | | |
| Revenue | $ | 1,015.7 |
| | $ | 1,389.2 |
| | $ | (373.5 | ) | | (27 | )% |
| Operating expenses: | | | | | | | |
| Direct operating costs (excluding items below) | 556.2 |
| | 716.5 |
| | (160.3 | ) | | (22 | )% |
| Depreciation and amortization | 282.6 |
| | 283.9 |
| | (1.3 | ) | | — | % |
| Other operating items - expense | 40.9 |
| | 328.8 |
| | (287.9 | ) | | n/m |
|
| Income from operations | $ | 136.0 |
| | $ | 60.0 |
| | $ | 76.0 |
| | 127 | % |
| | | | | | | | |
| Unallocated and other: | | | | | | | |
| Operating expenses: | | | | | | | |
| Depreciation and amortization | $ | 5.3 |
| | $ | 12.9 |
| | $ | (7.6 | ) | | (59 | )% |
| Selling, general and administrative | 102.1 |
| | 115.8 |
| | (13.7 | ) | | (12 | )% |
| Other operating items - expense | 0.6 |
| | 0.8 |
| | (0.2 | ) | | n/m |
|
| Loss from operations | $ | (108.0 | ) | | $ | (129.5 | ) | | $ | 21.5 |
| | (17 | )% |
| | | | | | | | |
| Total company: | | | | | | | |
| Revenue | $ | 1,843.2 |
| | $ | 2,137.0 |
| | $ | (293.8 | ) | | (14 | )% |
| Direct operating costs (excluding items below) | 778.2 |
| | 993.1 |
| | (214.9 | ) | | (22 | )% |
| Depreciation and amortization | 402.9 |
| | 391.4 |
| | 11.5 |
| | 3 | % |
| Selling, general and administrative | 102.1 |
| | 115.8 |
| | (13.7 | ) | | (12 | )% |
| Other operating items - expense | 41.6 |
| | 329.6 |
| | (288.0 | ) | | n/m |
|
| Income from operations | $ | 518.4 |
| | $ | 307.1 |
| | $ | 211.3 |
| | 69 | % |
| Other (expense), net | (192.8 | ) | | (149.4 | ) | | (43.4 | ) | | 29 | % |
| Income before income taxes | 325.6 |
| | 157.7 |
| | 167.9 |
| | 106 | % |
| Provision for income taxes | 5.0 |
| | 64.4 |
| | (59.4 | ) | | (92 | )% |
| Net Income | $ | 320.6 |
| | $ | 93.3 |
| | $ | 227.3 |
| | 244 | % |
| | | | | | | | |
| “n/m” - not meaningful. | | | | | | | |
Revenue
Consolidated. The decrease in consolidated revenue is described below.
Deepwater. An analysis of the net changes in revenue for 2016, compared to 2015, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
Contract Termination for Rowan Relentless and related items | $ | 142.7 |
|
| Lower drillship average day rates | (84.8 | ) |
| Lower reimbursable revenue | (14.3 | ) |
Rowan Reliance and Rowan Relentless fully in service in 2016 versus startup in February and June of 2015, respectively, net of idle time in 2016 | 21.5 |
|
| Lower unbillable downtime | 14.6 |
|
| Increase | $ | 79.7 |
|
Jack-ups. An analysis of the net changes in revenue for 2016, compared to 2015, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
| Lower jack-up utilization | $ | (319.8 | ) |
| Lower jack-up average day rates | (46.1 | ) |
| Lower reimbursable revenue | (7.9 | ) |
| Other | 0.3 |
|
| Decrease | $ | (373.5 | ) |
Direct operating costs
Consolidated. The decrease in consolidated direct operating costs is described below.
Deepwater. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
|
| | | |
| | Increase (decrease) |
| Reduction in drillship direct operating expense | $ | (34.8 | ) |
| Decrease due to idle drillship | (15.4 | ) |
| Lower reimbursable costs | (14.3 | ) |
| Reduction in shore base costs and other | (9.8 | ) |
Addition of Rowan Reliance and Rowan Relentless | 19.7 |
|
| Decrease | $ | (54.6 | ) |
Jack-ups. An analysis of the net changes in direct operating costs for 2016, compared to 2015, are set forth below (in millions):
|
| | | |
| | Decrease |
| Decrease due to idle or cold-stacked rigs | $ | (115.9 | ) |
| Reduction in jack-up direct operating expense | (29.9 | ) |
| Lower reimbursable costs | (7.9 | ) |
| Reduction in shore base costs and other | (6.6 | ) |
| Decrease | $ | (160.3 | ) |
Depreciation and amortization
Depreciation and amortization for 2016 increased largely due to the addition of the Rowan Reliance and Rowan Relentless in 2015.
Selling, general and administrative
Selling, general and administrative expenses for 2016 decreased largely due to lower personnel costs. In addition, professional fees and information technology expenses decreased in 2016 as compared to 2015.
Other operating items
Material charges for 2016 included a $34.3 million non-cash impairment charge to reduce the carrying values of five of our jack-up drilling units, partially offset by a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to outbounding certain U.S.-owned rigsa legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest.
Material charges for 2015 included a $329.8 million non-cash impairment charge to reduce the carrying values of ten of our non-U.S. subsidiaries in prior years,jack-up drilling units and a $7.6 million adjustment to an estimated liability for the 2014 termination of a contract for refurbishment work on the Rowan Gorilla III. A settlement agreement reached withfor this matter was signed during the U.S. Internal Revenue Servicethird quarter of 2015.
In 2016, we had a loss on disposals of property and equipment of $8.7 million compared to a gain of $7.7 million in September 2014 (see Note 72015.
Other expense, net
The increase in Other Expense, Net, is primarily due to a $31.2 million net loss on the early extinguishment of Notesdebt in 2016 compared to Consolidated Financial Statements).$1.5 million in 2015. Interest capitalization was $16.2 million in 2015. There was no interest capitalization in 2016 as the drillship construction program was completed in 2015. Additionally, our foreign currency exchange losses increased to $9.7 million in 2016 compared to $3.9 million in 2015 primarily due to the devaluation of the Egyptian pound. Partially offsetting these increases, our debt retirements in late 2015 and early 2016 resulted in a reduction in interest expense in 2016.
Provision for income taxes
In 2016, we recognized an income tax provision of $5.0 million on pretax income of $325.6 million. The low effective2016 tax rate of 3.3% in 2013provision was primarily due in part to 2016 operations offset by the amortization of deferred intercompany gains and losses related to outbounding certain U.S.-owned rigs to our non-U.S. subsidiaries in prior years;and deferred tax benefit as a significant proportionresult of 2016 restructuring.
In 2015, we recognized an income earned in low-tax foreign jurisdictions; the implementationtax provision of our international restructuring plan, which resulted in the utilization$64.4 million on pretax income of non-U.S. subsidiaries’ foreign taxes paid as credits against U.S. taxable income; additional$157.7 million. The 2015 tax basis in fixed assetsprovision was primarily due to the applicationestablishment of a rulingvaluation allowance on the U.S. deferred tax assets, impairments of assets in a third-party tax case to the Company's situation; and the continued recognition ofjurisdictions with no tax benefits, related to the application of certainand an increase in income in high-tax jurisdictions, offset by additional tax planning strategies implemented in 2012 related to interest capitalization.
2013 Compared to 2012
Our operating resultsbenefit for the years endedU.S. impaired assets and an increase in income in low-tax jurisdictions.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios at December 31 2013 and 2012 are highlighted belowwere as follows (dollars in millions):
|
| | | | | | | | | | | | | |
| | 2013 | | 2012 |
| | Amount | | % of Revenues | | Amount | | % of Revenues |
| Revenues | $ | 1,579.3 |
| | 100 | % | | $ | 1,392.6 |
| | 100 | % |
| Operating costs (excluding items below) | (860.9 | ) | | -55 | % | | (752.2 | ) | | -54 | % |
| Depreciation expense | (271.0 | ) | | -17 | % | | (247.9 | ) | | -18 | % |
| Selling, general and administrative expenses | (131.3 | ) | | -8 | % | | (99.7 | ) | | -7 | % |
| Net gain on property disposals | 20.1 |
| | 1 | % | | 2.5 |
| | 0 | % |
| Litigation settlement | — |
| | — | % | | 4.7 |
| | — | % |
| Material charges and other operating expenses | (4.5 | ) | | — | % | | (44.9 | ) | | -3 | % |
| Operating income | $ | 331.7 |
| | 21 | % | | $ | 255.1 |
| | 18 | % |
|
| | | | | | | |
| | 2017 | | 2016 |
| Cash and cash equivalents | $ | 1,332.1 |
| | $ | 1,255.5 |
|
| Current assets | $ | 1,560.4 |
| | $ | 1,580.3 |
|
| Current liabilities | $ | 257.4 |
| | $ | 483.8 |
|
| Current ratio | 6.06 |
| | 3.27 |
|
| Current portion of long-term debt | $ | — |
| | $ | 126.8 |
|
| Long-term debt, less current portion | $ | 2,510.3 |
| | $ | 2,553.4 |
|
| Shareholders' equity | $ | 5,386.1 |
| | $ | 5,113.9 |
|
| Debt to capitalization ratio | 32 | % | | 34 | % |
Revenues for 2013 increased by $186.7 million or 13% compared to 2012 as a result of the following (in millions):
|
| | | |
| | Increase |
| | |
| Higher average day rates for existing rigs | $ | 125.2 |
|
| Higher utilization of existing rigs | 48.1 |
|
| Other, net | 13.4 |
|
| Net increase | $ | 186.7 |
|
Operating costs other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses for 2013 increased by $108.7 million or 14% over the prior year, as a result of the following (in millions):
|
| | | |
| | Increase |
| | |
| Increase due to rigs operating in higher-cost locations | $ | 55.6 |
|
| Expansion of foreign shorebases | 14.6 |
|
| Operations support | 12.7 |
|
Repair costs for the Rowan Gorilla VII | 12.4 |
|
| Other, net | 13.4 |
|
| Net increase | $ | 108.7 |
|
Our operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses, litigation settlement and material charges and other operating expenses) was approximately 45% in 2013 and 46% in 2012. Depreciation increased by $23.1 million or 9% over 2012 due to capital improvements to the fleet.
In July 2013, while the Rowan Gorilla VII was changing locations, the legsSources and uses of cash and cash equivalents were severely damaged as the hull was being lowered into the water. Extended poor weather conditions in the North Sea hampered the rig's abilityfollows (in millions): |
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Net operating cash flows | $ | 299.8 |
| | $ | 905.6 |
| | $ | 998.1 |
|
| Capital expenditures | (100.6 | ) | | (117.6 | ) | | (722.9 | ) |
| Deposit on purchase of rigs | (7.7 | ) | | — |
| | — |
|
| Investment in unconsolidated subsidiary | (30.0 | ) | | — |
| | — |
|
| Contributions to unconsolidated subsidiary for note receivable | (357.7 | ) | | — |
| | — |
|
| Proceeds from sale of assets to unconsolidated subsidiary | 357.7 |
| | — |
| | — |
|
| Repayments of note receivable from unconsolidated subsidiary | 87.5 |
| | — |
| | — |
|
| Proceeds from disposals of property and equipment | 3.3 |
| | 6.2 |
| | 19.4 |
|
| Borrowings, net of issue costs | — |
| | 491.3 |
| | 220.0 |
|
| Reductions of long-term debt | (170.0 | ) | | (511.8 | ) | | (317.9 | ) |
| Dividends paid | — |
| | — |
| | (50.5 | ) |
| Shares repurchased for tax withholdings on vesting of restricted share units | (5.7 | ) | | (5.0 | ) | | (1.2 | ) |
| Excess tax benefits from share-based compensation | — |
| | 2.6 |
| | — |
|
| Total net source | $ | 76.6 |
| | $ | 771.3 |
| | $ | 145.0 |
|
Operating Cash Flows
Cash flows from operations decreased to return to its operating location following repairs. As a result of the incident, the rig was out of service for 174 days in 2013, resulting in a loss of revenue of approximately $43 million. In 2013, we incurred $12.4$300 million in incremental repair costs to the rig, which are included2017 from $906 million in direct operating costs. The rig returned to service in February 2014.
Selling, general and administrative expenses increased by $31.7 million or 32%2016 primarily due to professional services and fees for corporate restructuring, initiatives related tolower drilling activity in the Company's internationalization and entry intocurrent year as well as the ultra-deepwater market; the noncash impact of a new retirement policycontract termination settlements in the prior year. Operating cash flows for 2016 compared to 2015 decreased primarily due to lower drilling activity, the cash loss on the vesting periodearly extinguishment of debt, combined with uses of cash for share-based compensation; incremental incentive-based compensation based on the Company's projected performance;current assets and fair market adjustments to certain share-based awards based onliabilities, partially offset by deferred revenue and changes in the share price.other non-current assets and liabilities.
In 2013, the Company sold the Rowan Paris, oneWe have not provided deferred income taxes on certain undistributed earnings of the Company's older rigs, for approximately $40.0 million in cash and recognizednon-U.K. subsidiaries. No subsidiary of RCI has a gain of $19.1 million.
Material charges and other operating expenses for 2013 consisted of a $4.5 million noncash asset impairment charge on a maintenance and storage facility.
Litigation settlement for 2012 includes a $4.7 million gain for cash received in connection with a legal settlement.
Material charges and other operating expenses for 2012 consisted of $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the Rowan EXL I following its collision with a tanker, $8.7 million of pension settlement costs in connection with lump sum pension paymentsplan to employees of the Company’s former manufacturing subsidiary, $8.1 million of noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee.
In 2013, we recognized income tax expense of $8.7 million on $261.2 million of pretax income from continuing operations, as compareddistribute earnings to a benefit of $19.8 million on $183.5 million of pretax income from continuing operations in 2012. The low effective tax rate of 3.3% in 2013 was due in part to the amortization of deferred intercompany gains and losses related to outbounding certain U.S.-owned rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; the implementation of our international restructuring plan, which resulted in the utilization of non-U.S. subsidiaries’ foreign taxes paid as credits against U.S. taxable income; additional tax basis in fixed assets due to the application of a rulingRCI in a third-party tax casemanner that would cause those earnings to the Company's situation; and the continued recognition of tax benefits relatedbe subject to the application of certain tax planning strategies implemented in 2012 related to interest capitalization. The recognition of an income tax benefit in 2012 was due in part to the amortization of deferred intercompany gains and losses related to outbounding certain rigs to our non-U.S. subsidiaries in prior years; a significant proportion of income earned in low-tax foreign jurisdictions; and the implementation of tax planning strategies with regard to capitalized interest.U.S., U.K. or other local country taxation.
Outlook
Backlog
Our backlog by geographic area as of the date of our most recent Fleet Status Report is presented below (in millions):
|
| | | | | | | | | | | |
| | February 19, 2015 |
| | Jack-ups | | Drillships | | Total |
| | | | | | |
| US GOM | $ | 14 |
| | $ | 1,892 |
| | $ | 1,906 |
|
| Middle East | 1,666 |
| | — |
| | 1,666 |
|
| North Sea | 942 |
| | — |
| | 942 |
|
| West Africa | — |
| | 274 |
| | 274 |
|
| Southeast Asia | 61 |
| | — |
| | 61 |
|
| Other international | 241 |
| | — |
| | 241 |
|
| Total backlog | $ | 2,924 |
| | $ | 2,166 |
| | $ | 5,090 |
|
For purposes of computing backlog, we have assumed the Rowan Renaissance, which is currently operating in West Africa, will relocate to the US GOM for the third year of its three-year contract based on discussions with the customer, where it would earn a contract day rate of $630,000. Alternatively, if the rig continues to operate in West Africa during year three, the contract day rate would be $660,000. |
| | | | | | | | | | | |
| | February 13, 2018 |
| | Jack-ups (1) | | Deepwater | | Total |
| US GOM | $ | 11.4 |
| | $ | 89.8 |
| | $ | 101.2 |
|
| Middle East | 180.1 |
| | — |
| | 180.1 |
|
| North Sea | 96.9 |
| | — |
| | 96.9 |
|
| Central and South America | 78.0 |
| | — |
| | 78.0 |
|
| Total backlog | $ | 366.4 |
| | $ | 89.8 |
| | $ | 456.2 |
|
| | | | | | |
(1) Excludes any backlog associated with ARO. |
We estimate our backlog as of February 13, 2018, will be realized as follows (in millions):
|
| | | | | | | | | | | |
| | February 19, 2015 |
| | Jack-ups | | Drillships | | Total |
| | | | | | |
| 2015 | $ | 1,038 |
| | $ | 670 |
| | $ | 1,708 |
|
| 2016 | 793 |
| | 889 |
| | 1,682 |
|
| 2017 | 489 |
| | 589 |
| | 1,078 |
|
| 2018 | 256 |
| | 18 |
| | 274 |
|
| 2019 and later years | 348 |
| | — |
| | 348 |
|
| Total backlog | $ | 2,924 |
| | $ | 2,166 |
| | $ | 5,090 |
|
|
| | | | | | | | | | | |
| Year Ended: | Jack-ups (1) | | Deepwater | | Total |
| 2018 | $ | 335.4 |
| | $ | 89.8 |
| | $ | 425.2 |
|
| 2019 | 31.0 |
| | — |
| | 31.0 |
|
| 2020 | — |
| | — |
| | — |
|
| 2021 | — |
| | — |
| | — |
|
| 2022 and later years | — |
| | — |
| | — |
|
| Total backlog | $ | 366.4 |
| | $ | 89.8 |
| | $ | 456.2 |
|
| | | | | | |
(1) Excludes any backlog associated with ARO. |
For comparative purposes, ourOur contract backlog by geographic arearepresents remaining contractual terms and may not reflect actual revenue due to renegotiations or a number of factors such as reported in our 2013 Form 10-K, is set forth below (in millions):
|
| | | | | | | | | | | |
| | February 20, 2014 |
| | Jack-ups | | Drillships | | Total |
| | | | | | |
| US GOM | $ | 84 |
| | $ | 1,777 |
| | $ | 1,861 |
|
| North Sea | 1,405 |
| | — |
| | 1,405 |
|
| Middle East | 1,029 |
| | — |
| | 1,029 |
|
| West Africa | — |
| | 226 |
| | 226 |
|
| Southeast Asia | 160 |
| | — |
| | 160 |
|
| Other international | 297 |
| | — |
| | 297 |
|
| Total backlog | $ | 2,975 |
| | $ | 2,003 |
| | $ | 4,978 |
|
As a resultrig downtime, out of the dramatic decline in oil and gas prices over the last half of 2014, many oil and gas operators have significantly reduced their capital expenditure budgets for 2015. In addition, the offshore drilling market is currently experiencing an oversupply of drilling units as newbuilds enter the market. In the current environment, we may have difficulty securing new drilling contracts; we may be forced to enter into contracts at unattractive day rates; customers may seek to renegotiateservice time, estimated contract durations, customer concessions or terminate existing contracts; and we may have difficulty selling older rigs. We currently have a mix of short- and long-term contracts, which we expect will help to mitigate the effect of a prolonged downturn. Nevertheless, we are unable to predict the duration of the current market condition or its financial effects on the Company.
Newbuild deliveries in recent years have increased the pool of rigs competing for contracts in many areas in which we operate, putting significant downward pressure on utilization and day rates. As of February 16, 2015, there were approximately 132 jack-up rigs under construction worldwide for delivery through 2017 (24% of the current jack-up fleet), including 53 that are considered
high-specification (77% of the current high-specification fleet). Approximately 22 of these jack-up rigs, which are not contracted, are scheduled for delivery in 2015. Utilization and day rates in certain regions are expected to come under additional pressure as these rigs enter the worldwide fleet.
contract cancellations.
About 63%34% of our remaining available rig days in 2015 (excluding our three cold-stacked rigs)2018 and 43%4% of available rig days in 2016 were under contract or commitment2019 are included in backlog as revenue producing days as of February 19, 2015.13, 2018, excluding cold-stacked rigs. As of that date, we had two jack-ups that were cold-stacked and five jack-ups and three rigs without contracts (excluding the three cold-stacked rigs). Failure to obtain or renew contracts would significantly impact the Company's resultsdrillships that were available.
Since 2014, we have recognized asset impairment charges on several of operations and cash flow.
Out-of-Service Days – We define out-of-service days as those days when a rig is (or planned to be) out of service and is not able to earn revenue. The Company may be compensated for certain out-of-service days, such as for shipyard stays or for rig transit periods preceding a contract; however, recognition of any such compensation is deferred and recognized over the period of drilling operations.
Our out-of-service days totaled approximately 10% of available rig days in 2014 and 2013, down from 12% in 2012. We estimate planned out-of-service time for 2015 to range from 3% to 6%.
Operational Downtime– We define operational downtime as the unbillable time a rig is under contract and unable to conduct planned operations due to equipment breakdowns or procedural failures. Our operational downtime, which is in addition to out-of-service days, was approximately 1% of in-service days for both 2014 and 2013, down from 2% in 2012. We estimate operational downtime for our jack-up fleet will typically approximate 2.5% of operating days on a go-forward basis.
Following its January 2014 delivery from the shipyard and commencement of operations in April, the Rowan Renaissance ultra-deepwater drillship experienced 41 off-rate days, which included 23 out-of-service days for commissioning of late-arriving equipment and 18 days of operational downtime in 2014. Our second ultra-deepwater drillship, the Rowan Resolute, began operating in the US GOM in mid October 2014 and experienced 27 out-of-service days for commissioning and no operational downtime days in 2014.
We estimate that operational downtime for our newly constructed ultra-deepwater drillships will be less than 5% of operating days following an initial break-in period of operations, which could range from approximately six months to one year, during which time the actual rate could be somewhat higher.
Other Matters – During the fourth quarter of 2014, we engaged a broker to assist in the potential sale of certain of our older jack-up rigs.
LIQUIDITY AND CAPITAL RESOURCES
Key balance sheet amounts and ratios at December 31 were as follows (dollars in millions):
|
| | | | | | | |
| | 2014 | �� | 2013 |
| Cash and cash equivalents | $ | 339.2 |
| | $ | 1,092.8 |
|
| Current assets (excluding assets of discontinued operations) | $ | 941.1 |
| | $ | 1,505.1 |
|
| Current liabilities (excluding liabilities of discontinued operations) | $ | 333.2 |
| | $ | 334.5 |
|
| Current ratio (excluding assets and liabilities of discontinued operations) | 2.82 |
| | 4.50 |
|
| Long-term debt | $ | 2,807.3 |
| | $ | 2,008.7 |
|
| Shareholders' equity | $ | 4,691.4 |
| | $ | 4,893.8 |
|
| Debt to capitalization ratio | 37 | % | | 29 | % |
Sources and uses of cash and cash equivalents were as follows: |
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Net operating cash flows | $ | 423.0 |
| | $ | 623.2 |
| | $ | 393.7 |
|
| Borrowings, net of issue costs | 792.7 |
| | — |
| | 1,102.9 |
|
| Payment of cash dividends | (37.7 | ) | | — |
| | — |
|
| Capital expenditures | (1,958.2 | ) | | (607.3 | ) | | (685.2 | ) |
| Debt repayments | — |
| | — |
| | (238.5 | ) |
| Proceeds from asset disposals | 22.0 |
| | 44.5 |
| | 10.5 |
|
| Proceeds from equity compensation plans | 4.7 |
| | 2.9 |
| | 0.6 |
|
| All other, net | (0.1 | ) | | 5.5 |
| | 1.2 |
|
| Total net (use) sources | $ | (753.6 | ) | | $ | 68.8 |
| | $ | 585.2 |
|
Operating Cash Flows
Cash flows from operations decreased to approximately $423 million in 2014 from $623 million in 2013. Operating cash flows for 2014 compared to 2013 were negatively impacted by an increase in trade and other receivables, receipt of an approximately $53 million U.S. federal income tax refund in 2013, and higher pension contributions in 2014. Operating cash flows for 2013 increased by $229 million over 2012 primarily due to higher day rates and rig utilization, receipt of an approximately $53 million U.S. federal income tax refund, improved timing of collections of accounts receivables and a reduction in the required minimum pension contributiondrilling units as a result of U.S. legislation.
The Company has not provided deferred income taxes on undistributed earningsthe decline in market conditions and the expectation of its non-U.K. subsidiaries, including RCI's non-U.S. subsidiaries. It is the Company’s policyfuture demand and intentionday rates. If market conditions deteriorate further, we could be required to permanently reinvest earnings of non-U.S. subsidiaries of RCI outside the U.S. Generally, earnings of non-U.K. subsidiariesrecognize additional impairment charges in which RCI does not have a direct or indirect ownership interest can be distributed to the Company without imposition of either U.K. or local country tax.
As of December 31, 2014, RCI's portion of the unremitted earnings of its non-U.S. subsidiaries was approximately $205 million. Should the non-U.S. subsidiaries of RCI make a distribution from these earnings, we may be subject to additional U.S. income taxes. It is not practicable to estimate the amount of deferred tax liability related to the undistributed earnings, and RCI's non-U.S. subsidiaries have no plan to distribute earnings in a manner that would cause them to be subject to U.S., U.K. or other local country taxation.
At December 31, 2014, RCI’s non-U.S. subsidiaries held approximately $125 million of the $339 million of consolidated cash and cash equivalents. Management believes the Company has significant net assets, liquidity, contract backlog and/or other financial resources available to meet its operational and capital investment requirements and otherwise allow us to continue to maintain its policy of reinvesting such undistributed earnings outside the U.K. and U.S. indefinitely.
future periods.
Investing Activities
During 2014, we took delivery of three of our four newly constructed ultra-deepwater drillships, with the fourth expected to be delivered in late March 2015.
Capital expenditures in 20142017 totaled $1.958 billion$100.6 million and included the following:
$1.560 billion for construction of the ultra-deepwater drillships Rowan Renaissance, Rowan Resolute,Rowan Reliance and Rowan Relentless;
$34570.5 million for improvements to the existing fleet, including contractually required modifications; and
$5330.1 million for rig equipment inventory and other.
A cash deposit of $7.7 million was made toward the purchase of two jack-up rigs. See Note 19 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. In connection with the formation of ARO, we contributed $25 million to be used by the joint venture for working capital needs and incurred $5.0 million in transaction costs that were both capitalized to the investment in ARO. We deconsolidated $200.3 million worth of rigs and related assets which were sold to ARO for cash of $357.7 million.
Also, in connection with the ARO joint venture, we contributed $357.7 million in cash to ARO in exchange for a note receivable from ARO, our unconsolidated joint venture. We received $87.5 million in cash from ARO for repayment of the shareholder note receivable. As of December 31, 2017, $271.3 million was outstanding on this shareholder note receivable consisting of $270.2 million Long-term note receivable from unconsolidated subsidiary and the current portion of $1.1 million included in Receivables - trade and other, both on the Company's Consolidated Balance Sheets.
We currently estimate our 20152018 capital expenditures, to beexclusive of ARO's capital expenditures, will range from approximately $850-$875$100-110 million, including $660-$685 million in connection with our two newbuild drillships, including costswhich is primarily for mobilization, commissioning, riser gas-handling equipment, software certifications and drillship fleet spares to support our deepwater operations. The remaining amount is related to existing fleet maintenance, rig equipment, spares, upgrades to prepare two newly purchased rigs for service (see below) and other. This amount excludes any contractual modifications that may arise due to our securing additional work. In addition to our capital and worldwide spares.
We expect to fund our 20152018 capital expenditures using available cash cash flows from operations and our revolving credit facility.on hand.
TheOur capital budgetforecast reflects an appropriation of moneycash that we may or may not spend, and the timing of such expenditures may change. We will periodically review and adjust the capital budgetforecast as necessary based upon current and forecastexpected cash flows and liquidity, anticipated market conditions in our business, the availability of financial resources, and alternative uses of capital to enhance shareholder value.
Capital expenditures for 2016 totaled $117.6 million and included $68.5 million for improvements to the existing fleet, including contractually required modifications, and $49.1 million for rig equipment and other.
Capital expenditures for 20132015 totaled $607$722.9 million and included $229$541.3 million towards drillship construction, of the Rowan Renaissance, Rowan Resolute,Rowan Relianceincluding costs for mobilization, commissioning, riser gas-handling equipment, software certifications and Rowan Relentless;spares; $323132.5 million for improvements to the existing fleet, including contractually required modifications; and $55$49.1 million for rig equipment inventoryspares and other.
Capital expenditures for 2012 totaled $685 million With the delivery of our fourth and included $287 million towardsfinal drillship in March 2015, we concluded our ultra-deepwater drillship construction program. We took delivery of the first three drillships in 2014.Rowan Renaissance, Rowan Resolute,Rowan Reliance and Rowan Relentless; $350 million for improvements to the existing fleet, including contractually required modifications; and $48 million for rig equipment, inventory and other.
Financing Activities
In January 2014 we completed the issuance and sale in a public offering of $400 million aggregate principal amount of 4.75% Senior Notes due 2024, and $400 million aggregate principal amount of 5.85% Senior Notes due 2044. Net proceeds of the offering were approximately $792 million, which the Company used for its rig construction program and for general corporate purposes. Additionally, the Company amended and restated its credit agreement to increase the borrowing capacity under the revolving credit facility from $750 million to $1.0 billion, among other things. There were no amounts drawn under the revolving credit facility at December 31, 2014.
As of December 31, 2014, we had $2.8 billion of outstanding long-term debt consisting of $400 million principal amount of 5% Senior Notes due 2017; $500 million principal amount of 7.875% Senior Notes due 2019; $700 million principal amount of 4.875% Senior Notes due 2022; $400 million aggregate principal amount of 4.75% Senior Notes due 2024; $400 million principal amount of 5.4% Senior Notes due 2042; and $400 million aggregate principal amount of 5.85% Senior Notes due 2044 (together, the “Senior Notes”). The Senior Notes and amounts outstanding under our Revolving Credit Facility are fully, unconditionally and unconditionallyirrevocably guaranteed on a senior and unsecured basis by Rowan plc (see Note 15 of Notesplc. We were in compliance with our debt covenants at December 31, 2017, and expect to Financial Statementsremain in Item 8 of this Form 10-K).compliance throughout 2018.
Annual interest payments on the Senior Notes total $160 million.are estimated to be approximately $150 million in 2018. No principal payments are required until each series’ final maturity date. Management believes that cash flows from operating activities, existing cash balances, and amounts available under the revolving credit facilityour Revolving Credit Facility will be sufficient to satisfy the Company’s cash requirements for the following twelve months. The Company expects
Additional information related to utilize its revolving credit facilityour Senior Notes and Revolving Credit Facility is described in Note 5 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K and the first or second quarter of 2015 to fund the final shipyard paymentinformation discussed therein is incorporated by reference into this Part II, Item 7.for the Rowan Relentless.
Restrictive provisions in the Company’s bank credit facility agreement limit consolidated debt to 60% of book capitalization. Our consolidated debt to total capitalization ratio at December 31, 2014, was 37%.
Other provisions of our debt agreements limit the ability of the Company to create liens that secure debt, engage in sale and leaseback transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. Additionally, our credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2014, and expects to remain in compliance throughout 2015.
Cash Dividends
In January 2016, the Company announced that it had discontinued its quarterly dividend.
Prior to 2014, the Company had not paid a quarterly cash dividend since 2008. On April 25, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on May 20, 2014, to shareholders of record at the close of business on May 5, 2014. On July 31, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on August 26, 2014, to shareholders of record at the close of business on August 11, 2014. On October 30, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on November 25, 2014, to shareholders of record at the close of business on November 11, 2014. On January 29,Cash dividends for 2015 the Board of Directors approved a quarterly cash dividend of $0.10 per share payable on March 3, 2015, to shareholders of record at the close of business on February 9, 2015.are set forth below:
In September 2014 we completed a capital reduction under U.K. law, which increased the Company's distributable reserves and will provide the Company with greater flexibility to increase shareholder return in the form of dividends and share repurchases.
The capital reduction was authorized by our Board of Directors and approved by our shareholders at a general meeting in August 2014. The capital reduction was achieved through the issuance and cancellation of $2.0 billion of newly created Class C shares pursuant to a customary, court approved process in the U.K.
The capital reduction shares had no substantive economic rights, provided no voting rights and otherwise provided extremely limited rights (e.g., no right to receive any dividends or other distributions). The capital reduction shares were cancelled in September 2014, and $2.0 billion of shareholders’ equity of Rowan plc that was not previously available for distribution under U.K. law became available for dividends, future distributions or share repurchases, as may be determined by our Board of Directors, subject to compliance with applicable rules and limitations under U.K. law.
The capital reduction did not involve any distribution or repayment of capital, nor did it have an impact on the underlying net assets of the Company. There was no net impact on our shareholders’ equity as a result of the capital reduction.
|
| | | | | | | | | |
| | Cash dividend per share | | Declaration date | | Record date | | Payment date |
| 2015: | | | | | | | |
| First quarter | $ | 0.10 |
| | 1/29/2015 | | 2/9/2015 | | 3/3/2015 |
| Second quarter | 0.10 |
| | 5/1/2015 | | 5/12/2015 | | 5/26/2015 |
| Third quarter | 0.10 |
| | 7/31/2015 | | 8/11/2015 | | 8/25/2015 |
| Fourth quarter | 0.10 |
| | 10/29/2015 | | 11/9/2015 | | 11/23/2015 |
Off-balance Sheet Arrangements and Contractual Obligations
The Company had no off-balance sheet arrangements as of December 31, 20142017 or 2013,2016, other than operating lease obligations and other commitments in the ordinary course of business.
The following is a summary of our contractual obligations at December 31, 2014,2017, including obligations recognized on our balance sheet and those not required to be recognized (in millions):
| | | | Payments due by period | Payments due by period |
| | Total | | Within 1 year | | 2 to 3 years | | 4 to 5 years | | After 5 years | Total | | Within 1 year | | 2 to 3 years | | 4 to 5 years | | After 5 years |
| Long-term debt, including interest | $ | 4,392 |
| | $ | 160 |
| | $ | 720 |
| | $ | 779 |
| | $ | 2,733 |
| |
| Newbuild construction contracts | 527 |
| | 527 |
| | — |
| | — |
| | — |
| |
| Long-term debt principal payment | | $ | 2,520 |
| | $ | — |
| | $ | 201 |
| | $ | 621 |
| | $ | 1,698 |
|
| Interest on Senior Notes | | 1,696 |
| | 147 |
| | 271 |
| | 245 |
| | 1,033 |
|
| Purchase obligations | 210 |
| | 210 |
| | — |
| | — |
| | — |
| 80 |
| | 80 |
| | — |
| | — |
| | — |
|
| Operating leases | 46 |
| | 7 |
| | 12 |
| | 11 |
| | 16 |
| 37 |
| | 12 |
| | 12 |
| | 3 |
| | 10 |
|
| Total | $ | 5,175 |
| | $ | 904 |
| | $ | 732 |
| | $ | 790 |
| | $ | 2,749 |
| $ | 4,333 |
| | $ | 239 |
| | $ | 484 |
| | $ | 869 |
| | $ | 2,741 |
|
As of December 31, 2014,2017, our liability for unrecognized tax benefits related to uncertain tax positions totaled $62.8$113 million, inclusive of interest and penalties. Due to the high degree of uncertainty related to these tax matters, we are unable to make a reasonably reliable estimate as to the timing of cash settlement with the respective taxing authorities, and we have therefore excluded this amount from the contractual obligations presented in the table above.
We periodically employ letters of credit or other bank-issued guarantees in the normal course of our businesses,business and had outstanding letters of credit of approximately $22.3$7.3 million at December 31, 2014.2017, of which $5.0 million were issued under our Revolving Credit Facility.
Rowan has a potential obligation to fund ARO for newbuild jack-up rigs. See Note 1 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K and the information discussed therein is incorporated by reference into this Part II, Item 7. Pension Obligations
Minimum contributions under defined benefit pension plans are determined based upon actuarial calculations of pension assets and liabilities that involve, among other things, assumptions about long-term asset returns and interest rates. Similar calculations were used to estimate pension costs and obligations as reflected in our consolidated financial statements (see “Critical Accounting Policies and Management Estimates – Pension and other postretirement benefits)benefits”). As of December 31, 2014,2017, our financial statements reflected an aggregate unfunded pension liability of $216$226 million. We expect to make minimum contributions to our defined benefit pension plans of approximately $22$25 million in 2015,2018, and we will continue to make significant pension contributions over the next several years. Additional funding may be required if, for example, future interest rates or pension asset values decline.
decline or there are changes in legislation.
Contingent Liabilities
We are involved in various legal proceedings incidental to our businesses and are vigorously defending our position in all such matters. The Company believes that there are no known contingencies, claims or lawsuits that could have a material effect on its financial position, results of operations or cash flows.
CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES
Our significant accounting policies are presented in Note 2 of “Notes to Consolidated Financial Statements”our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. These policies and management judgments, assumptions and estimates made in their application underlie reported amounts of assets and liabilities at the date of the financial statements and reported amounts of revenuesrevenue and expenses during the reporting period. We believe that our most critical accounting policies and management estimates involve carrying values of long-lived assets, principles of consolidation and our equity method investment, pension and other postretirement benefit liabilities and costs (specifically assumptions used in actuarial calculations), and income taxes (particularly our estimated reserves for uncertain tax positions), as changes in such policies and/or estimates would produce significantly different amounts from those reported herein.
ImpairmentDepreciation and impairments of long-lived assets and Depreciation
We evaluate the carrying value of our property and equipment, primarily our drilling rigs, whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Potential impairment indicators include rapid declines in commodity prices, stock prices, day rates and utilization, among others. The offshore drilling industry has historically been highly cyclical and it is not unusual for rigs to be unutilized or underutilized for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Similarly, during periods of excess supply, rigs may be contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to specific individual rigs, groups of rigs, such as a specific type of drilling rig, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.
Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements of our drilling rigs. The estimates, judgments and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and operating results.
Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling rigs over the next few years; and the finalization of the Company's 2015 operating budget, among others, we conducted an impairment test of our assets and determined that the carrying values of our twelve oldest jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized a noncash asset impairment charge of $565.7 million (approximately 7% of total assets) in the fourth quarter of 2014. Also in 2014, we recognized an $8.3 million noncash impairment charge on a Company aircraft, which we sold later in 2014 at an immaterial loss. (See Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K.)
We depreciate our assets using the straight-line method over their estimated useful service lives after allowing for salvage values. We estimate useful lives and salvage values by applying judgments and assumptions that reflect both historical experience and expectations regarding future operations, utilization and performance. Useful lives may be affected by a variety of factors including technological advances in methods of oil and gas exploration, changes in market or economic conditions, and changes in laws or regulations that affect the drilling industry. Applying different judgments and assumptions in establishing useful lives and salvage values may result in carrying values that differ from recorded amounts. In connection with
We evaluate the completioncarrying value of the assetour property and equipment, primarily our drilling rigs, whenever events or changes in circumstances indicate that their carrying values may not be recoverable. Potential impairment testindicators include rapid declines in 2014, we evaluated our policycommodity prices, stock prices, rig utilization and day rates, among others. The offshore drilling industry has historically been highly cyclical, and it is not unusual for rigs to be underutilized or idle for extended periods of time and subsequently resume full or near full utilization when business cycles improve. Similarly, during periods of excess supply, rigs may be contracted at or near cash break-even rates for extended periods. Impairment situations may arise with respect to salvagespecific rigs, specific categories or classes of rigs, or rigs in a certain geographic region. Our rigs are mobile and may generally be moved from regions with excess supply, if economically feasible.
Asset impairment evaluations are, by nature, highly subjective. In most instances, they involve expectations of future cash flows to be generated by our drilling rigs and are based on management's judgments and assumptions regarding future industry conditions and operations, as well as management's estimates of future expected utilization, contract rates, expense levels and capital requirements. The estimates, judgments, and assumptions used by management in the application of our asset impairment policies reflect both historical experience and an assessment of current operational, industry, market, economic and political environments. The use of different estimates, judgments, assumptions (including discount rates) and expectations regarding future industry conditions and operations would likely result in materially different asset carrying values and in lightoperating results.
We conducted an impairment test of our historical experience,assets during the fourth quarter of 2017; however, the test resulted in no impairment as the estimated undiscounted cash flows from the assets exceeded the assets' carrying values (see Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K).
In 2016 and 2015, we reduced salvageconducted impairment tests of our assets and determined that the carrying values of certain jack-up rigs were not recoverable from their undiscounted cash flows and exceeded their fair values. As a result, we recognized non-cash asset impairment charges of approximately $34 million and $330 million in 2016 and 2015, respectively (see Note 2 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K). Principles of Consolidation
The consolidated financial statements include our accounts and those of our wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Investments in operating entities where we have the ability to exercise significant influence, but where we do not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if we have an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our proportionate share of earnings or losses and distributions. We account for our jack-up rigs from 20 percentinterest in ARO using the equity method of accounting and only recognize our portion of equity earnings in our consolidated financial statements. ARO is a variable interest entity; however, we are not the primary beneficiary and therefore do not consolidate ARO. Our judgment regarding the level of influence over ARO included considering key factors such as each company's ownership interest, representation on the board of managers of ARO, ability to 10 percent of historical cost.
direct activities that most significantly impact the ARO's economic performance, as well as the ability to influence policy-making decisions.
Pension and other postretirement benefits
Our pension and other postretirement benefit liabilities and costs are based upon actuarial computations that reflect our assumptions about future events, including long-term asset returns, interest rates, annual compensation increases, mortality rates and other factors. Key assumptions at December 31, 2014,2017, included i) a weighted average discount ratesrate of 4.12% and 4.83% used3.68% to determine pension benefit obligations, ii) a weighted average discount rate of 4.29% to determine net periodic pension cost and net cost, respectively,iii), an expected long-term rate of return on pension plan assets of 7.45% and annual healthcare cost increases ranging from 7.0% in 2015 to 4.5% in 2026 and beyond.6.70%. The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds, and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations. A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $121.2$103.9 million, while a one-percentage-point decrease (increase) in the expected long-term rate of return on plan assets would increase (decrease) annual net benefits cost by approximately $5.2 million. A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2015 other postretirement benefit cost by $0.3$5.3 million. To develop the expected long-term rate of return on assets assumption, we considered the current level of expected returns on risk-free investments (primarily government bonds), the
historical level of the risk premium associated with the plans’ other asset classes, and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plan, which was reduced to 7.45%6.70% at December 31, 2014,2017, from 8%7.15% at December 31, 2013.
2016.
Income taxes
In accordance with accounting guidelines for income tax uncertainties, we evaluate each tax position to determine if it is more likely than not that the tax position will be sustained upon examination, based on its merits. A tax position that meets the more-likely-than-not recognition threshold is subject to a measurement assessment to determine the amount of benefit to recognize in income for the period and a reserve, if any. Our incomeappropriate reserve. Income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities.taxing authorities in most jurisdictions. Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows. We believe our reserve for uncertain tax positions totaling $55$102 million at December 31, 2014,2017, is properly recorded in accordance with the accounting guidelines.
On December 22, 2017, the U.S. Tax Act was enacted into law and the new legislation contains several key tax provisions, including a one-time mandatory transition tax on certain non-U.S. earnings, a reduction of the corporate income tax rate to 21%, a change in the taxability of certain non-U.S. subsidiaries, an additional tax on certain payments made from U.S. affiliates to non-U.S. affiliates, a limitation on interest deduction and a tax imposed on non-U.S. income in excess of a deemed return on tangible assets of non-U.S. corporations among others. In December 2017, the SEC staff issued Staff Accounting Bulletin No. 118, Income Tax Accounting Implications of the Tax Cuts and Jobs Act (SAB 118), which allows us to record provisional amounts during a measurement period not to extend beyond one year of the enactment date. Since the U.S. Tax Act was passed late in the fourth quarter of 2017, we consider our accounting of the one-time transition tax, deferred tax remeasurements, and other impacted items to be incomplete due to expected issuance of accounting interpretations and our ongoing analysis of data and tax positions. We expect to complete our analysis within the measurement period in accordance with SAB 118.
In January 2018, the FASB released guidance on the accounting for tax on the global intangible low-taxed income ("GILTI") provisions of the U.S. Tax Act. The GILTI provisions impose a tax on non-U.S. income in excess of a deemed return on tangible assets of non-U.S. corporations. The guidance indicates that either accounting for deferred taxes related to GILTI inclusions or
treating any taxes on GILTI inclusions as period cost are both acceptable methods subject to an accounting policy election. The Company is still evaluating which accounting policy to elect but currently believes the impact to the financial statements will be immaterial.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-08,Information relating to recent accounting pronouncements is described in Reporting Discontinued Operations and Disclosures of Disposals of Components of an EntityNote 2 ("ASU 2014-08"), which limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results. Under current guidelines prior to the effective date of ASU 2014-08, many disposals that were routine in nature and not a change in an entity's strategy were reported in discontinued operations. The provisions of the new standard will apply to disposals (or classifications as held for sale) of components of an entity occurring in annual and interim periods beginning in 2015. We do not expect adoption of the standard will have a material effect on our consolidated financial statements orin Part II, Item 8 of this Annual Report on Form 10-K and the notes thereto.information discussed therein is incorporated by reference into this Part II, Item 7.
In May 2014, the FASB issued Accounting Standards Update No. 2014-09, Revenue from Contracts with Customers, which sets forth a global standard for revenue recognition and which replaces most existing industry-specific guidance. We will be required to adopt the new standard in annual and interim reports for periods beginning January 1, 2017. We are currently evaluating the potential effect of the new guidance.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISKS
Interest rate risk – Our outstanding debt at December 31, 2014,2017, consisted entirely of fixed-rate debt with a carrying value of $2.807$2.510 billion and a weighted-average annual interest rate of 5.6%5.8%. DueWe are subject to interest rate risk on our fixed-interest rate borrowings. Fixed rate debt, where the fixed-rate natureinterest rate is fixed over the life of our debt, management believes the risk of loss dueinstrument, exposes us to changes in market interest rates is not material.reflected in the fair value of the debt and to the risk that we may need to refinance maturing debt with new debt at a higher rate.
Our Long-term note receivable from unconsolidated subsidiary consisted of a 10-year shareholder note receivable from ARO at a stated interest rate of LIBOR plus two percent with a carrying value of $270.2 million at December 31, 2017. A one-percentage-point decrease in LIBOR would decrease our interest income by approximately $3 million in the next twelve months, while a one-percentage-point increase in LIBOR would increase our interest income by approximately $3 million in the same period.
In order to reduce the impact ofCurrency exchange rate fluctuations, we generally require customer payments to berisk – A substantial majority of our revenue is received in U.S. dollars and try to limit local currency holdings to the extent they are needed to pay liabilities denominatedUSD, which is our functional currency. However, in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive some payment in the local currency. In such instances, we may beWe are exposed to devaluation and otherforeign 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 loss. Inrate risk, we attempt to limit foreign currency holdings to the event we terminate operations in such countries we may not be ableextent they are needed to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where we hold approximately $15.2 million in Egyptian pounds, based on exchange rates in effect at January 31, 2015. We can provide no assurance we will be able to convert, utilize or repatriate such fundspay liabilities in the future.local currency. We did not enter into such transactions for the purpose of speculation, trading or investing in the market. Our risk policy allows us to enter into such forward exchange contracts; however, we do not currently anticipate entering into such transactions in the future and had no such contracts outstanding as of December 31, 2017.
Commodity price risk – Fluctuating commodity prices affect our future earnings materially to the extent that they influence demand for our products and services. As a general practice, we do not hold or issue derivative financial instruments and had no derivatives outstanding during the periods covered by this report.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Rowan Companies plc and subsidiaries (the “Company”) as of December 31, 20142017 and 2013, and2016, the related consolidated statements of income,operations, comprehensive income, stockholders’changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are2017, and the responsibility ofrelated notes and the Company’s management. Our responsibility is to express an opinion on the financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosuresschedule listed in the financial statements. An audit also includes assessingIndex at Item 15 (collectively referred to as the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
"financial statements"). In our opinion, such consolidatedthe financial statements present fairly, in all material respects, the financial position of Rowan Companies plc and subsidiariesthe Company as of December 31, 20142017 and 2013,2016, and the results of theirits operations and theirits cash flows for each of the three years in the period ended December 31, 2014,2017, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2014,2017, based on the criteria established in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 2, 2015February 28, 2018, expressed an unqualified opinion on the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 2 to the financial statements, the Company has changed its method of accounting for current and deferred income tax effects for intra-entity transfers of assets other than inventory in 2017 due to the adoption of Accounting Standards Update No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory.
Basis for Opinion
These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud.Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 2, 2015February 28, 2018
We have served as the Company’s auditor since 1966.
41
ROWAN COMPANIES PLC
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of Rowan is responsible for establishing and maintaining adequate internal control over financial reporting for the Company as defined in Rules 13a-15(f) and 15d-15(f) of the Securities Exchange Act of 1934, as amended. Our internal controls were designed to provide reasonable assurance as to the reliability of our financial reporting and the preparation and presentation of consolidated financial statements in accordance with accounting principles generally accepted in the United States, as well as to safeguard assets from unauthorized use or disposition.
We are required to assess the effectiveness of our internal controls relative to a suitable framework. The Committee of Sponsoring Organizations of the Treadway Commission (COSO) in its Internal Control - Integrated Framework (2013), developed a formalized, organization-wide framework that embodies five interrelated components — the control environment, risk assessment, control activities, information and communication and monitoring, as they relate to three internal control objectives — operating effectiveness and efficiency, financial reporting reliability and compliance with laws and regulations.
Our assessment included an evaluation of the design of our internal control over financial reporting relative to COSO and testing of the operational effectiveness of our internal control over financial reporting. Based upon our assessment, we have concluded that our internal controls over financial reporting were effective as of December 31, 2014.
2017.
The independent registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements and financial statement schedule included in our 20142017 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.
|
| |
| /s/ THOMAS P. BURKE | /s/ STEPHEN M. BUTZ |
| Thomas P. Burke | Stephen M. Butz |
| President and Chief Executive Officer | Executive Vice President and Chief Financial Officer and Treasurer |
| | |
| | |
March 2, 2015February 28, 2018 | March 2, 2015February 28, 2018 |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the shareholders and the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas
Opinion on Internal Control over Financial Reporting
We have audited the internal control over financial reporting of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2014,2017, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control - Integrated Framework(2013) issued by COSO.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements and financial statement schedule as of and for the year ended December 31, 2017, of the Company and our report dated February 28, 2018 expressed an unqualified opinion on those financial statements and financial statement schedule, and included an explanatory paragraph relating to the Company's adoption of Accounting Standards Update No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory.
Basis for Opinion
The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002.Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States).PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control over Financial Reporting
A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of theits inherent limitations, of internal control over financial reporting including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be preventedprevent or detected on a timely basis.detect misstatements. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014, of the Company and our report dated March 2, 2015 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
Houston, Texas
March 2, 2015February 28, 2018
ROWAN COMPANIES PLC
AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETSSTATEMENTS OF OPERATIONS
(In millions, except per share amounts)
|
| | | | | | | |
| | December 31, |
| | 2014 | | 2013 |
| | (In thousands, except shares) |
| ASSETS |
| CURRENT ASSETS: | | | |
| Cash and cash equivalents | $ | 339,154 |
| | $ | 1,092,844 |
|
| Receivables - trade and other | 545,204 |
| | 344,546 |
|
| Prepaid expenses and other current assets | 29,253 |
| | 45,538 |
|
| Deferred income taxes - net | 27,485 |
| | 22,137 |
|
| Assets of discontinued operations | — |
| | 23,813 |
|
| Total current assets | 941,096 |
| | 1,528,878 |
|
| | | | |
| PROPERTY, PLANT AND EQUIPMENT: | |
| | |
|
| Drilling equipment | 7,639,171 |
| | 7,040,451 |
|
| Construction in progress | 1,023,646 |
| | 1,009,380 |
|
| Other property and equipment | 137,365 |
| | 147,884 |
|
| Property, plant and equipment - gross | 8,800,182 |
| | 8,197,715 |
|
| Less accumulated depreciation and amortization | 1,367,970 |
| | 1,811,960 |
|
| Property, plant and equipment - net | 7,432,212 |
| | 6,385,755 |
|
| | | | |
| Other assets | 37,884 |
| | 61,128 |
|
| | | | |
| TOTAL ASSETS | $ | 8,411,192 |
| | $ | 7,975,761 |
|
| | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| CURRENT LIABILITIES: | |
| | |
|
| Accounts payable - trade | $ | 102,773 |
| | $ | 123,976 |
|
| Deferred revenues | 36,189 |
| | 54,515 |
|
| Accrued liabilities | 194,259 |
| | 155,971 |
|
| Liabilities of discontinued operations | — |
| | 20,122 |
|
| Total current liabilities | 333,221 |
| | 354,584 |
|
| | | | |
| Long-term debt | 2,807,324 |
| | 2,008,700 |
|
| Other liabilities | 368,266 |
| | 289,061 |
|
| Deferred income taxes - net | 210,982 |
| | 429,655 |
|
| Commitments and contingent liabilities (Note 7) | — |
| | — |
|
| | | | |
| SHAREHOLDERS' EQUITY: | |
| | |
|
| Class A Ordinary Shares, $0.125 par value, 124,828,807 and 124,778,407 shares issued at December 31, 2014 and 2013, respectively | 15,604 |
| | 15,597 |
|
| Additional paid-in capital | 1,436,910 |
| | 1,407,031 |
|
| Retained earnings | 3,466,993 |
| | 3,619,540 |
|
| Cost of 264,903 and 542,475 treasury shares at December 31, 2014 and 2013, respectively | (7,990 | ) | | (5,962 | ) |
| Accumulated other comprehensive loss | (220,118 | ) | | (142,445 | ) |
| Total shareholders' equity | 4,691,399 |
| | 4,893,761 |
|
| | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | $ | 8,411,192 |
| | $ | 7,975,761 |
|
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2017 | | 2016 | | 2015 |
| REVENUE | $ | 1,282.8 |
| | $ | 1,843.2 |
| | $ | 2,137.0 |
|
| | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
|
| Direct operating costs (excluding items below) | 684.8 |
| | 778.2 |
| | 993.1 |
|
| Depreciation and amortization | 403.7 |
| | 402.9 |
| | 391.4 |
|
| Selling, general and administrative | 104.9 |
| | 102.1 |
| | 115.8 |
|
| Gain on sale of assets to unconsolidated subsidiary | (157.4 | ) | | — |
| | — |
|
| (Gain) loss on disposals of property and equipment | 9.4 |
| | 8.7 |
| | (7.7 | ) |
| Material charges and other operating items | — |
| | 32.9 |
| | 337.3 |
|
| Total costs and expenses | 1,045.4 |
| | 1,324.8 |
| | 1,829.9 |
|
| | | | | | |
| Equity in earnings of unconsolidated subsidiary | 0.9 |
| | — |
| | — |
|
| | | | | | |
| INCOME FROM OPERATIONS | 238.3 |
| | 518.4 |
| | 307.1 |
|
| | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
|
| Interest expense, net of interest capitalized | (155.7 | ) | | (155.5 | ) | | (145.3 | ) |
| Interest income | 15.4 |
| | 3.8 |
| | 1.1 |
|
| Gain (Loss) on extinguishment of debt | 1.7 |
| | (31.2 | ) | | (1.5 | ) |
| Other - net | (0.4 | ) | | (9.9 | ) | | (3.7 | ) |
| Total other (expense) - net | (139.0 | ) | | (192.8 | ) | | (149.4 | ) |
| | | | | | |
| INCOME BEFORE INCOME TAXES | 99.3 |
| | 325.6 |
| | 157.7 |
|
| Provision for income taxes | 26.6 |
| | 5.0 |
| | 64.4 |
|
| | | | | | |
| NET INCOME | $ | 72.7 |
| | $ | 320.6 |
| | $ | 93.3 |
|
| | | | | | |
| NET INCOME PER SHARE - BASIC: | $ | 0.58 |
| | $ | 2.56 |
| | $ | 0.75 |
|
| | | | | | |
| NET INCOME PER SHARE - DILUTED: | $ | 0.57 |
| | $ | 2.55 |
| | $ | 0.75 |
|
ROWAN COMPANIES PLC
CONSOLIDATED STATEMENTS OF INCOME
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2014 | | 2013 | | 2012 |
| | (In thousands, except per share amounts) |
| REVENUES | $ | 1,824,383 |
| | $ | 1,579,284 |
| | $ | 1,392,607 |
|
| | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
|
| Direct operating costs (excluding items below) | 991,340 |
| | 860,893 |
| | 752,173 |
|
| Depreciation and amortization | 322,641 |
| | 271,008 |
| | 247,900 |
|
| Selling, general and administrative | 125,834 |
| | 131,373 |
| | 99,712 |
|
| Gain on disposals of property and equipment | (1,778 | ) | | (20,119 | ) | | (2,502 | ) |
| Litigation settlement | (20,875 | ) | | — |
| | (4,700 | ) |
| Material charges and other operating expenses | 573,950 |
| | 4,453 |
| | 44,972 |
|
| Total costs and expenses | 1,991,112 |
| | 1,247,608 |
| | 1,137,555 |
|
| | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (166,729 | ) | | 331,676 |
| | 255,052 |
|
| | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
|
| Interest expense, net of interest capitalized | (103,934 | ) | | (69,794 | ) | | (50,717 | ) |
| Interest income | 1,861 |
| | 1,578 |
| | 745 |
|
| Loss on debt extinguishment | — |
| | — |
| | (22,223 | ) |
| Other - net | (805 | ) | | (2,221 | ) | | 613 |
|
| Total other income (expense) - net | (102,878 | ) | | (70,437 | ) | | (71,582 | ) |
| | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS | |
| | |
| | |
|
| BEFORE INCOME TAXES | (269,607 | ) | | 261,239 |
| | 183,470 |
|
| Provision (benefit) for income taxes | (150,732 | ) | | 8,663 |
| | (19,829 | ) |
| | | | | | |
| NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (118,875 | ) | | 252,576 |
| | 203,299 |
|
| | | | | | |
| DISCONTINUED OPERATIONS: | |
| | |
| | |
|
| Income (loss) from discontinued operations, net of tax | 4,023 |
| | — |
| | (22,697 | ) |
| Discontinued operations, net of tax | 4,023 |
| | — |
| | (22,697 | ) |
| | | | | | |
| NET INCOME (LOSS) | $ | (114,852 | ) | | $ | 252,576 |
| | $ | 180,602 |
|
| | | | | | |
| INCOME (LOSS) PER SHARE - BASIC: | |
| | |
| | |
|
| Income (loss) from continuing operations | $ | (0.96 | ) | | $ | 2.04 |
| | $ | 1.65 |
|
| Discontinued operations | $ | 0.03 |
| | $ | — |
| | $ | (0.18 | ) |
| Net income (loss) | $ | (0.93 | ) | | $ | 2.04 |
| | $ | 1.47 |
|
| | | | | | |
| INCOME (LOSS) PER SHARE - DILUTED: | |
| | |
| | |
|
| Income (loss) from continuing operations | $ | (0.96 | ) | | $ | 2.03 |
| | $ | 1.64 |
|
| Discontinued operations | $ | 0.03 |
| | $ | — |
| | $ | (0.18 | ) |
| Net income (loss) | $ | (0.93 | ) | | $ | 2.03 |
| | $ | 1.46 |
|
See Notes to Consolidated Financial Statements.
ROWAN COMPANIES PLC
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(In millions)
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2014 | | 2013 | | 2012 |
| | (In thousands) |
| NET INCOME (LOSS) | $ | (114,852 | ) | | $ | 252,576 |
| | $ | 180,602 |
|
| | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS) | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income tax (benefit) expense of ($46,944), $34,092, and ($8,003), respectively | (87,293 | ) | | 63,315 |
| | (14,862 | ) |
| Net reclassification adjustments for amounts recognized in net income as a component of net periodic benefit cost, net of income tax expense of $5,261, $8,250, and $10,474, respectively | 9,824 |
| | 15,322 |
| | 19,451 |
|
| | | | | | |
| | (77,469 | ) | | 78,637 |
| | 4,589 |
|
| | | | | | |
| COMPREHENSIVE INCOME (LOSS) | $ | (192,321 | ) | | $ | 331,213 |
| | $ | 185,191 |
|
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2017 | | 2016 | | 2015 |
| NET INCOME | $ | 72.7 |
| | $ | 320.6 |
| | $ | 93.3 |
|
| | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS) | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income (loss), net of income tax expense (benefit) of $0, $(2.8), and $3.4, respectively. | (33.3 | ) | | (5.1 | ) | | 7.0 |
|
| Net reclassification adjustment for amounts recognized in net income as a component of net periodic benefit cost, net of income tax expense of $0, $3.8, and $7.4, respectively. | 11.4 |
| | 7.4 |
| | 13.8 |
|
| | | | | | |
| | (21.9 | ) | | 2.3 |
| | 20.8 |
|
| | | | | | |
| COMPREHENSIVE INCOME | $ | 50.8 |
| | $ | 322.9 |
| | $ | 114.1 |
|
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(In millions, except par value)
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| ASSETS | | | |
| | | | |
| CURRENT ASSETS: | | | |
| Cash and cash equivalents | $ | 1,332.1 |
| | $ | 1,255.5 |
|
| Receivables - trade and other | 212.8 |
| | 301.3 |
|
| Prepaid expenses and other current assets | 15.5 |
| | 23.5 |
|
| Total current assets | 1,560.4 |
| | 1,580.3 |
|
| | | | |
| PROPERTY AND EQUIPMENT: | |
| | |
|
| Drilling equipment | 8,697.8 |
| | 8,965.3 |
|
| Other property and equipment | 136.1 |
| | 135.5 |
|
| Property and equipment - gross | 8,833.9 |
| | 9,100.8 |
|
| Less accumulated depreciation and amortization | 2,281.2 |
| | 2,040.8 |
|
| Property and equipment - net | 6,552.7 |
| | 7,060.0 |
|
| | | | |
| Long-term note receivable from unconsolidated subsidiary | 270.2 |
| | — |
|
| | | | |
| Investment in unconsolidated subsidiary | 30.9 |
| | — |
|
| | | | |
| Other assets | 44.1 |
| | 35.3 |
|
| | $ | 8,458.3 |
| | $ | 8,675.6 |
|
| | | | |
| LIABILITIES AND SHAREHOLDERS' EQUITY | | | |
| | | | |
| CURRENT LIABILITIES: | |
| | |
|
| Current portion of long-term debt | $ | — |
| | $ | 126.8 |
|
| Accounts payable - trade | 97.2 |
| | 94.3 |
|
| Deferred revenue | 1.1 |
| | 103.9 |
|
| Accrued liabilities | 159.1 |
| | 158.8 |
|
| Total current liabilities | 257.4 |
| | 483.8 |
|
| | | | |
| Long-term debt, less current portion | 2,510.3 |
| | 2,553.4 |
|
| Other liabilities | 293.6 |
| | 338.8 |
|
| Deferred income taxes - net | 10.9 |
| | 185.7 |
|
Commitments and contingent liabilities (Note 8) |
|
| |
|
|
| | | | |
| SHAREHOLDERS' EQUITY: | |
| | |
|
| Class A Ordinary Shares, $0.125 par value; 128.1 and 128.0 shares issued, respectively; 126.3 and 125.5 shares outstanding, respectively | 16.0 |
| | 16.0 |
|
| Additional paid-in capital | 1,488.6 |
| | 1,471.7 |
|
| Retained earnings | 4,109.7 |
| | 3,830.4 |
|
| Cost of 1.8 and 2.5 treasury shares, respectively | (9.3 | ) | | (7.2 | ) |
| Accumulated other comprehensive loss | (218.9 | ) | | (197.0 | ) |
| Total shareholders' equity | 5,386.1 |
| | 5,113.9 |
|
| | $ | 8,458.3 |
| | $ | 8,675.6 |
|
ROWAN COMPANIES PLC AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(In millions)
| | | | Shares outstanding | | Class A Ordinary Shares/ Common stock | | Additional paid-in capital | | Retained earnings | | Treasury shares | | Accumulated other comprehensive income (loss) | | Total shareholders' equity | Shares outstanding | | Class A Ordinary Shares/ Common stock | | Additional paid-in capital | | Retained earnings | | Treasury shares | | Accumulated other comprehensive income (loss) | | Total shareholders' equity |
| | (In thousands) | |
| Balance, January 1, 2012 | 123,581 |
| | $ | 15,947 |
| | $ | 1,478,233 |
| | $ | 3,186,362 |
| | $ | (128,884 | ) | | $ | (225,671 | ) | | $ | 4,325,987 |
| |
| Balance, January 1, 2015 | | 124.6 |
| | $ | 15.6 |
| | $ | 1,436.9 |
| | $ | 3,467.0 |
| | $ | (8.0 | ) | | $ | (220.1 | ) | | $ | 4,691.4 |
|
| Net shares issued (acquired) under share-based compensation plans | 578 |
| | 65 |
| | (21,212 | ) | | — |
| | 17,511 |
| | — |
| | (3,636 | ) | 0.2 |
| | 0.1 |
| | 0.4 |
| | — |
| | (4.2 | ) | | — |
| | (3.7 | ) |
| Share-based compensation | — |
| | — |
| | 23,018 |
| | — |
| | — |
| | — |
| | 23,018 |
| — |
| | — |
| | 23.8 |
| | — |
| | — |
| | — |
| | 23.8 |
|
| Excess tax benefit from share-based compensation plans | — |
| | — |
| | 1,164 |
| | — |
| | — |
| | — |
| | 1,164 |
| |
| Retirement benefit adjustments, net of taxes of $2,472 | — |
| | — |
| | — |
| | — |
| | — |
| | 4,589 |
| | 4,589 |
| |
| Cancelation of treasury shares | — |
| | (419 | ) | | (109,068 | ) | | — |
| | 109,487 |
| | — |
| | — |
| |
| Excess tax deficit from share-based awards | | — |
| | — |
| | (2.6 | ) | | — |
| | — |
| | — |
| | (2.6 | ) |
| Retirement benefit adjustments, net of tax expense of $10.8 | | — |
| | — |
| | — |
| | — |
| | — |
| | 20.8 |
| | 20.8 |
|
| Dividends | | — |
| | — |
| | — |
| | (50.5 | ) | | — |
| | — |
| | (50.5 | ) |
| Other | 52 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Net income | — |
| | — |
| | — |
| | 180,602 |
| | — |
| | — |
| | 180,602 |
| — |
| | — |
| | — |
| | 93.3 |
| | — |
| | — |
| | 93.3 |
|
| Balance, December 31, 2012 | 124,211 |
| | 15,593 |
| | 1,372,135 |
| | 3,366,964 |
| | (1,886 | ) | | (221,082 | ) | | 4,531,724 |
| |
| Balance, December 31, 2015 | | 124.8 |
| | 15.7 |
| | 1,458.5 |
| | 3,509.8 |
| | (12.2 | ) | | (199.3 | ) | | 4,772.5 |
|
| Net shares issued (acquired) under share-based compensation plans | 26 |
| | 4 |
| | 2,330 |
| | — |
| | (4,076 | ) | | — |
| | (1,742 | ) | 0.7 |
| | 0.3 |
| | (9.8 | ) | | — |
| | 5.0 |
| | — |
| | (4.5 | ) |
| Share-based compensation | — |
| | — |
| | 27,056 |
| | — |
| | — |
| | — |
| | 27,056 |
| — |
| | — |
| | 20.4 |
| | — |
| | — |
| | — |
| | 20.4 |
|
| Excess tax benefit from share-based compensation plans | — |
| | — |
| | 3,690 |
| | — |
| | — |
| | — |
| | 3,690 |
| |
| Retirement benefit adjustments, net of taxes of $42,342 | — |
| | — |
| | — |
| | — |
| | — |
| | 78,637 |
| | 78,637 |
| |
| Other | — |
| | — |
| | 1,820 |
| | — |
| | — |
| | — |
| | 1,820 |
| |
| Excess tax benefit from share-based awards | | — |
| | — |
| | 2.6 |
| | — |
| | — |
| | — |
| | 2.6 |
|
| Retirement benefit adjustments, net of tax expense of $1.0 | | — |
| | — |
| | — |
| | — |
| | — |
| | 2.3 |
| | 2.3 |
|
| Net income | — |
| | — |
| | — |
| | 252,576 |
| | — |
| | — |
| | 252,576 |
| — |
| | — |
| | — |
| | 320.6 |
| | — |
| | — |
| | 320.6 |
|
| Balance, December 31, 2013 | 124,237 |
| | 15,597 |
| | 1,407,031 |
| | 3,619,540 |
| | (5,962 | ) | | (142,445 | ) | | 4,893,761 |
| |
| Balance, December 31, 2016 | | 125.5 |
| | 16.0 |
| | 1,471.7 |
| | 3,830.4 |
| | (7.2 | ) | | (197.0 | ) | | 5,113.9 |
|
| Net shares issued (acquired) under share-based compensation plans | 327 |
| | 7 |
| | 1,566 |
| | — |
| | (2,028 | ) | | — |
| | (455 | ) | 0.8 |
| | — |
| | (2.4 | ) | | — |
| | (2.1 | ) | | — |
| | (4.5 | ) |
| Share-based compensation | — |
| | — |
| | 28,445 |
| | — |
| | — |
| | — |
| | 28,445 |
| — |
| | — |
| | 19.3 |
| | — |
| | — |
| | — |
| | 19.3 |
|
| Excess tax benefit from share-based compensation plans | — |
| | — |
| | (132 | ) | | — |
| | — |
| | — |
| | (132 | ) | |
| Retirement benefit adjustments, net of tax benefit of $41,683 | — |
| | — |
| | — |
| | — |
| | — |
| | (77,469 | ) | | (77,469 | ) | |
| Dividends | — |
| | — |
| | — |
| | (37,695 | ) | | — |
| | — |
| | (37,695 | ) | |
| Other | — |
| | — |
| | — |
| | — |
| | — |
| | (204 | ) | | (204 | ) | |
| Net loss | — |
| | — |
| | — |
| | (114,852 | ) | | — |
| | — |
| | (114,852 | ) | |
| Balance, December 31, 2014 | 124,564 |
| | $ | 15,604 |
| | $ | 1,436,910 |
| | $ | 3,466,993 |
| | $ | (7,990 | ) | | $ | (220,118 | ) | | $ | 4,691,399 |
| |
Adoption of new accounting standard (see Note 2) | | — |
| | — |
| | — |
| | 206.6 |
| | — |
| | — |
| | 206.6 |
|
| Retirement benefit adjustments, net of tax expense of $0 | | — |
| | — |
| | — |
| | — |
| | — |
| | (21.9 | ) | | (21.9 | ) |
| Net income | | — |
| | — |
| | — |
| | 72.7 |
| | — |
| | — |
| | 72.7 |
|
| Balance, December 31, 2017 | | 126.3 |
| | $ | 16.0 |
| | $ | 1,488.6 |
| | $ | 4,109.7 |
| | $ | (9.3 | ) | | $ | (218.9 | ) | | $ | 5,386.1 |
|
ROWAN COMPANIES PLC
AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
| | | | Years ended Years ended December 31, | Years ended December 31, |
| | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| | (In thousands) | |
| CASH PROVIDED BY OPERATIONS: | | | | | | |
| Net income (loss) | $ | (114,852 | ) | | $ | 252,576 |
| | $ | 180,602 |
| |
| Adjustments to reconcile net income (loss) to net cash provided by operations: | |
| | |
| | |
| |
| CASH FLOWS FROM OPERATING ACTIVITIES: | | | | | | |
| Net income | | $ | 72.7 |
| | $ | 320.6 |
| | $ | 93.3 |
|
| Adjustments to reconcile net income to net cash provided by operating activities: | | |
| | |
| | |
|
| Depreciation and amortization | 322,641 |
| | 271,008 |
| | 247,900 |
| 403.7 |
| | 402.9 |
| | 392.7 |
|
| Provision for pension and postretirement benefits | 25,117 |
| | 32,010 |
| | 39,484 |
| |
| Equity in earnings of unconsolidated subsidiary | | (0.9 | ) | | — |
| | — |
|
| Deferred income taxes | | 24.7 |
| | (37.9 | ) | | (1.1 | ) |
| Provision for pension and other postretirement benefits | | 12.5 |
| | 15.0 |
| | 34.0 |
|
| Share-based compensation expense | 34,547 |
| | 33,931 |
| | 24,808 |
| 29.0 |
| | 34.6 |
| | 33.6 |
|
| Other postretirement benefit claims paid | (4,125 | ) | | (3,470 | ) | | (3,811 | ) | |
| Gain on disposals of property, plant and equipment | (3,691 | ) | | (20,119 | ) | | (2,502 | ) | |
| Deferred income taxes | (182,544 | ) | | (33,559 | ) | | (4,649 | ) | |
| Contributions to pension plans | (54,834 | ) | | (18,860 | ) | | (42,055 | ) | |
| Write-off of deferred debt issuance costs | — |
| | — |
| | 690 |
| |
| Gain on sale of assets to unconsolidated subsidiary | | (157.4 | ) | | — |
| | — |
|
| (Gain) loss on disposals of property and equipment | | 9.4 |
| | 8.7 |
| | (7.7 | ) |
| Contingent payment derivative | | 0.1 |
| | (6.1 | ) | | — |
|
| Asset impairment charges | 573,950 |
| | 4,453 |
| | 12,038 |
| — |
| | 34.3 |
| | 329.8 |
|
| Other | | 1.5 |
| | 3.7 |
| | 0.5 |
|
| Changes in current assets and liabilities: | |
| | |
| | |
| |
| | |
| | |
|
| Receivables - trade and other | (200,658 | ) | | 30,784 |
| | (105,762 | ) | 82.9 |
| | 109.2 |
| | 134.7 |
|
| Prepaid expenses and other current assets | 16,328 |
| | 9,583 |
| | (9,879 | ) | 14.2 |
| | 9.2 |
| | 0.6 |
|
| Accounts payable | (20,629 | ) | | 32,373 |
| | (8,608 | ) | 1.9 |
| | (4.0 | ) | | 23.2 |
|
| Accrued income taxes | 4,891 |
| | (17,714 | ) | | 16,210 |
| (3.8 | ) | | (3.4 | ) | | 10.6 |
|
| Deferred revenues | (18,326 | ) | | 2,175 |
| | 16,120 |
| |
| Other current liabilities | 72,897 |
| | (12,441 | ) | | 17,873 |
| 7.8 |
| | (27.2 | ) | | (11.9 | ) |
| Other postretirement benefit claims paid | | (18.4 | ) | | (7.9 | ) | | (4.4 | ) |
| Contributions to pension plans | | (29.3 | ) | | (22.5 | ) | | (11.4 | ) |
| Deferred revenue | | (112.8 | ) | | 63.7 |
| | (3.1 | ) |
| Net changes in other noncurrent assets and liabilities | (27,753 | ) | | 60,446 |
| | 15,250 |
| (38.0 | ) | | 12.7 |
| | (15.3 | ) |
| Net cash provided by operations | 422,959 |
| | 623,176 |
| | 393,709 |
| |
| Net cash provided by operating activities | | 299.8 |
| | 905.6 |
| | 998.1 |
|
| | | | | | | | | | | |
| CASH USED IN INVESTING ACTIVITIES: | |
| | |
| | |
| |
| CASH FLOWS FROM INVESTING ACTIVITIES: | | |
| | |
| | |
|
| Capital expenditures | (1,958,227 | ) | | (607,311 | ) | | (685,256 | ) | (100.6 | ) | | (117.6 | ) | | (722.9 | ) |
| Proceeds from disposals of property, plant and equipment | 21,987 |
| | 44,550 |
| | 10,500 |
| |
| Deposit on purchase of rigs | | (7.7 | ) | | — |
| | — |
|
| Investment in unconsolidated subsidiary | | (30.0 | ) | | — |
| | — |
|
| Contributions to unconsolidated subsidiary for note receivable | | (357.7 | ) | | — |
| | — |
|
| Proceeds from sale of assets to unconsolidated subsidiary | | 357.7 |
| | — |
| | — |
|
| Repayments of note receivable from unconsolidated subsidiary | | 87.5 |
| | — |
| | — |
|
| Proceeds from disposals of property and equipment | | 3.3 |
| | 6.2 |
| | 19.4 |
|
| Net cash used in investing activities | (1,936,240 | ) | | (562,761 | ) | | (674,756 | ) | (47.5 | ) | | (111.4 | ) | | (703.5 | ) |
| | | | | | | | | | | |
| CASH PROVIDED BY FINANCING ACTIVITIES: | |
| | |
| | |
| |
| CASH FLOWS FROM FINANCING ACTIVITIES: | | |
| | |
| | |
|
| Proceeds from borrowings | 793,380 |
| | — |
| | 1,104,929 |
| — |
| | 500.0 |
| | 220.0 |
|
| Reductions of long-term debt | | (170.0 | ) | | (511.8 | ) | | (317.9 | ) |
| Dividends paid | (37,695 | ) | | — |
| | — |
| — |
| | — |
| | (50.5 | ) |
| Debt issue costs | (687 | ) | | — |
| | (2,026 | ) | — |
| | (8.7 | ) | | — |
|
| Repayments of borrowings | — |
| | — |
| | (238,453 | ) | |
| Proceeds from exercise of share options | 4,725 |
| | 2,911 |
| | 588 |
| |
| Shares repurchased for tax withholdings on vesting of restricted share units | | (5.7 | ) | | (5.0 | ) | | (1.2 | ) |
| Excess tax benefits from share-based compensation | (132 | ) | | 3,690 |
| | 1,164 |
| — |
| | 2.6 |
| | — |
|
| Other | — |
| | 1,820 |
| | — |
| |
| Net cash provided by financing activities | 759,591 |
| | 8,421 |
| | 866,202 |
| |
| Net cash used in financing activities | | (175.7 | ) | | (22.9 | ) | | (149.6 | ) |
| | | | | | | | | | | |
| (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS | (753,690 | ) | | 68,836 |
| | 585,155 |
| |
| INCREASE IN CASH AND CASH EQUIVALENTS | | 76.6 |
| | 771.3 |
| | 145.0 |
|
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 1,092,844 |
| | 1,024,008 |
| | 438,853 |
| 1,255.5 |
| | 484.2 |
| | 339.2 |
|
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 339,154 |
| | $ | 1,092,844 |
| | $ | 1,024,008 |
| $ | 1,332.1 |
| | $ | 1,255.5 |
| | $ | 484.2 |
|
NOTE 1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION
On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales, (Rowan plc), became the successor issuer to Rowan Companies, Inc. (RCI) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of RCI on April 16, 2012. As a result of the redomestication, Rowan plc became the parent company of the Rowan group of companies, and our place of incorporation was effectively changed from Delaware to the United Kingdom. The redomestication was accounted for as an internal reorganization of entities under common control; accordingly, the carrying values of assets and liabilities of the merged entities were carried forward without adjustment. Unless the context otherwise requires, the terms “Rowan,” “Company,” “we,” “us” and “our” are used to refer to Rowan plc (or RCI for periods prior to the redomestication) and its consolidated subsidiaries.
We areis a global provider of offshore contract drilling services to the oil and gas contract drilling services utilizingindustry, with a fleet of 30 self-elevating mobile offshore “jack-up” drilling units and four ultra-deepwater drillships, including one which is currently under construction. Historically, our primary focus has been on high-specification and premium jack-up rigs which our customers use for exploratory and development drillingultra-deepwater drillships. Prior to ARO commencing operations on October 17, 2017 (see "ARO Joint Venture" below), we operated in two segments: Deepwater and associated drilling services. In 2009, we began executing a new strategic plan that included divesting non-core assetsJack-ups; however, as of December 31, 2017, the Company operated in three segments: Deepwater, Jack-ups and investing in ultra-deepwater assets, with a goal of balancing earnings from jack-ups and deepwater rigs over the long term. In 2011 and 2012 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction ofARO. The Deepwater segment includes four ultra-deepwater drillships. During 2014, we took deliveryThe Jack-ups segment is composed of 21 self-elevating jack-up rigs and the impact of the first three drillships:various arrangements with ARO (see discussion below and Note 3), in addition, two LeTourneau Super 116E jack-up rigs were purchased in January 2018, (see Note 19). The ARO segment is the 50/50 joint venture with Rowan Renaissance, which commenced drilling operations offshore West Africa in April 2014; the Rowan Resolute, which commenced operationsand Saudi Aramco that owns a fleet of five self-elevating jack-up rigs for operation in the United StatesArabian Gulf of Mexico (US GOM) in October 2014; and the Rowan Reliance, which commenced operations in the US GOM in February 2015. Our fourth drillship, the Rowan Relentless, is scheduled for delivery in late March 2015 and is expected to commence operations in the US GOM in the third quarter of 2015.
Saudi Aramco. The Company conducts offshorecontracts its drilling operationsrigs, related equipment and work crews primarily on a day-rate basis in various markets throughout the world, currently including the US GOM, the U.K. and Norwegian sectors of the North Sea, the Middle East West and North Africa, Southeast Asia and Trinidad.
The consolidated financial statements included herein are presented in USD and include the accounts of Rowan plc and its subsidiaries, all of whichdirect and indirect subsidiaries. Unless the context otherwise requires, the terms “Rowan,” and “Company” are wholly owned.used to refer to Rowan plc and its consolidated subsidiaries. Intercompany balances and transactions have been eliminated in consolidation.
The financial information presented in this report does not constitute the Company's statutory accounts within the meaning of the U.K. Companies Act 2006 for the years ended December 31, 20142017 or 2013.2016. The audit of the statutory accounts for the year ended December 31, 2014,2017, was not complete as of March 2, 2015.February 28, 2018. These accounts will be finalized by the directors on the basis of the financial information presented herein adjusted to meet the requirements of International Financial Reporting Standards as adopted by the European Union and the U.K. Companies Act 2006 and will be delivered to the Registrar of Companies in the U.K.
ARO Joint Venture
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture (the "Shareholders' Agreement") to own, manage and operate offshore drilling units in Saudi Arabia. The new entity, ARO, was formed in May 2017 with each of Rowan and Saudi Aramco contributing $25 million to be used for working capital needs. In addition, $5 million in transaction costs were incurred by Rowan and capitalized to the investment in ARO. ARO commenced operations on October 17, 2017 (see Note 3 to our consolidated financial statements for additional information). On October 17, 2017, Rowan and Saudi Aramco amended the asset transfer and contribution agreements (the "Amended Agreements"), previously entered into in connection with the Shareholders' Agreement, to, among other things, modify and clarify the mechanics associated with the formation of ARO to provide for: (1) equal cash contributions to ARO by each of Rowan and Saudi Aramco, (2) the receipt of cash from both Rowan and Saudi Aramco in exchange for shareholder notes, (3) the subsequent sale of: (a) three rigs and related assets to ARO by Rowan in exchange for cash and (b) one rig and related assets to ARO by Saudi Aramco in exchange for cash, and (4) the distribution by ARO of excess cash in the amount of approximately $88 million to each party, to be applied as a repayment to each party's shareholder note, maintaining each party’s 50% ownership interest in ARO following such asset sales. On October 17, 2017, these transactions were completed at which point the Company derecognized the related rig assets and began recording its interest in the ARO joint venture under the equity method of accounting. Pursuant to the terms of the Shareholders' Agreement and the Amended Agreements, Saudi Aramco also sold an additional rig to ARO in late December 2017 for cash. Rowan expects to sell two more rigs to ARO in late 2018 when those rigs complete their current contracts. Rowan expects the sale transactions to be similar to the October 2017 transactions. Rigs sold will receive contracts for an aggregate 15 years, renewed and re-priced every three years, provided that the rigs meet the technical and operational requirements of Saudi Aramco.
Rowan rigs in Saudi Arabia not selected for sale to the JV will be managed by ARO until the end of their current contracts with Saudi Aramco pursuant to a management services agreement that provides for a management fee equal to a percentage of revenue to cover overhead costs.
Each of Rowan and Saudi Aramco have agreed to take all steps necessary to ensure that ARO purchases at least 20 new build jack-up rigs ratably over 10 years once Saudi Aramco's joint venture to manufacture rigs commences operations. The first rig is expected to be delivered as early as 2021. The partners intend that the newbuild jack-up rigs will be financed out of available cash from operations and/or funds available from third party debt financing. The parties agreed that Saudi Aramco as a customer will provide drilling contracts to ARO in connection with the acquisition of the new rigs, which contracts could be used as security for third party debt financing if needed. If cash from operations or financing is not available to fund the cost of the newbuild jack-up rig, each partner is obligated to contribute funds, in the form of additional shareholder loans, to purchase such rigs, over time of up to a maximum amount of $1.25 billion per partner in the aggregate for all 20 newbuild jack-up rigs, which total investment amount
is subject to a reduction formula as rigs are delivered. Further, no shareholder will be required to fund the delivery of more than three rigs during any twelve (12) month period.
Customer Contract Termination Amendment
On September 15, 2016, the Company amended its contract with Cobalt, for the drillship Rowan Reliance, which was scheduled to conclude on February 1, 2018. The amendment provided cash settlement payments to the Company totaling $95.9 million, that the drillship remain at its day rate of approximately $582,000 and that the drilling contract may be terminated as early as March 31, 2017. The Company received cash payments totaling $76.3 million in 2016 and received a final cash payment of $19.6 million during the first quarter of 2017. In addition, the amendment provided that if Cobalt continued its operations with the Rowan Reliance after March 31, 2017, the day rate would be reduced to approximately $262,000 per day for the remaining operating days through February 1, 2018 (subject to further adjustment thereafter). Cobalt International Energy, Inc., the parent of Cobalt, also committed to use the Company as its exclusive provider of comparable drilling services for a period of five years. As the Company had the obligation and intent to have the drillship or a substitute available through the pre-amended contract scheduled end date, in certain circumstances (including a 90 day notice of intent to use the rig prior to the original contract scheduled end date of February 1, 2018), the $95.9 million settlement was recorded as a deferred revenue liability at December 31, 2016. Amortization of deferred revenue began on April 1, 2017 and was fully amortized as of December 31, 2017 as Cobalt did not provide notice to the Company by November 2, 2017 (90 day notice of intent to use the rig).
Customer Contract Termination and Settlement
On May 23, 2016, the Company reached an agreement with FMOG and its parent company, FCX in connection with the drilling contract for the drillship Rowan Relentless ("FCX Agreement"), which was scheduled to terminate in June 2017. The FCX Agreement provided that the drilling contract be terminated immediately, and that FCX pay the Company $215 million to settle outstanding receivables and early termination of the contract, which was received in 2016. In addition, the Company received the right to receive up to two additional contingent payments from FCX, payable on September 30, 2017, of $10 million (the "First FCX Contingent Payment Provision") and $20 million (the "Second FCX Contingent Payment Provision" and, together with the First FCX Contingent Payment Provision, the "FCX Contingent Payments Provisions") depending on the average price of WTI crude oil over a 12-month period beginning June 30, 2016. The FCX Contingent Payments Provisions would have been due if the average price over the period was greater than $50 per barrel with respect to the First FCX Contingent Payment Provision and $65 per barrel with respect to the Second FCX Contingent Payment Provision ("Price Targets"). During the quarter ended June 30, 2016, the Company recognized $173.2 million in revenue for the Rowan Relentless, including $130.9 million for the cancelled contract value, $6.2 million for the fair value of the derivative associated with the FCX Contingent Payments Provisions, $5.6 million for previously deferred revenue related to the contract, and $30.5 million for operations through May 22, 2016. For additional information related to the FCX Contingent Payments Provisions see Note 6. NOTE 2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenuesrevenue and expenses during the reporting period. Actual results could differ from those estimates.
Revenue and Expense Recognition
OurThe Company's drilling contracts generally provide for payment on a daily rate basis, and revenues arerevenue is recognized as the work progresses with the passage of time. WeThe Company occasionally receivereceives lump-sum payments at the outset of a drilling assignment for equipment moves or modifications. Lump-sum fees received for equipment moves (and related costs) and fees received for equipment modifications or upgrades are initially deferred and amortized on a straight-line basis over the primary term of the drilling contract. The costs of contractual equipment modifications or upgrades and the costs of the initial move of newly acquiredconstructed rigs are capitalized and depreciated in accordance with the Company’s fixed asset capitalization policy. The costs of moving equipment while not under contract are expensed as incurred. RevenuesThe following table sets forth deferred revenue (revenue received but unearned are included in currentunearned) and long-term liabilities and totaled $60.2 million and $81.8 milliondeferred contracts costs on the Consolidated Balance Sheets at December 31 2014 and 2013, respectively. Deferred contract costs are included in prepaid expenses and other assets and totaled $5.4 million and $19.8 million at December 31, 2014 and 2013, respectively.(in millions):
|
| | | | | | | | | |
| | Balance Sheet Classification | | 2017 | | 2016 |
Deferred revenue (1) | | | | | |
| Current | Deferred revenue (2) | | $ | 1.1 |
| | $ | 103.9 |
|
| Noncurrent | Other liabilities | | 0.5 |
| | 10.5 |
|
| | | | $ | 1.6 |
| | $ | 114.4 |
|
| | | | | | |
| Deferred contract costs | | | | | |
| Current | Prepaid expenses and other current assets | | $ | 2.8 |
| | $ | 2.0 |
|
| Noncurrent | Other assets | | — |
| | 0.2 |
|
| | | | $ | 2.8 |
| | $ | 2.2 |
|
| | | | | | |
(1) 2016 Deferred revenue included $95.9 million ($86.5 million and $9.4 million, current and noncurrent, respectively) related to the Cobalt contract amendment (see Note 1). |
| (2) A current liability. |
The Company recognizes revenue for certain reimbursable costs. Each reimbursable item and amount is stipulated in the Company’s contract with the customer, and such items and amounts frequently vary between contracts. We recognizeThe Company recognizes reimbursable costs on the gross
basis, as both revenuesrevenue and expenses, because we arethe Company is the primary obligor in the arrangement, havehas discretion in supplier selection, areis involved in determining product or service specifications and assumeassumes full credit risk related to the reimbursable costs.
Cash Equivalents
Cash equivalents consist of highly liquid temporary cash investments with maturities no greater than three months at the time of purchase.
Accounts Receivable and Allowance for Doubtful Accounts
The Company's accounts receivable is stated at historical carrying value net of write-offs and allowance for doubtful accounts. The Company assesses the collectability of receivables and records adjustments to an allowance for doubtful accounts, which is recorded as an offset to accounts receivable, to cover the risk of credit losses. TheAny allowance is based on historical and other factors that predict collectability, including write-offs, recoveries and the evaluation and monitoring of credit quality. No allowance for doubtful accounts was required at December 31, 20142017 or 2013.
2016.
The following table sets forth the components of Receivables - tradeTrade and otherOther at December 31 (in thousands)millions):
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Trade | $ | 524,712 |
| | $ | 323,679 |
| $ | 195.8 |
| | $ | 286.2 |
|
| Income tax | 6,315 |
| | 6,759 |
| 8.0 |
| | 7.7 |
|
| Other | 14,177 |
| | 14,108 |
| 9.0 |
| | 7.4 |
|
| Total receivables - trade and other | $ | 545,204 |
| | $ | 344,546 |
| $ | 212.8 |
| | $ | 301.3 |
|
Property and Depreciation
We provideThe Company provides depreciation for financial reporting purposes under the straight-line method over the asset’s estimated useful life from the date the asset is placed into service until it is sold or becomes fully depreciated. In connection with the completion of the asset impairment test in 2014, we reduced salvage values for our jack-up rigs from 20 percent to 10 percent of historical cost effective December 31, 2014. Estimated useful lives and salvage values are presented below:
| | | | Life (in years) | | Salvage Value | Life (in years) | | Salvage Value |
| Jack-up drilling rigs: | | | | | | |
| Hulls | 35 | | 10 | % | 25 to 35 | | 10 | % |
| Legs | 30 | | 10 | % | 25 to 30 | | 10 | % |
| Quarters | 25 | | 10 | % | 25 | | 10 | % |
| Drilling equipment | 5 to 25 | | 0% to 10% |
| 2 to 25 | | 0% to 10% |
|
| | | | | |
| Drillships: | | | | |
| Hull | 35 | | 10 | % | |
| Hulls | | 35 | | 10 | % |
| Drilling equipment | 5 to 25 | | 0% to 10% |
| 2 to 25 | | 0% to 10% |
|
| | | | | |
| Drill pipe and tubular equipment | 4 | | 10 | % | 4 | | 10 | % |
| Other property and equipment | 3 to 30 | | various |
| 3 to 30 | | various |
|
Expenditures for new property or enhancements to existing property are capitalized and depreciated over the asset’s estimated useful life. As assets are sold or retired, property cost and related accumulated depreciation are removed from the accounts, and any resulting gain or loss is included in results of operations. The Company capitalizescapitalized a portion of interest cost incurred during the drillship construction period. Weperiod, which ended in 2015 with the completion of the drillship construction program. The Company capitalized interest in the amount of $57.616.2 million in 2014, $48.7 million2015. The Company did not capitalize interest in 20132017 and $33.4 million in 2012.2016.
Expenditures for maintenance and repairs are charged to operationsexpense as incurred and totaled $161113 million in 2014,2017, $152118 million in 20132016 and $132129 million in 2012.2015.
Impairment of Long-lived Assets
We reviewThe Company reviews the carrying values of long-lived assets for impairment whenever events or changes in circumstances indicate their carrying amounts may not be recoverable. For assets held and used, we determinethe Company determines recoverability by evaluating the undiscounted estimated future net cash flows based on projected day rates, operating costs, capital requirements and utilization of the asset under review. When the impairment of an asset is indicated, we measurethe Company measures the amount of impairment as the amount by which the asset’s carrying amount exceeds its estimated fair value. We measureThe Company measures fair value by estimating discounted future net cash flows under various operating scenarios (an income approach) and by assigning probabilities to each scenario in order to determine an expected value. The lowest level of inputs we usethe Company uses to value assets held and used in the business are categorized as “significant unobservable inputs,” which are Level 3 inputs in the fair value hierarchy. For assets held for sale, we measurethe Company measures fair value based on equipment broker quotes, less anticipated selling costs, which are considered Level 3 inputs in the fair value hierarchy.
Due to a number of factors including the rapid and dramatic fall in worldwide oil prices in the last half of 2014 and decline in the Company's stock price; the expected delivery of a large number of newbuild jack-up drilling units over the next few years; and the finalization of the Company's 2015 operating budget, among others, weThe Company conducted an impairment test of ourits assets during the fourth quarter of 2017; however, the test resulted in no impairment as the estimated undiscounted cash flows from the assets exceeded the assets' carrying values.
In 2016, the Company conducted an impairment test of its assets and determined that the carrying values for five of our twelve oldestits jack-up drilling units aggregating $840.8$43.6 million were not recoverable from their undiscounted cash flows and exceeded the rigs' estimated fair values. Asas a result, wethe Company recognized a noncashnon-cash impairment charge of $565.7$34.3 million in 2016. In 2015, the fourth quarterCompany conducted an impairment test of 2014. Weits assets and determined that the carrying values for ten of its jack-up drilling units aggregating $457.8 million were not recoverable, and as a result, recognized a non-cash impairment charge of $329.8 million in 2015. The Company measured fair valuevalues using the income approach described above. Our estimate ofThe fair value estimates required usthe Company to use significant unobservable inputs, which are internally developed assumptions not observable in the market, including assumptions related to future demand for drilling services, supplyestimated availability of available rigs and future day rates, among others.
Also The impairments recognized in 2014, we recognized an $8.3 million impairment charge for2016 and 2015 on the carrying value of a Company aircraft, which was used to support operations. We sold the aircraft laterjack-up rigs are included in 2014 and recognized an immaterial loss on sale. The asset had a carrying value of $12.7 million prior to the write-down. The amount of the impairment was based on actual sales prices for similar equipment obtained from a third-party dealer of such equipment. Quoted prices in active markets for similar equipment are considered a Level 2 inputjack-up operations in the fair value hierarchy.
In 2013 we recognized a $4.5 million impairment charge for a dock and storage facility, which had a carrying value of $23.5 million prior to the write-down.
segment information in Note 13In 2012 we recognized a $5.2 million impairment charge for the Rowan Juneau, which had a carrying value of $18.7 million prior to the write-down.
. Impairment charges are included in material chargesMaterial Charges and other operating expensesOther Operating Items on the Consolidated Statements of Income.
Operations.
Share-based Compensation
We recognizeThe Company generally recognizes compensation cost for employee share-based awards on a straight-line basis over a 36-month service period. For employees who are retirement-eligible at the requisite servicegrant date or who will become retirement-eligible within six months of the grant date, compensation cost is generally recognized over a minimum period of the award. Compensationsix months. Generally, compensation cost of awards granted beginning March 2013 that have retirement-eligibility provisions is recognized over the lessor offor employees who become retirement eligible after six months orfollowing the grant date but before the maximum service
period which is typically 36 months is amortized over the period from the grant date to the date the employee meets the retirement eligibility and certain other requirements.
Fair value of restricted sharesRSAs and restricted share unitsRSUs awarded to employees is based on the average of the high and low market price of the stockshares on the date of grant. CompensationPrior to January 1, 2017, compensation cost iswas recognized for awards that arewere expected to vest and iswere adjusted in subsequent periods if actual forfeitures differdiffered from estimates. Pursuant to the adoption of ASU No. 2016-09 as of January 1, 2017, the Company no longer estimates forfeitures, but rather adjusts its compensation costs in the period that actual forfeitures occur.
Restricted share units grantedNon-employee directors may annually elect to non-employee directors ("Director RSUs")receive either Directors RSUs or Directors ND RSUs. Both Directors RSUs and Directors ND RSUs vest one yearat the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date. Directors ND RSUs are settled on the vesting date, but maywhile Director RSUs are not be settled until the director terminates service from the board.Board. Both Directors ND RSUs and Directors RSUs are settled in cash, shares or a combination thereof at the discretion of the Company Compensation Committee. Compensation cost isfor both Director RSUs and Director ND RSUs are recognized over the one-year service period. Directorperiod which is up to one year. Directors RSUs may be settled in cash and/or shares of stock and Directors ND RSUs are accounted for under the liability method of accounting. Fairaccounting, the fair value is based on the market price of the underlying stockshares on the grant date, and compensation expense is adjusted for changes in fair value at each report date through the settlement date.
Performance-based awards consist of Performance Units,P-Units, in which the payment is contingent on the Company's total shareholder returnTSR relative to anthe selected industry peer group. Fair value of Performance UnitsP-Units is determined using a Monte-Carlo simulation model. Performance Units areThe Company Compensation Committee has previously determined that any amount earned with respect to P-Units granted in 2015 would be settled in cash; however, P-Units granted in 2016 or after may be settled in cash, andshares or a combination thereof at the Company Compensation Committee's discretion. All P-Units are accounted for under the liability method of accounting. Compensation cost is generally recognized on a straight-line basis over the service period and is adjusted for changes in fair value at each report date through the vest date.
the performance period. For P-Units granted in 2017, the Company recognizes compensation cost on the accelerated method for those retirement eligible or who will become retirement eligible during the vesting period as the 2017 awards provide for pro-rata vesting rather than full vesting if a retirement eligible employee retires prior to the end of the 36 month service period.
Fair value of share appreciation rights ("SARs")options is determined using the Black-Scholes option pricing model. The Company uses the simplified method for determining the expected life of options, because it does not have sufficient historical exercise data to provide a reasonable basis on which to estimate expected term, as permitted under US GAAP. The Company intends to share-settle options that are exercised and has therefore accounted for them as equity awards.
Fair value of SARs is determined using the Black-Scholes option pricing model. The Company uses the simplified method for determining the expected life of SARs, because it does not have sufficient historical exercise data to provide a reasonable basis on which to estimate expected term, as permitted under US GAAP. The Company has not granted any SARs since 2013. The Company intends to share-settle SARs that are exercised and has therefore accounted for them as equity awards.
Foreign Currency Transactions
The U.S. dollarA substantial majority of the Company's revenue is received in USD, which is the Company's functional currency. However, in certain countries in which the Company operates, local laws or contracts may require some payments to be received in the local currency. The Company is exposed to foreign currency for allexchange risk to the extent the amount of our operations. Non-U.S. dollar transaction gains and losses are recognizedits monetary assets denominated in “other income” on the Consolidated Statements of Income.foreign currency differs from its obligations in that foreign currency. In order to reducemitigate the impacteffect of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and tryrisk, the Company attempts to limit localforeign currency holdings to the extent they are needed to pay liabilities denominated in local currencies. In certain countries in which we operate, local laws or contracts may require us to receive payment in the local currency. InPrior to 2016, the Company entered into spot purchases or short-term derivative transactions, such instances, we may be exposedas forward exchange contracts, with one-month durations. The Company did not enter into such transactions for the purpose of speculation, trading or investing in the market and believed that its use of forward exchange contracts did not expose it to devaluationmaterial credit risk or other material market risk. Although the Company's risk policy allows it to enter into such forward exchange contracts, the Company does not currently anticipate entering into such transactions in the future and other riskhad no such contracts outstanding as of exchange loss. InDecember 31, 2017.
At December 31, 2017 and 2016, the event we terminate operations in such countries we may not be able to utilize or convert such funds to another currency for future use. In 2014 we terminated operations in Egypt, where weCompany held approximately $16.3 million in Egyptian pounds basedin the amount of $2.8 million and $5.1 million, respectively, of which $2.2 million and $4.2 million are classified as Other Assets on exchange rates in effect atthe Consolidated Balance Sheets. At December 31, 2014. Such amount was reclassified to noncurrent assets as of that date. We can provide no assurance we will be able to utilize or repatriate such funds2017, the Company held Angolan Kwanza in the future.amount of $4.3 million, which is classified as Other Assets on the Consolidated Balance Sheets. See the "Assets and Liabilities Measured at Fair Value on a Recurring Basis" section ofNote 7 for further information.
Non-USD transaction gains and losses are recognized in “other - net” on the Consolidated Statements of Income. The Company recognized a net currency exchange gainlosses of $0.05$0.4 million, $9.7 million and $3.9 million in 2014, a net2017, 2016 and 2015, respectively. In 2016, the exchange loss was primarily due to the devaluation of $2.3 million in 2013 and a net exchange gain of $0.5 million in 2012.the Egyptian pound.
Income Taxes
Rowan recognizes deferred income tax assets and liabilities for the estimated future tax consequences of differences between the financial statement and tax bases of assets and liabilities. Valuation allowances are provided against deferred tax assets that are not likely to be realized. Interest and penalties related to income taxes are included in income tax expense.
The Company doeshas not provideprovided deferred income taxes on certain undistributed earnings of its non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiariesNo subsidiary of RCI outside the U.S. Should the non-U.S. subsidiaries ofhas a plan to distribute earnings to RCI makein a distribution from thesemanner that would cause those earnings we mayto be subject to U.S., U.K. or other local country taxation.
Principles of Consolidation
The consolidated financial statements include the Company's accounts and those of its wholly-owned subsidiaries. Intercompany balances and transactions have been eliminated in consolidation. Investments in operating entities where the Company has the ability to exercise significant influence, but where it does not control operating and financial policies are accounted for using the equity method. Significant influence generally exists if the Company has an ownership interest representing between 20% and 50% of the voting stock of the investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional U.S. income taxes. Generally,investments and the Company's proportionate share of earnings or losses and distributions. Equity in earnings of non-U.K. subsidiariesARO, in which RCI does not have a direct or indirect ownership interest can be distributedthe consolidated statements of operations, reflects the Company's proportionate share of ARO's net income, including any associated affiliate taxes. See the Note 3 for additional details related to the Company without the imposition of either U.K. or local country tax. See Note 11 for further information regarding the Company’s income taxes.Company's equity method investment.
Income Per Common Share
Basic income (loss) per share is computed by dividing net income (loss) available to common shareholders by the weighted-average number of common shares outstanding during the period. Diluted income per share includes the additional weighted effect of all potentially dilutive securities outstanding during the period, which includes nonvested restricted stock, and units and dilutiveRSUs, P-Units, share options and appreciation rightsSARs granted under share-based compensation plans. Dilutive securities areThe effect of share equivalents is not included in the computation of loss per share when the Company reportsfor periods in which a net loss from continuing operations as the impactoccurs because to do so would be antidilutive.anti-dilutive.
A reconciliation of net income for basic and diluted income per share is set forth below (in millions):
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Net income | $ | 72.7 |
| | $ | 320.6 |
| | $ | 93.3 |
|
| Income allocated to non-vested share awards | 0.1 |
| | 1.5 |
| | — |
|
| Net income - adjusted for income allocated to non-vested share awards | $ | 72.8 |
| | $ | 322.1 |
| | $ | 93.3 |
|
A reconciliation of shares for basic and diluted income per share is set forth below. There were no income adjustments to the numerators of the basic or diluted computations for the periods presentedbelow (in thousands)millions):
|
| | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Average common shares outstanding | 124,067 |
| | 123,517 |
| | 122,998 |
|
| Add dilutive securities: | |
| | |
| | |
|
| Nonvested restricted shares and restricted share units | — |
| | 542 |
| | 457 |
|
| Share options and appreciation rights | — |
| | 409 |
| | 417 |
|
| Average shares for diluted computations | 124,067 |
| | 124,468 |
| | 123,872 |
|
|
| | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Average common shares outstanding | 126.1 |
| | 125.3 |
| | 124.5 |
|
| Effect of dilutive securities - share based compensation | 1.6 |
| | 1.0 |
| | 0.7 |
|
| Average shares for diluted computations | 127.7 |
| | 126.3 |
| | 125.2 |
|
Share options, SARs, nonvested restricted stock, P-Units and appreciation rightsRSUs granted under share-based compensation plans are antidilutiveanti-dilutive and excluded from diluted earnings per share when their exercise or strike pricethe hypothetical number of shares that could be repurchased under the treasury stock method exceeds the average market price during the period,number of shares that can be exercised, or when the Company reports a net loss from continuing operations. The following table sets forth antidilutiveAnti-dilutive shares, excluded from diluted earnings per share. Such securitieswhich could potentially dilute earnings per share in the future, are set forth below (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Share options and appreciation rights | 2,234 |
| | 1,065 |
| | 658 |
| $ | 1.5 |
| | $ | 1.6 |
| | $ | 1.2 |
|
| Nonvested restricted shares and restricted share units | 619 |
| | — |
| | — |
| 2.1 |
| | 0.9 |
| | 1.1 |
|
| Total potentially dilutive shares | 2,853 |
| | 1,065 |
| | 658 |
| $ | 3.6 |
| | $ | 2.5 |
| | $ | 2.3 |
|
Recent Accounting Pronouncements - Adopted
Stock Compensation –In March 2016, the FASB issued ASU No. 2016-09, Improvements to Employee Share-based Payment Accounting ASC 718), which simplifies several aspects of accounting for employee share-based payment awards, including the accounting for income taxes, withholding taxes and forfeitures, as well as classification on the statement of cash flows. The Company adopted this ASU as of January 1, 2017 and elected to account for forfeitures when they occur, on a modified retrospective basis. As required by this ASU, the Consolidated Statement of Cash Flows was retroactively adjusted for the years ended December 31, 2016 and 2015, to reclass $5.0 million and $1.2 million, respectively, from operating activities to financing activities related to shares repurchased for tax withholdings on vesting of RSUs. The Company prospectively adopted the provision of this ASU related to the classification of excess tax benefits on the statement of cash flows as an operating cash flow. The adoption did not have a material impact on the Company's consolidated financial statements.
Income Taxes– In October 2016, the FASB issued ASU No. 2016-16, Income Taxes (ASC 740): Intra-Entity Transfers of Assets Other than Inventory, which eliminates the exception that prohibits the recognition of current and deferred income tax effects for intra-entity transfers of assets other than inventory until the asset has been sold to an outside party. As permitted under this ASU, the Company elected early adoption of this ASU as of January 1, 2017 and recorded a $206.6 million increase to retained earnings for the remaining unamortized deferred tax liability resulting from intra-entity transactions. The impact of the adoption of this ASU was a reduction in tax benefits of $39.2 million, or a reduction per share of $0.31 for the year ended December 31, 2017.
Business Combinations –In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (ASC 805): Clarifying the Definition of a Business, which clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. As permitted under this ASU, the Company early adopted this guidance as of October 17, 2017 in conjunction with the finalization of the ARO joint venture discussed in Note 1 and Note 3. The adoption did not have a material impact on the Company's consolidated financial statements. Stock Compensation (Scope of Modification) –In May 2017, the FASB issued ASU No. 2017-09, Compensation - Stock Compensation (ASC 718): Scope of Modification Accounting, which provides guidance about which changes to the terms or conditions of a share-based payment award require an entity to apply modification accounting in Topic 718. This ASU was issued to provide clarity and reduce both (1) diversity in practice and (2) cost and complexity when applying the guidance in Topic 718 to a change to the terms or conditions of a share-based payment award. An entity will not have to account for the effects of a modification if all of the following are met: (1) The fair value of the modified award is the same as that of the original award immediately before the modification; (2) the vesting conditions of the modified award are the same as that of the original award immediately before the modification; and (3) the classification of the modified award as either an equity instrument or liability instrument is the same as that of the original award immediately before the modification. The Company adopted this guidance in the fourth quarter of 2017 and it did not have a material impact on its consolidated financial statements.
Recent Accounting Pronouncements
- to be Adopted
In April 2014, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2014-08,Revenue Recognition Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity– ("ASU 2014-08"), which limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have (or will have) a major effect on an entity's operations and financial results. Under current guidelines prior to the effective date of ASU 2014-08, many disposals that were routine in nature and not a change in an entity's strategy were reported in discontinued operations. The provisions of the new standard will apply to disposals (or classifications as held for sale) of components of an entity occurring in annual and interim periods beginning in 2015. We do not expect adoption of the standard will have a material effect on our financial statements or the notes thereto.
In May 2014, the Financial Accounting Standards BoardFASB issued Accounting Standards UpdateASU No. 2014-09, Revenue from Contracts with Customers(ASC 606), which sets forth a global standard for revenue recognition and replaces most existing industry-specific guidance. WeThe Company will be required to adopt the new standard in annual and interim reports for periods beginning January 1, 2017. We2018. ASC 606 requires an entity to recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The Company will adopt ASC 606, effective January 1, 2018 utilizing the modified retrospective approach. In adopting ASC 606, the Company expects its revenue recognition to differ from its current revenue recognition pattern only as it relates to demobilization revenue. Such revenue, which is recognized upon completion of a contract under current GAAP, will be estimated at contract inception and recognized over the term of the contract under the new guidance for customer contracts that have demobilization provisions. While the Company continues to finalize the impact of adoption, the Company does not expect that the cumulative effect adjustment to opening retained earnings required by the modified retrospective adoption approach to be significant, as it will primarily consist of the impact of the timing difference related to recognition of demobilization revenue for affected contracts.
Lease Accounting – In February 2016, the FASB issued ASU No. 2016-02, Leases(ASC 842): Amendments to the FASB ASC, which requires an entity to recognize lease assets and lease liabilities on the balance sheet and to disclose key qualitative and quantitative information about the entity's leasing arrangements. Based on current guidance, lessees and lessors will be required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach, including a number of optional practical expedients that entities may elect to apply. However, in January 2018, the FASB issued an exposure draft which allows for an option to apply the guidance prospectively, instead of retrospectively, and allows for other classification provisions, as described below. ASC 842 is effective for annual and interim periods beginning after December 15, 2018, with early adoption permitted. Under the updated accounting standards, the Company has preliminarily determined that its drilling contracts contain a lease component, and the adoption, therefore, will require that the Company separately recognize revenue associated with the lease and services components. As noted above, in January 2018, the FASB issued an exposure draft which
discussed a practical expedient which would allow companies to combine lease and non-lease components where the revenue recognition pattern is the same and where the combination of the service and lease component would be considered an operating lease. With respect to the applicability to the drilling industry of the practical expedients, the Company has and will continue to consult with its peers in the International Association of Drilling Contractors Accounting Sub-committee ("IADC Accounting Sub-committee") to evaluate any accounting standard updates issued as a result of the exposure draft for the applicability of this practical expedient to its drilling contracts. Although the Company had previously disclosed its intent to adopt ASC 842 and ASC 606 concurrently, due to the implications of this exposure draft, the Company elected to not adopt ASC 842 early on January 1, 2018, and as a result, is no longer adopting ASC 842 and ASC 606 concurrently.
The adoption of ASC 842 will have an impact on how the Company's consolidated balance sheets, statements of operations, cash flows and disclosures contained in our notes to consolidated financial statements will be presented, however because we are currently evaluating the potentialimpact of the new exposure draft, we are unable to quantify the overall impact at this time. As a lessee, we have estimated future minimum lease commitments of approximately $40 million with an estimated present value of approximately $30 million based on our currently identified lease portfolio. We continue to refine our estimate, which is subject to change at the adoption date of ASC 842.
Financial Instruments –In June 2016, the FASB issued ASU No. 2016-13, Financial Instruments - Credit Losses (ASC 326): Measurement of Credit Losses on Financial Instruments, which amends the FASB's guidance on the impairment of financial instruments. The ASU adds to US GAAP an impairment model that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of expected credit losses. The Company will be required to adopt the amended guidance in annual and interim reports beginning January 1, 2020, with early adoption permitted for fiscal years beginning after December 15, 2018. The Company is in the process of evaluating the impact this amendment will have on its consolidated financial statements.
Statement of Cash Flows –In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (ASC 230): Classification of Certain Cash Receipts and Cash Payments, which provides guidance on eight cash flow classification issues with the objective of reducing differences in practice. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2018, with early adoption permitted. Adoption is required to be on a retrospective basis, unless impracticable for any of the amendments, in which case a prospective application is permitted. The Company is in the process of finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but currently believes such impact will be immaterial.
Statement of Cash Flows Restricted Cash –In November 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (ASC 230): Restricted Cash, which requires restricted cash to be presented with cash and cash equivalents in the statement of cash flows. The changes in restricted cash and restricted cash equivalents during the period should be included in the beginning and ending cash and cash equivalents balance reconciliation on the statement of cash flows. When cash, cash equivalents, restricted cash or restricted cash equivalents are presented in more than one line item within the statement of financial position, an entity shall calculate a total cash amount in a narrative or tabular format that agrees with the amount shown on the statement of cash flows. Details on the nature and amounts of restricted cash should also be disclosed. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2018, with early adoption permitted. Adoption is required to be applied using a retrospective approach to each period presented. The Company is in the process of evaluating the impact these amendments may have on its consolidated financial statements.
Other Income –In February 2017, the FASB issued ASU No. 2017-05, Other Income (ASC 610): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets” (“ASU 2017-05”). ASU 2017-05 clarifies the scope of the original guidance within Subtopic 610-20 that was issued in connection with ASU 2014-09, which provides guidance for recognizing gains and losses from the transfer of nonfinancial assets in contracts with non-customers. ASU 2017-05 also added guidance for partial sales of nonfinancial assets. The Company will be required to adopt the amendments in this ASU beginning January 1, 2018, concurrently with ASC 606. The Company is in the process of evaluating the impact this amendment may have on its consolidated financial statements.
Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost –In March 2017, the FASB issued ASU No. 2017-07, Compensation - Retirement Benefits (ASC 715): Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires entities to present the service cost component of the net periodic benefit cost in the same income statement line item as other employee compensation costs. The other components of net benefit cost, including interest cost, expected return on plan assets, amortization of prior service cost/credit and actuarial gain/loss, and settlement and curtailment effects, are to be presented outside of any subtotal of operating income. Entities will have to disclose the line(s) used to present the other components of net periodic benefit cost, if the components are not presented separately in the income statement. The ASU also allows only the service cost component to be eligible for capitalization. This ASU is effective for fiscal years and interim periods beginning after December 15, 2017, and early adoption is permitted. The Company is in the process of
finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but currently believes such impact will be immaterial.
Comprehensive Income – In February 2018, the FASB issued ASU No. 2018-02, Income Statement - Reporting Comprehensive Income (ASC 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allow a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the Tax Cuts and Jobs Act of 2017. The Company will be required to adopt the amendments in this ASU in annual and interim periods beginning January 1, 2019, with early adoption permitted. Adoption is required to be applied either in the period of adoption or retrospectively to each period (or periods) in which the effect of the new guidance.change in the U.S. federal corporate income tax rate in the Tax Cuts and Jobs Act is recognized. The Company is in the process of finalizing its evaluation of the impact these amendments will have on its consolidated financial statements but estimates a reclassification of $40-$50 million from Accumulated other comprehensive income to increase Retained earnings.
NOTE 3 – DISCONTINUED OPERATIONSEquity Method Investments and Variable Interest Entities
On November 21, 2016, Rowan and Saudi Aramco, through their subsidiaries, entered into a Shareholders’ Agreement to create a 50/50 joint venture, known as ARO (see Note 1). ARO commenced operations on October 17, 2017 and owns, manages and operates offshore drilling units in Saudi Arabia. The Company accounts for its interest in ARO using the equity method of accounting and only recognizes its portion of equity earnings in the Company's consolidated financial statements. ARO is a variable interest entity; however, the Company is not the primary beneficiary and therefore does not consolidate ARO. The Company's judgment regarding the level of influence over ARO included considering key factors such as: each company's ownership interest, representation on the board of managers of ARO, ability to direct activities that most significantly impact ARO's economic performance, as well as the ability to influence policy-making decisions. Summarized financial information
Summarized financial information for ARO, as derived from ARO's financial statements, is as follows (in millions):
|
| | | |
| | October 17, 2017 to |
| | December 31, 2017 |
| Revenue | $ | 48.6 |
|
| Direct operating costs (excluding items below) | 22.2 |
|
| Depreciation and amortization | 12.9 |
|
| Selling, general and administrative | 6.1 |
|
| Gain on disposals of property and equipment | (0.1 | ) |
| Income from Operations | 7.5 |
|
| Interest expense | (4.2 | ) |
| Provision for income taxes | 1.6 |
|
| Net Income | $ | 1.7 |
|
| | |
| Rowan's Equity in earnings from ARO | $ | 0.9 |
|
Related party transactions
In connection with the establishment of ARO the Company signed an Asset Transfer and Contribution Agreement. As part of this agreement the Company contributed cash to ARO of $357.7 million in exchange for a 10-year shareholder note receivable from ARO, initially totaling $357.7 million, at a stated interest rate of LIBOR plus two percent. As of December 31, 2017, the outstanding amount for this shareholder note receivable was $271.3 million, consisting of $270.2 million and $1.1 million, respectively, included in Long-term note receivable from unconsolidated subsidiary and Receivables - trade and other on the Company's Consolidated Balance Sheets. Interest related to this note is being recognized as a part of Interest Income in the Company's Consolidated Statement of Operations and totaled approximately $2.1 million for the period from October 17, 2017 to December 31, 2017.
In 2011,conjunction with the establishment of ARO, the Company completedsigned a series of agreements including: a Transition Services Agreement and a Secondment Agreement. Pursuant to these agreements the saleCompany, or its seconded employees, will provide various services to ARO (see Note 13), and in return, the Company is to be provided remuneration for those services. From time to time Rowan may sell equipment or supplies to ARO. Additionally, Rowan incurred certain preparation costs prior to ARO commencing operations which will be reimbursed to Rowan by ARO. Revenue and other amounts recognized related to these agreements and transactions is as follows (in millions): |
| | | |
| | October 17, 2017 to |
| | December 31, 2017 |
| Secondment Revenue - Jack-ups | $ | 9.2 |
|
| Transition Services Revenue - Unallocated | 7.4 |
|
| Sales of supplies | 0.5 |
|
| Total Revenue received from ARO | $ | 17.1 |
|
| | |
Reimbursement of preparation costs (a) | $ | 1.6 |
|
Equipment sales to ARO (b) | 1.0 |
|
| Total reimbursements from ARO | $ | 2.6 |
|
| | |
| (a) The reimbursement resulted in a reduction in expense of $1.3 million and a $0.3 million decrease to Prepaid expenses and other current assets. The entire $1.6 million is included in Receivable - trade and other for the amount to be reimbursed. |
| (b) There was no gain or loss recognized and $1.0 million is included in Receivable - trade and other for the $1.0 million purchase price. |
Total Accounts receivable from ARO related to these transactions totaled approximately $17.3 million as of its manufacturing and land drilling businesses. In 2012 we recognized aDecember 31, 2017.
As discussed in Note 1$3.9 million impairment charge relating to a land rig that was retained in connection, with the saleestablishment of ARO, the manufacturing business.Company also signed a Rig Management Agreement whereby ARO will provide certain rig management services for Rowan's rigs while they are contracted with Saudi Aramco. The Company will compensate ARO for the services in which they provide to Rowan. For the period from October 17, 2017 to December 31, 2017, the Company recognized $7.8 million in Direct operating cost in the Consolidated Statements of Operations related to these rig had a carrying valuemanagement services. Additionally, ARO may sell equipment or supplies to Rowan or purchase such for Rowan, in which case ARO is provided reimbursement. For the period from October 17, 2017 to December 31, 2017, the Company recognized $0.6 million in Direct operating cost in the Consolidated Statements of $26.9 million priorOperations related to these transactions as well as $2.4 million in accrued capital expenditures. Accounts payable to ARO related to these transactions totaled approximately $10.8 million as of December 31, 2017.
The following summarizes the write-down. In 2014 we sold the rig, which had a net carrying value at the time of sale of $4.1 million, consisting of a $24.2 million asset and a $20.1 million liability previously included intotal assets and liabilities of discontinued operations. The Company received $6.0 millionas reflected in cash resultingthe Company's consolidated balance sheets as well as the Company's maximum exposure to loss related to ARO (in millions). Generally, the Company's maximum exposure to loss is limited to its 1) equity investment in a $4.0 million gain, net of tax effects. The impairment chargethe joint venture, 2) outstanding note receivable and gain on sale were classified as discontinued operations in 2012 and 2014, respectively.
Discontinued operations for 2012 also included write-offs of receivables assumed, a working capital adjustment3) any amounts payable to the sale price ofCompany for services it provides to the land drilling business, and a prior year return-to-provision tax adjustment, among other items. The following table sets forthjoint venture, reduced by payables for services which the components of “Discontinued operations, net of tax” (in thousands):
Company owes to ARO.
|
| | | | | | | | | | | |
| | |
| | 2014 | | |
|
| | Manufacturing | | Drilling | | Total |
| | | | | | |
| Pretax income (loss) | $ | 1,882 |
| | $ | — |
| | $ | 1,882 |
|
| Provision (benefit) for taxes on income | (2,141 | ) | | — |
| | (2,141 | ) |
| Discontinued operations, net of tax | $ | 4,023 |
| | $ | — |
| | $ | 4,023 |
|
| | | | | | |
| | |
| | 2012 | | |
|
| | Manufacturing | | Drilling | | Total |
| | | | | | |
| Pretax income (loss) | $ | (7,599 | ) | | $ | (3,603 | ) | | $ | (11,202 | ) |
| Provision (benefit) for taxes on income | 15,751 |
| | (4,256 | ) | | 11,495 |
|
| Discontinued operations, net of tax | $ | (23,350 | ) | | $ | 653 |
| | $ | (22,697 | ) |
|
| | | |
| | December 31, 2017 |
| Total assets | $ | 319.5 |
|
| Total liabilities | 10.8 |
|
| Maximum exposure to loss | $ | 308.7 |
|
NOTE 4 – ACCRUED LIABILITIES
Accrued liabilities at December 31 consisted of the following (in thousands)millions):
| | | | 2014 | | 2013 | 2017 | | 2016 |
| Pension and other postretirement benefits | $ | 26,219 |
| | $ | 49,659 |
| $ | 27.0 |
| | $ | 32.1 |
|
| Compensation and related employee costs | 88,186 |
| | 59,096 |
| 69.0 |
| | 62.4 |
|
| Interest | 47,414 |
| | 27,841 |
| 32.0 |
| | 33.6 |
|
| Income taxes | 13,265 |
| | 8,374 |
| 15.4 |
| | 18.3 |
|
| Other | 19,175 |
| | 11,001 |
| 15.7 |
| | 12.4 |
|
| Total accrued liabilities | $ | 194,259 |
| | $ | 155,971 |
| $ | 159.1 |
| | $ | 158.8 |
|
NOTE 5 – LONG-TERM DEBT
Long-term debt at December 31 consisted of the following (in thousands)millions):
|
| | | | | | | |
| | 2014 | | 2013 |
| 5% Senior Notes, due September 2017 ($400 million principal amount; 5.1% effective rate) | $ | 399,244 |
| | $ | 398,961 |
|
| 7.875% Senior Notes, due August 2019 ($500 million principal amount; 8.0% effective rate) | 498,500 |
| | 498,171 |
|
| 4.875% Senior Notes, due June 2022 ($700 million principal amount; 4.6% effective rate) | 711,640 |
| | 713,208 |
|
| 4.75% Senior Notes, due January 2024 ($400 million principal amount; 4.8% effective rate) | 399,631 |
| | — |
|
| 5.4% Senior Notes, due December 2042 ($400 million principal amount; 5.4% effective rate) | 398,417 |
| | 398,360 |
|
| 5.85% Senior Notes, due January 2044 ($400 million principal amount; 5.9% effective rate) | 399,892 |
| | — |
|
| Total long-term debt | $ | 2,807,324 |
| | $ | 2,008,700 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| 5% Senior Notes, due September 2017 ($92.2 million principal amount; 5.2% effective rate) | $ | — |
| | $ | 92.0 |
|
| 7.875% Senior Notes, due August 2019 ($201.4 million and $209.8 million principal amount, respectively; 8.0% effective rate) | 200.9 |
| | 208.9 |
|
| 4.875% Senior Notes, due June 2022 ($620.8 million and $690.2 million principal amount, respectively; 4.7% effective rate) | 624.6 |
| | 695.4 |
|
| 4.75% Senior Notes, due January 2024 ($398.1 million principal amount; 4.8% effective rate) | 395.9 |
| | 395.6 |
|
| 7.375% Senior Notes, due June 2025 ($500 million principal amount; 7.4% effective rate) | 497.5 |
| | 497.2 |
|
| 5.4% Senior Notes, due December 2042 ($400 million principal amount; 5.4% effective rate) | 395.1 |
| | 394.9 |
|
| 5.85% Senior Notes, due January 2044 ($400 million principal amount; 5.9% effective rate) | 396.3 |
| | 396.2 |
|
| Total carrying value | 2,510.3 |
| | 2,680.2 |
|
Current portion (1) | — |
| | 126.8 |
|
| Carrying value, less current portion | $ | 2,510.3 |
| | $ | 2,553.4 |
|
| | | | |
| (1) Current portion of long-term debt at December 31, 2016, included the 5% Senior Notes due 2017, as well as the portion of 7.875% Senior Notes due 2019 and 4.875% Senior Notes due 2022 tendered in December 2016 but not settled until January 2017. |
The following is a summary of scheduled long-term debt maturities by year, as of December 31, 2017 (in millions):
|
| | | |
| 2018 | $ | — |
|
| 2019 | 201.4 |
|
| 2020 | — |
|
| 2021 | — |
|
| 2022 | 620.8 |
|
| Thereafter | 1,698.1 |
|
| | $ | 2,520.3 |
|
Revolving Credit Facility
Availability under the Revolving Credit Facility is $1.50 billion through January 23, 2019, declining to $1.44 billion through January 23, 2020, and to approximately $1.29 billion through the maturity in 2021. As of December 31, 2014,2017, no principal payments areamounts were outstanding and $5.0 million in letters of credit had been issued under the Revolving Credit Facility leaving remaining availability of $1.495 billion.
Advances under the Revolving Credit Facility bear interest at LIBOR or Base Rate plus an applicable margin, which is dependent upon the Company's credit ratings. The applicable margins for LIBOR and Base Rate advances range from 1.125% - 2.0% and 0.125% - 1.0%, respectively. The Company is also required with respect to our outstanding debt through 2016; $400 million becomes due in September 2017pay a commitment fee on undrawn amounts of the Revolving Credit Facility, which ranges from 0.125% to 0.35%, and $500 million becomes due in August 2019.depending on the Company's credit ratings.
The Revolving Credit Facility requires the Company to maintain a total debt-to-capitalization ratio of less than or equal to 60%. Additionally, the Revolving Credit Facility has customary restrictive covenants that, including others, restrict the Company's ability to incur certain debt and liens, enter into certain merger and acquisition agreements, sell, transfer, lease or otherwise dispose of all or substantially all of the Company's assets and substantially change the character of the Company's business from contract drilling.
Debt Reductions
During 2015, the Company paid $101.1 million in cash to retire $97.9 million aggregate principal amount of the 2017 Notes and the 2019 Notes, plus accrued interest, and recognized a $1.5 million loss on early extinguishment of debt.
During the first half of 2016, the Company paid $45.2 million in cash to retire $47.9 million aggregate principal amount of the 2017 Notes and the 2019 Notes, and recognized a $2.4 million gain on early extinguishment of debt.
In December 2016, the Company commenced cash tender offers for $750 million aggregate principal amount of the Subject Notes issued by the Company (the "Tender Offers"). The Tender Offers expired on January 3, 2017; however, there was also an early tender expiration on December 16, 2016 which provided for an early tender premium. Subject Notes validly tendered and accepted for purchase prior to the early tender expiration time on December 16, 2016, received tender offer consideration plus an early tender premium. As a result of the Tender Offers, in December 2016, the Company paid $490.5 million to repurchase $463.9 million aggregate principal amount of outstanding Subject Notes, consisting of $265.5 million of the 2017 Notes, $186.7 million of the 2019 Notes, $9.8 million of the 2022 Notes and $1.9 million of the 2024 Notes, and recognized a $33.6 million loss on the early extinguishment of debt which included approximately $5.9 million of bank and legal fees.
On January 15, 2014,December 19, 2016, Rowan plc, as guarantor, and its 100% owned subsidiary, RCI, as issuer, completed the issuance and sale in a public offering of $400$500 million aggregate principal amount of its 4.75% Seniorthe 2025 Notes due 2024 at a price to the public of 99.898%100% of the principal amount. The Company used the net proceeds of the offering, approximately $492 million, along with cash on hand, to fund the repurchase of Subject Notes pursuant to the Tender Offers. $5.3 million of the cash paid to the underwriting banks in the form of the underwriters discount and structuring fee was expensed and included in the $33.6 million loss on early extinguishment of debt related to the Tender Offers. Interest on the 2025 Notes is payable on June 15 and December 15 of each year and began on June 15, 2017. The 2025 Notes contain a provision whereby upon a change of control repurchase event, as defined in the indenture governing the 2025 Notes, the Company may be required to make an offer to repurchase all outstanding notes at a price in cash equal to 101% of the aggregate principal amount of the notes repurchased, plus any accrued and $400unpaid interest to the repurchase date. Otherwise, the 2025 Notes contain substantially the same provisions as the Company’s other Senior Notes.
In January 2017, at the expiration of the Tender Offers, the Company paid $32.8 million to repurchase an additional $34.6 million aggregate principal amount of its 5.85% Senioroutstanding Subject Notes, due 2044 at a price to the publicconsisting of 99.972%$0.1 million of the principal amount. Net proceeds2017 Notes, $0.9 million of the offering were approximately $7922019 Notes and $33.6 million whichof the 2022 Notes.
On January 9, 2017, the Company used in its rig construction programcalled for redemption $92.1 million aggregate principal amount of the 2017 Notes that remained outstanding and for general corporate purposes. Also in January,on February 8, 2017, the Company amendedpaid $94.0 million to redeem such notes.
In the second quarter of 2017, the Company paid $33.5 million in cash to retire $35.8 million aggregate principal amount of the 2022 Notes and restated its credit agreementrecognized a $2.4 million gain on early extinguishment of debt.
In July 2017, the Company paid $7.0 million in cash to increaseretire $6.5 million aggregate principal amount of the borrowing capacity under the revolving credit facility from $7502019 Notes and recognized a $0.5 million to $1.0 billion, among other things. There were no amounts drawn under the revolving credit facility at December 31, 2014. loss on early extinguishment of debt.
Debt Guarantee and Other Provisions
The 5%Senior Notes due 2017, 7.875% Senior Notes due 2019, 4.875% Senior Notes due 2022, 4.75% Senior Notes due 2024, 5.4% Senior Notes due 2042, and 5.85% Senior Notes due 2044 (together, the "Senior Notes") are RCI’s senior unsecured obligations and rank senior in right of payment to all of its subordinated indebtedness and pari passu in right of payment with any of RCI’s future senior indebtedness, including any indebtedness under RCI’s senior revolving credit facility.Revolving Credit Facility. The Senior Notes rank effectively junior to RCI’s future secured indebtedness, if any, to the extent of the value of its assets constituting collateral securing that indebtedness and to all existing and future indebtedness of its subsidiaries (other than indebtedness and liabilities owed to RCI).
All or part of the Senior Notes may be redeemed at any time for an amount equal to 100% of the principal amount plus accrued and unpaid interest to the redemption date plus the applicable make-whole premium, if any.
The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan plc (see Note 15).
17 ).
Restrictive provisions in the Company’s bank credit facility agreement limit consolidated debt to 60% of book capitalization. OurThe Company's consolidated debt to total capitalization ratio at December 31, 2014,2017, was 37%32%.
Other provisions of ourthe Company's debt agreements limit the ability of the Company to create liens that secure debt, engage in sale and leaseback transactions, merge or consolidate with another company and, in the event of noncompliance, restrict investment activities and asset purchases and sales, among other things. Additionally, the revolving credit facility agreement provides that the facility will not be available in the event of a material adverse change in the Company’s condition, operations, business, assets, liabilities or ability to perform. The Company was in compliance with its debt covenants at December 31, 2014.2017.
NOTE 6 – DERIVATIVES
In 2016, the Company determined that the FCX Contingent Payments Provisions resulting from the contract termination with FMOG (See Note 1) were freestanding financial instruments and that they each met the criteria of a derivative instrument. The FCX Contingent Payments Provisions were initially recorded to revenue at a fair value of $6.2 million on May 23, 2016, and were revalued at each reporting date with changes in the fair value reported as non-operating income or expense. The fair value of the FCX Contingent Payments Provisions was determined using a Monte Carlo simulation (see Note 7). In January 2017, the Company and FCX settled the First FCX Contingent Payment Provision with a $6.0 million payment received by the Company. At maturity, the value of the Second FCX Contingent Payment Provision was zero based on the actual results of the average price of WTI crude oil over the period determined in the agreement; therefore, no payment was due to the Company. The following table provides the fair value of the Company’s derivative as reflected in the Consolidated Balance Sheets (in millions):
|
| | | | | | |
| Balance sheet classification | Fair value |
| | December 31, 2017 | December 31, 2016 |
| Derivative: | | |
| FCX Contingent Payments Provisions | | |
| Prepaid expenses and other current assets | $ | — |
| $ | 6.1 |
|
The following table provides the revaluation effect of the Company’s derivative on the Consolidated Statements of Operations (in millions):
|
| | | | | | | | | |
| | | | | Amount of gain (loss) recognized in income (loss) |
| Derivative | | Classification of gain (loss) recognized in income (loss) | | Year ended December 31, 2017 | Year ended December 31, 2016 |
| FCX Contingent Payments Provisions | | Other - net | | $ | (0.1 | ) | $ | (0.1 | ) |
NOTE 67 – FAIR VALUE MEASUREMENTS
Fair value is defined as the exchange price that would be received for an asset or paid to transfer a liability (an exit price) in the principal or most advantageous market for the asset or liability in an orderly transaction between market participants on the measurement date. The fair value hierarchy prescribed by US GAAP requires an entity to maximize the use of observable inputs and minimize the use of unobservable inputs when measuring fair value. The three levels of inputs that may be used to measure fair value are:
Level 1 – Quoted prices for identical instruments in active markets;
Level 2 – Quoted market prices for similar instruments in active markets; quoted prices for identical instruments in markets that are not active, and model-derived valuations in which all significant inputs and significant value drivers are observable in active markets; and
Level 3 – Valuations derived from valuation techniques in which one or more significant inputs or significant value drivers are unobservable, such as those used in pricing models or discounted cash flow methodologies, for example.
The applicable level within the fair value hierarchy is the lowest level of any input that is significant to the fair value measurement.
Derivative
The fair values of the FCX Contingent Payments Provisions (Level 3) were estimated using a Monte Carlo simulation model, which calculated the probabilities of the daily closing WTI spot price exceeding the Price Targets on a daily averaging basis during the 12-month payment measurement period ending on June 30, 2017. The probabilities were applied to the payout at each price target to calculate the probability-weighted expected payout. The following were the significant inputs used in the valuation of the FCX Contingent Payments Provisions: the WTI Spot Price on the valuation date, the expected volatility, and the risk-free
interest rate, and the slope of the WTI forward curve, which were $47.48, 37.5%, 0.765% and 5.5% at May 23, 2016, respectively, and $53.72, 28.557%, 0.734%, and 11.205% at December 31, 2016, respectively. The expected volatility was estimated from the implied volatility rates of WTI crude futures. The risk-free rate was based on yields of U.S. Treasury securities commensurate with the remaining term of the FXC Contingent Payments. At December 31, 2016, the Company valued the FCX Contingent Payments Provisions in the amount of $6.1 million which was classified as Prepaid expenses and other current assets on the Consolidated Balance Sheet. In January 2017, the Company and FCX settled the First FCX Contingent Payment Provision with a $6.0 million payment received by the Company (see Note 1). The Second FCX Contingent Payment Provision had no value at maturity, as the average price of WTI crude oil did not meet the terms specified in the FCX Agreement; therefore, no payment was due to the Company (see Note 6). Assets and Liabilities Measured at Fair Value on a Recurring Basis
Assets and liabilities measured at fair value on a recurring basis at December 31 are presented below (in thousands)millions):
|
| | | | | | | | | | | | | | | |
| | | | Estimated fair value measurements |
| | Carrying value | | Quoted prices in active markets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) |
| December 31, 2014: | | | | | | | |
| Assets - cash equivalents | $ | 314,570 |
| | $ | 314,570 |
| | $ | — |
| | $ | — |
|
| Other assets | 16,304 |
| | 16,304 |
| | — |
| | — |
|
| | | | | | | | |
| December 31, 2013: | | | | | | | |
| Assets - cash equivalents | $ | 1,063,500 |
| | $ | 1,063,500 |
| | $ | — |
| | $ | — |
|
|
| | | | | | | | | | | | | | | |
| | | | Estimated fair value measurements |
| | Fair value | | Quoted prices in active markets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) |
| December 31, 2017: | | | | | | | |
| Assets - cash equivalents | $ | 1,332.1 |
| | $ | 1,332.1 |
| | $ | — |
| | $ | — |
|
| Other assets (Egyptian Pounds) | 2.2 |
| | 2.2 |
| | — |
| | — |
|
| Other assets (Angolan Kwanza) | 4.3 |
| | 4.3 |
| | — |
| | — |
|
| | | | | | | | |
| December 31, 2016: | | | | | | | |
| Assets - cash equivalents | $ | 1,242.3 |
| | $ | 1,242.3 |
| | $ | — |
| | $ | — |
|
| Derivative | 6.1 |
| | — |
| | — |
| | 6.1 |
|
| Other assets (Egyptian Pounds) | 4.2 |
| | 4.2 |
| | — |
| | — |
|
At December 31, 2016, the Company had FCX Contingent Payments Provisions in the amount of $6.1 million, which is classified as Prepaid expenses and other current assets on the Consolidated Balance Sheet.
At December 31, 2017 and 2016, the Company held Egyptian pounds in the amount of $2.2 million and $4.2 million, respectively, which are classified as Other assets on the Consolidated Balance Sheets. The Company ceased drilling operations in Egypt in 2014, and is currently working to obtain access to the funds for use outside Egypt to the extent they are not utilized.
Given stricter foreign currency exchange controls in Angola, the Company determined in May 2017 that its previous method of converting Angola Kwanza to USD is likely no longer feasible. As a result, at December 31, 2017, the Company classified its Angolan Kwanza USD equivalent balance of $4.3 million as a non-current asset in Other assets on the Consolidated Balance Sheet. Currently, the Company considers the amounts to be recoverable and will continue to evaluate options to convert the Angolan Kwanza to USD.
Trade receivables and trade payables, which are also required to be measured at fair value, have carrying values that approximate their fair values due to their short maturities.
In 2014 we terminated operations in Egypt, where we held approximately $16.3 million in Egyptian pounds, valued at the exchange rate in effect at December 31, 2014. We may be unable to convert, utilize or repatriate such funds in the future. As a result, we have reclassified such amount to a noncurrent asset as of December 31, 2014.
Assets Measured at Fair Value on a Nonrecurring Basis
Assets measured at fair value on a nonrecurring basis atand whose carrying values were remeasured during the years ended December 31 are set forth below (in thousands)millions):
| | | | | | Estimated fair value measurements | | | | | Estimated fair value measurements | | |
| | Carrying value | | Quoted prices in active markets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) | | Total gains (losses) | Fair value | | Quoted prices in active markets (Level 1) | | Significant other observable inputs (Level 2) | | Significant unobservable inputs (Level 3) | | Total gains (losses) |
| December 31, 2014: | | | | | | | | | | |
| 2016: | | | | | | | | | | |
Property and equipment, net | $ | 275,148 |
| | $ | — |
| | $ | — |
| | $ | 275,148 |
| | $ | (565,650 | ) | $ | 9.3 |
| | $ | — |
| | $ | — |
| | $ | 9.3 |
| | $ | (34.3 | ) |
| | | | | | | | | | | |
| 2015: | | | | | | | | | | |
Property and equipment, net (2) | | $ | 128.0 |
| | $ | — |
| | $ | — |
| | $ | 128.0 |
| | $ | (329.8 | ) |
| | | | | | | | | | | |
| (1) This represents a non-recurring fair value measurement made at September 30, 2016 for five jack-up drilling units. | | (1) This represents a non-recurring fair value measurement made at September 30, 2016 for five jack-up drilling units. |
| (2) This represents a non-recurring fair value measurement made at September 30, 2015 for ten jack-up drilling units. | | (2) This represents a non-recurring fair value measurement made at September 30, 2015 for ten jack-up drilling units. |
In 2014 we2016, the Company recognized a noncashnon-cash asset impairment charge of $565.7charges aggregating $34.3 million on twelvefive of the Company's oldestits jack-up drilling units with ahaving an aggregate net carrying value aggregating $840.8of $43.6 million prior to the write-down. See Note 2,Two of these jack-up drilling units were sold in the fourth quarter of 2016 for gross proceeds of approximately $5.0 million and the Company recognized a net loss on sale of $1.2 million. In 2015, the Company recognized non-cash asset impairment charges aggregating $329.8 million on ten of its jack-up drilling units having an aggregate net carrying value of $457.8 million prior to the write-down. Impairment charges are included in Material Charges and Other Operating Items on the Consolidated Statements of Operations (see "Impairment of Long-lived Assets."
Assets" in Note 2). The financial information for these rigs has been reported as part of the Jack-ups segment. Other Fair Value Measurements
Those financialFinancial instruments not required to be measured at fair value consist of the Company’s publicly traded debt securities. The Company's publicly traded debt securities had a carrying value of $2.510 billion at December 31, 2017, and an estimated fair value at that date aggregating $2.262 billion, compared to a carrying and fair value of $2.680 billion and $2.448 billion, respectively, at December 31, 2016. Fair values of the Company’sCompany's publicly traded debt securities were provided by one to two brokersa broker who makemakes a market in our debtsuch securities and were measured using a market-approach valuation technique. Fair value was determined by addingtechnique, which is a spread based on actual trades for that security (or a trader quote where actual trades were unavailable) to the applicable benchmark Treasury security with a
comparable maturity in order to derive a current yield. The yield is then used to determine a price given the individual security’s coupon rate and maturity. Such inputs are considered “significant other observable inputs,” which are categorized as Level 2 inputs in the fair value hierarchy. Estimated fair values and related carrying values of our long-term debt securities at December 31 are presented below (in thousands):
|
| | | | | | | | | | | | | | | |
| | 2014 | | 2013 |
| | Fair value | | Carrying value | | Fair value | | Carrying value |
| 5% Senior Notes, due 2017 | $ | 414,552 |
| | $ | 399,244 |
| | $ | 433,879 |
| | $ | 398,961 |
|
| 7.875% Senior Notes, due 2019 | 570,626 |
| | 498,500 |
| | 603,177 |
| | 498,171 |
|
| 4.875% Senior Notes, due 2022 | 680,165 |
| | 711,640 |
| | 711,816 |
| | 713,208 |
|
| 4.75% Senior Notes, due 2024 | 377,703 |
| | 399,631 |
| | — |
| | — |
|
| 5.4% Senior Notes, due 2042 | 345,835 |
| | 398,417 |
| | 368,602 |
| | 398,360 |
|
| 5.85% Senior Notes, due 2044 | 366,132 |
| | 399,892 |
| | — |
| | — |
|
| | $ | 2,755,013 |
| | $ | 2,807,324 |
| | $ | 2,117,474 |
| | $ | 2,008,700 |
|
measurement.
Concentrations of Credit Risk
We invest ourThe Company invests its excess cash primarily in time deposits and high-quality money market accounts at several large commercial banks with strong credit ratings, and therefore believebelieves that ourits risk of loss is minimal.
The Company’s customers largely consist of major international oil and gas explorationcompanies, national oil companies and national oillarge investment-grade exploration and production companies. WeThe Company routinely evaluateevaluates and monitors the credit quality of potential customers. One customer, Saudi Aramco, accounted for 24% of consolidated revenues in 2014 and 29% of the consolidated trade receivable balance at December 31, 2014. In 2013 one customer accounted for 26% and another accounted for 11% of consolidated revenues. In 2012 one customer accounted for 29% and another accounted for 11% of consolidated revenues.current customers. The Company maintains reserves for credit losses when necessary and actual losses have been within management’smanagement's expectations.
Revenue and receivables from transactions with external customers that amount to 10% or more of revenue during the years ended December 31 are set forth below:
Percentage of revenue from major customers:
|
| | | | | | | | |
| | Years ended December 31, |
| | 2017 | | 2016 | | 2015 |
Saudi Aramco (2) | 29 | % | | 20 | % | | 19 | % |
Anadarko (3) | 17 | % | | 8 | % | | 10 | % |
Cobalt International (1) (3) | 14 | % | | 12 | % | | 8 | % |
Repsol (3) | 7 | % | | 12 | % | | 5 | % |
ConocoPhillips (2) | 7 | % | | 11 | % | | 13 | % |
Freeport-McMoRan (3) | — | % | | 12 | % | | 6 | % |
| | | | | | |
(1) The year ended December 31, 2017 includes amortization of $95.9 million of revenue deferred in 2016 related to a contract amendment to the Company's subsidiary's drilling contract with Cobalt International (See Note 1).
|
| (2) Included in the Jack-ups Segment |
| (3) Included in the Deepwater Segment |
Percentage of receivables from major customers:
|
| | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 |
Saudi Aramco (1) | 34 | % | | 32 | % | | 34 | % |
Anadarko (2) | 19 | % | | 4 | % | | 9 | % |
Cobalt International (2) | — | % | | 19 | % | | 5 | % |
Repsol (2) | 5 | % | | 12 | % | | 1 | % |
ConocoPhillips (1) | 8 | % | | 8 | % | | 12 | % |
Freeport-McMoRan (2) | — | % | | — | % | | 9 | % |
| | | | | | |
| (1) Included in the Jack-ups Segment | | |
| (2) Included in the Deepwater Segment | | |
NOTE 78 – COMMITMENTS AND CONTINGENT LIABILITIES
The Company has operating leases covering office space and equipment. Certain of the leases are subject to escalations based on increases in building operating costs. Rental expense attributable to continuing operations was $13.811.4 million, $10.6 million and $13.2 million in 2014, $9.3 million in 20132017, 2016 and 2015, respectively.$8.0 million in 2012.
At December 31, 2014,2017, future minimum payments to be made under noncancelable operating leases were as follows (in thousands):
|
| | | |
| 2015 | $ | 7,045 |
|
| 2016 | 5,765 |
|
| 2017 | 5,655 |
|
| 2018 | 5,615 |
|
| 2019 | 5,573 |
|
| Later years | 16,138 |
|
| | $ | 45,791 |
|
The following table presents the status of the Company’s rigs under construction as of December 31, 2014. Project costs include capitalized interest (in millions):
|
| | | | | | | | | | | | | | | | | |
| | Actual/scheduled delivery date | | Total estimated project costs | | Total costs incurred through Dec. 31, 2014 | | Projected costs in 2015 | | Total future costs |
| Rowan Reliance | November 2014 | | $ | 722 |
| | $ | 687 |
| | $ | 35 |
| | $ | 35 |
|
| Rowan Relentless | March 2015 | | 750 |
| | 258 |
| | 492 |
| | 492 |
|
| | | | $ | 1,472 |
| | $ | 945 |
| | $ | 527 |
| | $ | 527 |
|
|
| | | |
| 2018 | $ | 11.8 |
|
| 2019 | 8.1 |
|
| 2020 | 4.4 |
|
| 2021 | 1.4 |
|
| 2022 | 1.5 |
|
| Later years | 9.6 |
|
| | $ | 36.8 |
|
In addition, theThe Company expects to incur approximately $120 million of capital expenditures in 2015 for mobilization, commissioning, riser gas-handling equipment, software certifications and drillship fleet spares to support its deepwater operations, and approximately $10 million for late-arriving equipment for the first two drillships delivered in 2014.
We havehad commitments for other purchase obligations totaling $210$80.0 million at December 31, 2014.2017.
WeLetters of credit – The Company periodically employemploys letters of credit in the normal course of ourits business and had outstanding letters of credit of approximately $22.37.3 million at December 31, 2014.2017, of which $5.0 million were issued under the Company's Revolving Credit Facility.
Joint venture funding obligations – For the Company's potential obligation to fund ARO for newbuild jack-up rigs see Note 1. Uncertain tax positions – InThe Company has been advised by the IRS of proposed unfavorable tax adjustments of $85 million including applicable penalties for the open tax years 2009 through 2012. The unfavorable tax adjustments primarily related to the Company recognized certainfollowing items: 2009 tax benefits recognized as a result of applying the facts of a third-party tax case to the Company’s situation. That casethat provided a more favorable tax treatment for certain foreignnon-U.S. contracts entered into in prior years. Our position was challengedyears to the Company’s situation; transfer pricing; and domestic production activity deduction. The Company has protested the proposed adjustment. However, the IRS does not agree with the Company's protest and they have submitted the proposed unfavorable tax adjustments to be reviewed by the U.S. Internal Revenue Service ("IRS"). We appealed their findingsIRS appeals group. In years subsequent to 2012, the Company has similar positions that could be subject to adjustments for the open years. The Company has provided for amounts that it believes will be ultimately payable under the proposed adjustments and reached a settlement agreement in September 2014 with respect to three of the four years under review in the amount of approximately $36 million, including interest, which we collected in October 2014. A remaining year continues to be under examination. We planintends to vigorously defend our position.its positions; however, if the Company determines the provisions for these matters to be inadequate due to new information or the Company is required to pay a significant amount of additional U.S. taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, the Company's consolidated results of operations and cash flows could be materially and adversely affected.
The gross unrecognized tax benefits excluding penalties and interest are $102 million and $120 million as of December 31, 2017 and 2016, respectively. The decrease to gross unrecognized tax benefits was primarily due to a lapse in statutes of limitation and audit settlement offset by foreign currency exchange revaluation and tax positions taken related to current year anticipated transfer pricing positions. If the December 31, 2017 net unrecognized tax benefits excluding penalties and interest were recognized, this would favorably impact the Company's tax provision by $41 million.
We areIt is reasonable that the existing liabilities for the unrecognized tax benefits may increase or decrease over the next 12 months as a result of audit closures and statute expirations, however, the ultimate timing of the resolution and/or closure of audits is highly uncertain.
Pending or threatened litigation – The Company is involved in various routine legal proceedings incidental to ourits businesses and are vigorously defending ourdefends its position in all such matters. TheAlthough the outcome of such proceedings cannot be predicted with certainty, the Company believes that there are no known contingencies, claims or lawsuits that couldwill have a material adverse effect on its financial position, results of operations or cash flows.
In addition to the legal proceedings described above, we are vigorously contesting a claim by a former agent in the Middle East for compensation associated with the Company's termination of the agent's services. In February 2018, the agent made a demand for approximately $45 million, which the Company believes is without merit. The Company is making payments pursuant to its agreements with the agent and has an accrual for the Company's best estimate of the potential liability. Because of the current uncertainty of the basis for the claim and the application of which law may apply to resolving the dispute, the amount of the accrual may be different from the amount of the ultimate liability.
NOTE 89 – SHARE-BASED COMPENSATION PLANS
Under the 2013 Rowan Companies plc Incentive Plan, (the Plan), the Company Compensation Committee of the Company’s Board of Directors is authorized to grant employees and nonemployeenon-employee directors incentive awards covering up to 7,500,000 of our ordinary shares. The awards may be in the form of restricted share awards, restricted share units,RSAs, RSUs, options and share appreciation rights.SARs. In addition, the Company Compensation Committee may grant performance-based awards under the Plan (such as P-Units which may be settled in shares cash, or a combination thereof at the discretion of the Company Compensation Committee), for which the amount earned is dependent on the achievement of certain long-term market or performance conditions over a specified period. As of December 31, 2014,2017, there were 5,619,2128,548,953 shares available for future grant under the Plan.Plan, including 2,174,572 additional shares approved for issuance by the shareholders at the Annual General Meeting on May 25, 2017. Shares issued to satisfy awards to employees are issued from the Company's EBT which are deemed treasury shares, while shares issued to satisfy awards to non-employee directors are newly issued shares. In accordance with the Company's adoption of ASU 2016-09, the Company no longer estimates forfeitures but rather accounts for forfeitures in the period in which they occur; therefore the expected to vest percentage is 100% for awards not vested.
Compensation cost charged to expense under all share-based incentive awards is presented below (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Restricted shares and restricted share units | $ | 23,577 |
| | $ | 23,786 |
| | $ | 18,557 |
| $ | 19.3 |
| | $ | 21.8 |
| | $ | 22.5 |
|
| Share appreciation rights | 3,724 |
| | 6,412 |
| | 5,358 |
| — |
| | 0.2 |
| | 1.1 |
|
| Share options | — |
| | 23 |
| | 152 |
| |
| Performance-based awards | 7,246 |
| | 3,710 |
| | 741 |
| 9.7 |
| | 12.6 |
| | 10.0 |
|
| Total compensation cost | $ | 34,547 |
| | $ | 33,931 |
| | $ | 24,808 |
| $ | 29.0 |
| | $ | 34.6 |
| | $ | 33.6 |
|
As of December 31, 2014,2017, unrecognized compensation cost related to nonvested share-based compensation arrangements totaled $33.232.7 million, which is expected to be recognized over a weighted-average period of 1.81.7 years.
Restricted Shares (Employees and Non-employee Directors) – A restricted share represents anRSAs represent ordinary shareshares subject to a vesting period that restricts its sale or transfer until the vesting period ends. In general, the restricted shares vestgranted to employees vested and the restrictions lapselapsed in one-third increments each year over a three-year service period, or in some cases, cliff vestvested at the end of a three-year service period. Restricted share activityThe Company discontinued granting restricted shares as annual awards to employees beginning in 2013 and all restricted shares granted to employees were vested as of December 31, 2016. In 2016, the Company granted RSAs to non-employee directors and such vested and were settled in shares on the date of the 2017 annual meeting of shareholders. Activity related to RSAs for the year ended December 31, 2014,2017, is summarized below:
|
| | | | | | |
| | Number of Shares | | Weighted-average grant-date fair value per share |
| Nonvested at January 1, 2014 | 553,441 |
| | $ | 36.50 |
|
| Granted | — |
| | — |
|
| Vested | (340,633 | ) | | 37.35 |
|
| Forfeited | (2,254 | ) | | 36.10 |
|
| Nonvested at December 31, 2014 | 210,554 |
| | $ | 35.13 |
|
|
| | | | | | |
| | Number of Shares | | Weighted-average grant-date fair value per share |
| | (in thousands) | | |
| Nonvested at January 1, 2017 | 54 |
| | $ | 18.60 |
|
| Vested | (54 | ) | | 18.60 |
|
| Nonvested at December 31, 2017 | — |
| | $ | — |
|
restricted shares granted in 2016 was $18.60. No restricted shares were granted in 2017 and 2015. The aggregate fair value of restricted shares that vested in 2014, 20132017, 2016 and 20122015 was $10.9$758 thousand, $37 thousand and $4.1 million,, $16.2 million and $17.8 million, respectively, based on share prices on the vesting dates.
Employee Restricted Share Units – Restricted share units (RSUs)RSUs are rights to receive a specified number of ordinary shares upon vesting. RSUs granted to employees typically vest in one-third increments over a three-year service period or in some cases, cliff vest at the end of three years. Employee RSU activity for the year ended December 31, 2014,2017, follows:
| | | | Number of Shares | | Weighted-average grant-date fair value per share | Number of Shares | | Weighted-average grant-date fair value per share |
| Nonvested at January 1, 2014 | 603,665 |
| | $ | 34.44 |
| |
| | | (in thousands) | | |
| Nonvested at January 1, 2017 | | 2,243 |
| | $ | 15.59 |
|
| Granted | 842,836 |
| | 32.45 |
| 1,501 |
| | 17.09 |
|
| Vested | (279,191 | ) | | 34.17 |
| (984 | ) | | 17.96 |
|
| Forfeited | (35,157 | ) | | 33.65 |
| (324 | ) | | 15.38 |
|
| Nonvested at December 31, 2014 | 1,132,153 |
| | $ | 33.05 |
| |
| Nonvested at December 31, 2017 | | 2,436 |
| | $ | 15.59 |
|
The aggregateweighted-average grant date fair value of employee RSUs that vestedgranted in 20142017, 2016 and 20132015 was $8.5 million$17.09, $11.62 and $0.5 million,$21.11, respectively. The aggregate fair value of employee RSUs that vested in 20122017, 2016 and 2015 was not material.$17.8 million, $14.6 million and $8.9 million, respectively.
Non-employee Director Deferred Restricted Share Units and Non-employee Director Non-Deferred Restricted Share Units – Non-employee directors may annually elect to receive either Directors RSUs granted to nonemployee directors generally cliffor Directors ND RSUs. Both Directors RSUs and Directors ND RSUs vest at the earlier of the first anniversary of the grant date or the next annual meeting of shareholders following the grant date. Directors ND RSUs are settled on the vesting date, while Director RSUs are not settled until the director terminates service from the Board. Both Directors ND RSUs and Directors RSUs are settled in either cash, or shares or a combination thereof at the discretion of the Company Compensation Committee determined at the time the director terminates serviceCommittee.
Activity related to the Board. Non-employee director RSU activityDirectors RSUs for the year ended December 31, 2014,2017, follows:
|
| | | | | | |
| | Number of shares | | Weighted-average grant-date fair value per share |
| Outstanding at January 1, 2014 | 250,648 |
| | $ | 32.42 |
|
| Granted | 54,041 |
| | 31.10 |
|
| Settled | (37,251 | ) | | 33.25 |
|
| Outstanding at December 31, 2014 | 267,438 |
| | $ | 32.04 |
|
| | | | |
| Vested at December 31, 2014 | 216,254 |
| | $ | 32.22 |
|
|
| | | | | | |
| | Number of shares | | Weighted-average grant-date fair value per share |
| | (in thousands) | | |
| Outstanding at January 1, 2017 | 287 |
| | $ | 27.78 |
|
| Granted | 30 |
| | 13.24 |
|
| Settled | (114 | ) | | 29.85 |
|
| Outstanding at December 31, 2017 | 203 |
| | $ | 25.62 |
|
| | | | |
| Vested at December 31, 2017 | 173 |
| | $ | 27.78 |
|
The weighted-average grant date fair value of non-employee Directors RSUs granted in 2017, 2016 and 2015 was $13.24, $17.43 and $20.96, respectively. The number and aggregate settlement-date fair value of non-employee directorDirectors RSUs settled during the year were as follows: 20142017 – 37,251114 thousand Directors RSUs at $1.2 million; 2013$1.5 million; 2016 – 23,92854 thousand Directors RSUs at $0.8$1.0 million; 20122015 – 43,07244 thousand Directors RSUs at $1.4$0.9 million.
OtherActivity related to Directors ND RSUs for the year ended December 31, 2017, follows:
|
| | | | | | |
| | Number of shares | | Weighted-average grant-date fair value per share |
| | (in thousands) | | |
| Outstanding at January 1, 2017 | — |
| | $ | — |
|
| Granted | 91 |
| | 13.24 |
|
| Settled | — |
| | — |
|
| Outstanding at December 31, 2017 | 91 |
| | $ | 13.24 |
|
| | | | |
| Vested at December 31, 2017 | — |
| | $ | — |
|
The weighted-average grant date fair value of non-employee Directors ND RSUs granted in 2017 was $13.24.
Directors RSUs and Directors ND RSUs are accounted for under the liability method. Accordingly, other long-term liabilities at December 31, 20142017 and 2013,2016, included liabilities for non-employee director RSUs in the amount of $5.8$3.8 million and $8.1$5.2 million, respectively.
respectively, related to such awards.
Performance-based Awards – The Company Compensation Committee may grant awards in which payment is contingent upon the achievement of certain market or performance-based conditions over a period of time specified by the Committee. Payment of such awards may be in ordinary shares or in cash as determined by the Committee.
In March 2014During 2015, 2016 and 2017, the Company granted to certain members of management performance units (P-Units)P-Units that have a target value of $100 per unit. The amount ultimately earned with respect to the P-Units will depend onis determined by the Company’s total shareholder return (TSR) ranking comparedTSR relative to a selected group of peer companies, as selected by the Company Compensation Committee, over a three-year period ending December 31, 2017, 2018 and 2019 for the 2015, 2016 and 2017 grants, respectively. The amount earned could range from zero to $200 per unit depending on performance. Twenty-five percent of the P-Units’ value is determined by the Company’s relative TSR ranking for each one-year period ended December 31 2014, 2015, and 2016, respectively, and 25% of the P-Units’ value is determined by the relative TSR ranking for the three-year period ended December 31, 2016. Vesting of awards31. P-Units cliff vest and payment is made, if any, payment with respect to the P-Units would not occur untilon the third anniversary following the grant date. Any employee who terminates employment with the Company prior to the third anniversary for any reason other than retirement will not receive any payment with respect to P-Units unless approved by the Company Compensation Committee. Settlement of the P-Units granted in 2016 and 2017 may be in cash, shares or a combination thereof at the Company Compensation Committee's discretion. The
Company Compensation Committee has previously determined that any amount earned with respect to P-Units granted in 20142015 would be settled in cash.
The grant-date fair value of P-Units granted in 20142017, 2016 and 2015 was estimated to be $9.1 million.$9.5 million, $8.6 million and $9.0 million, respectively. Fair value was estimated using the Monte Carlo simulation model, which considers the probabilities of the Company’s TSR ranking at the end of each performance period, and the amount of the payout at each rank to determine the probability-weighted expected payout. The Company uses liability accounting to account for the P-Units. Compensation is recognized on a straight-line basis over a maximum period of three years from the grant date and is adjusted for changes in fair value through the vesting date.end of the performance period.
Other long-term liabilities at December 31, 2014, and 2013, included liabilitiesLiabilities for estimated P-Unit obligations at December 31, 2017 for 2017 grants and prior, included $11.5 million and $10.5 million classified as current and noncurrent, respectively, compared to $10.9 million and $12.8 million, respectively, at December 31, 2016. Current and noncurrent estimated P-Unit liabilities are included in Accrued liabilities, and Other liabilities, respectively, in the amount of Consolidated Balance Sheets.$11.6 million
In 2017, 2016 and $4.52015, the Company paid $11.4 million, respectively.
No performance-based awards$7.9 million and $2.7 million, respectively, in cash to settle P-Units that vested or settled in 2014, 2013, or 2012.
during the year.
Share Appreciation Rights – Share appreciation rights (SARs)SARs give the holder the right to receive ordinary shares at no cost to the employee, or cash at the discretion of the Committee, equal in value to the excess of the market price of a share on the date of exercise over the exercise price. All SARs granted have exercise prices equal to the market price of the underlying shares on the date of grant. SARs become exercisable in one-third annual increments over a three-year service period and expire ten years following the grant date. The Company intends to share-settle any exercises of SARs and has therefore accounted for SARs as equity awards.
Fair values of SARs granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions:
|
| | | |
| | 2013 | | 2012 |
| Expected life in years | 6.0 | | 6.0 |
| Risk-free interest rate | 1.058% | | 1.108% |
| Expected volatility | 41.11% | | 44.30% |
| Weighted-average grant-date per-share fair value | $13.91 | | $15.28 |
No SARs werehave been granted in 2014.
The Company uses the simplified method for determining the expected life of SARs because the Company does not have sufficient historical exercise data to provide a reasonable basis upon which to estimate expected term, as permitted under US GAAP.
since 2013.
SARs activity for the year ended December 31, 2014,2017, is summarized below:
|
| | | | | | | | | | | | |
| | Number of shares under SARs | | Weighted-average exercise price | | Weighted-average remaining contractual term (in years) | | Aggregate intrinsic value (in thousands) |
| Outstanding at January 1, 2014 | 1,831,695 |
| | $ | 30.45 |
| | | | |
| Exercised | (67,707 | ) | | 17.39 |
| | | | |
| Forfeited or expired | (2,718 | ) | | 35.47 |
| | | | |
| Outstanding at December 31, 2014 | 1,761,270 |
| | $ | 30.94 |
| | 5.0 | | $ | 2,451 |
|
| | | | | | | | |
| Exercisable at December 31, 2014 | 1,444,099 |
| | $ | 30.15 |
| | 4.3 | | $ | 2,451 |
|
|
| | | | | | | | | | | | |
| | Number of shares under SARs | | Weighted-average exercise price | | Weighted-average remaining contractual term (in years) | | Aggregate intrinsic value |
| | (in thousands) | | | | | | (in millions) |
| Outstanding at January 1, 2017 | 1,544 |
| | $ | 30.67 |
| | | | |
| Forfeited or expired | (515 | ) | | 29.94 |
| | | | |
| Outstanding at December 31, 2017 | 1,029 |
| | $ | 31.03 |
| | 3.0 | | $ | — |
|
| | | | | | | | |
| Exercisable at December 31, 2017 | 1,029 |
| | $ | 31.03 |
| | 3.0 | | $ | — |
|
The aggregate intrinsic value ofNo SARs were exercised in 2014, 2013,2017, 2016 and 2012 was $0.9 million, $0.5 million, and $0.4 million, respectively.
2015.
Share Options – Share options granted to employees in 2017 become exercisable and cliff vest at the end of a four-year vesting period at a price generally equal to the market price of the Company’s common shares on the date of grant. The remaining share options became exercisable in one-third or one-quarter annual increments over a three or four-year- year service period at a price generally equal to the market price of the Company’s common shares on the date of grant. The Company has not granted share options since 2008. Unexercised options expire seven to ten years after the grant date.
Fair values of Share options granted were determined using the Black-Scholes option pricing model with the following weighted-average assumptions:
|
| | | |
| | February 22, 2017 |
| Expected life in years | 5.5 |
|
| Risk-free interest rate | 1.987 | % |
| Expected volatility | 40.551 | % |
| Weighted average grant date per share fair value | $ | 7.04 |
|
Share option activity for the year ended December 31, 2014,2017, is summarized below:
|
| | | | | | | | | | | | |
| | Number of shares under option | | Weighted-average exercise price | | Weighted-average remaining contractual term (in years) | | Aggregate intrinsic value (in thousands) |
| Outstanding at January 1, 2014 | 384,643 |
| | $ | 24.52 |
| | | | |
| Exercised | (189,000 | ) | | 25.00 |
| | | | |
| Forfeited or expired | (10,239 | ) | | 43.85 |
| | | | |
| Outstanding at December 31, 2014 | 185,404 |
| | $ | 22.96 |
| | 2.7 | | $ | 835 |
|
| | | | | | | | |
| Exercisable at December 31, 2014 | 185,404 |
| | $ | 22.96 |
| | 2.7 | | $ | 835 |
|
|
| | | | | | | | | | | | |
| | Number of shares under option | | Weighted-average exercise price | | Weighted-average remaining contractual term (in years) | | Aggregate intrinsic value |
| | (in thousands) | | | | | | (in millions) |
| Outstanding at January 1, 2017 | 100 |
| | $ | 15.31 |
| | | | |
| Granted | 355 |
| | 17.59 |
| | | | |
| Outstanding at December 31, 2017 | 455 |
| | $ | 17.08 |
| | 5.0 | | $ | — |
|
| | | | | | | | |
| Exercisable at December 31, 2017 | 100 |
| | $ | 15.31 |
| | 0.1 | | $ | — |
|
No options were exercised in 2017, 2016 or 2015.
The aggregate intrinsic value of options exercised was $1.4 million in 2014, $2.0 million in 2013 and $0.3 million in 2012.
Award modifications – In 2014 the Company accelerated the vesting of share-based awards and extended the exercise period for vested SARs held by two retiring employees whose awards would otherwise have been forfeited upon retirement. As a result of the modifications, the Company recognized additional compensation expense in 2014 in the amount of $1.7 million, net of forfeitures, which is included in selling, general and administrative expense. The Company valued the modified SARs assuming they are to be outstanding near or until such time as they expire.
In 2012 the Company modified share-based awards held by a retiring employee and recognized additional compensation expense in the amount of $2.3 million, which is included in material charges and other operating expenses.
NOTE 910 – PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company provides defined-benefit pension, health care and life insurance benefits upon retirement for certain full-time employees. Pension benefits are provided under theThe Rowan Pension Plan, and the Restoration Plan ofThe Rowan Companies, Inc. (the “Rowan SERP”),SERP, and health care and life insurance benefits are provided under the Retiree Life & Medical Supplemental Plan of Rowan Companies, Inc.Plan.
The following table presents the changes in benefit obligations and plan assets for the years ended December 31 and the funded status and weighted-average assumptions used to determine the benefit obligation at each year end (dollars in thousands)millions):
| | | | 2014 | | 2013 | 2017 | | 2016 |
| | Pension benefits | | Other benefits | | Total | | Pension benefits | | Other benefits | | Total | Pension benefits | | Other benefits | | Total | | Pension benefits | | Other benefits | | Total |
| Projected benefit obligations: | | | | | | | | | | | | | | | | | | | | | | |
| Balance, January 1 | $ | 679,880 |
| | $ | 66,832 |
| | $ | 746,712 |
| | $ | 733,355 |
| | $ | 76,639 |
| | $ | 809,994 |
| $ | 772.1 |
| | $ | 29.9 |
| | $ | 802.0 |
| | $ | 760.0 |
| | $ | 66.7 |
| | $ | 826.7 |
|
| Interest cost | 32,680 |
| | 3,025 |
| | 35,705 |
| | 29,984 |
| | 3,006 |
| | 32,990 |
| 25.5 |
| | 0.9 |
| | 26.4 |
| | 26.3 |
| | 1.6 |
| | 27.9 |
|
| Service cost | 14,573 |
| | 1,067 |
| | 15,640 |
| | 12,309 |
| | 1,445 |
| | 13,754 |
| 12.3 |
| | 0.1 |
| | 12.4 |
| | 16.3 |
| | 0.3 |
| | 16.6 |
|
| Actuarial (gain) loss | 114,030 |
| | 6,779 |
| | 120,809 |
| | (58,907 | ) | | (10,788 | ) | | (69,695 | ) | 78.0 |
| | 5.5 |
| | 83.5 |
| | 32.8 |
| | 9.2 |
| | 42.0 |
|
| Plan amendments | 259 |
| | — |
| | 259 |
| | 3,585 |
| | — |
| | 3,585 |
| — |
| | — |
| | — |
| | — |
| | (39.9 | ) | | (39.9 | ) |
| Plan settlements | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | (16.4 | ) | | (16.4 | ) | | (2.5 | ) | | (2.6 | ) | | (5.1 | ) |
| Plan curtailments | | — |
| | — |
| | — |
| | (1.0 | ) | | — |
| | (1.0 | ) |
| Exchange rate changes | (1,215 | ) | | — |
| | (1,215 | ) | | — |
| | — |
| | — |
| 0.3 |
| | — |
| | 0.3 |
| | 0.1 |
| | — |
| | 0.1 |
|
| Benefits paid | (32,254 | ) | | (4,125 | ) | | (36,379 | ) | | (40,446 | ) | | (3,470 | ) | | (43,916 | ) | (52.4 | ) | | (2.0 | ) | | (54.4 | ) | | (59.9 | ) | | (5.4 | ) | | (65.3 | ) |
| Balance, December 31 | 807,953 |
| | 73,578 |
| | 881,531 |
| | 679,880 |
| | 66,832 |
| | 746,712 |
| 835.8 |
| | 18.0 |
| | 853.8 |
| | 772.1 |
| | 29.9 |
| | 802.0 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Plan assets: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Fair value, January 1 | 542,449 |
| | — |
| | 542,449 |
| | 494,432 |
| | — |
| | 494,432 |
| 544.6 |
| | — |
| | 544.6 |
| | 550.7 |
| | — |
| | 550.7 |
|
| Actual return | 27,596 |
| | — |
| | 27,596 |
| | 69,603 |
| | — |
| | 69,603 |
| 88.0 |
| | — |
| | 88.0 |
| | 33.8 |
| | — |
| | 33.8 |
|
| Employer contributions | 54,834 |
| | — |
| | 54,834 |
| | 18,860 |
| | — |
| | 18,860 |
| 29.3 |
| | — |
| | 29.3 |
| | 22.5 |
| | — |
| | 22.5 |
|
| Plan settlements | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | (2.5 | ) | | — |
| | (2.5 | ) |
| Exchange rate changes | (665 | ) | | — |
| | (665 | ) | | — |
| | — |
| | — |
| 0.2 |
| | — |
| | 0.2 |
| | — |
| | — |
| | — |
|
| Benefits paid | (32,254 | ) | | — |
| | (32,254 | ) | | (40,446 | ) | | — |
| | (40,446 | ) | (52.4 | ) | | — |
| | (52.4 | ) | | (59.9 | ) | | — |
| | (59.9 | ) |
| Fair value, December 31 | 591,960 |
| | — |
| | 591,960 |
| | 542,449 |
| | — |
| | 542,449 |
| 609.7 |
| | — |
| | 609.7 |
| | 544.6 |
| | — |
| | 544.6 |
|
| Net benefit liabilities | $ | (215,993 | ) | | $ | (73,578 | ) | | $ | (289,571 | ) | | $ | (137,431 | ) | | $ | (66,832 | ) | | $ | (204,263 | ) | $ | (226.1 | ) | | $ | (18.0 | ) | | $ | (244.1 | ) | | $ | (227.5 | ) | | $ | (29.9 | ) | | $ | (257.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Amounts recognized in Consolidated Balance Sheet: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Accrued liabilities | $ | (21,839 | ) | | $ | (4,380 | ) | | $ | (26,219 | ) | | $ | (45,599 | ) | | $ | (4,060 | ) | | $ | (49,659 | ) | $ | (24.5 | ) | | $ | (2.5 | ) | | $ | (27.0 | ) | | $ | (29.7 | ) | | $ | (2.4 | ) | | $ | (32.1 | ) |
| Other liabilities (long-term) | (194,154 | ) | | (69,198 | ) | | (263,352 | ) | | (91,832 | ) | | (62,772 | ) | | (154,604 | ) | (201.6 | ) | | (15.5 | ) | | (217.1 | ) | | (197.8 | ) | | (27.5 | ) | | (225.3 | ) |
| Net benefit liabilities | $ | (215,993 | ) | | $ | (73,578 | ) | | $ | (289,571 | ) | | $ | (137,431 | ) | | $ | (66,832 | ) | | $ | (204,263 | ) | $ | (226.1 | ) | | $ | (18.0 | ) | | $ | (244.1 | ) | | $ | (227.5 | ) | | $ | (29.9 | ) | | $ | (257.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated contributions in excess of (less than) net periodic benefit cost | $ | 124,248 |
| | $ | (75,522 | ) | | $ | 48,726 |
| | $ | 90,708 |
| | $ | (75,825 | ) | | $ | 14,883 |
| $ | 120.2 |
| | $ | (39.1 | ) | | $ | 81.1 |
| | $ | 109.4 |
| | $ | (63.3 | ) | | $ | 46.1 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| Amounts not yet reflected in net periodic benefit cost: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Actuarial (loss) gain | (360,753 | ) | | 1,944 |
| | (358,809 | ) | | (252,794 | ) | | 8,961 |
| | (243,833 | ) | (358.1 | ) | | (6.3 | ) | | (364.4 | ) | | (353.8 | ) | | (7.3 | ) | | (361.1 | ) |
| Prior service credit | 20,512 |
| | — |
| | 20,512 |
| | 24,655 |
| | 32 |
| | 24,687 |
| 11.8 |
| | 27.4 |
| | 39.2 |
| | 16.9 |
| | 40.7 |
| | 57.6 |
|
| Total accumulated other comprehensive loss | (340,241 | ) | | 1,944 |
| | (338,297 | ) | | (228,139 | ) | | 8,993 |
| | (219,146 | ) | |
| Total accumulated other comprehensive income (loss) | | (346.3 | ) | | 21.1 |
| | (325.2 | ) | | (336.9 | ) | | 33.4 |
| | (303.5 | ) |
| Net benefit liabilities | $ | (215,993 | ) | | $ | (73,578 | ) | | $ | (289,571 | ) | | $ | (137,431 | ) | | $ | (66,832 | ) | | $ | (204,263 | ) | $ | (226.1 | ) | | $ | (18.0 | ) | | $ | (244.1 | ) | | $ | (227.5 | ) | | $ | (29.9 | ) | | $ | (257.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Weighted-average assumptions: | | | |
| | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
| | |
|
| Discount rate | 4.12 | % | | 3.95 | % | | |
| | 4.58 | % | | 4.74 | % | | |
| 3.68 | % | | 3.52 | % | | |
| | 4.29 | % | | 3.94 | % | | |
|
| Rate of compensation increase | 4.15 | % | | |
| | |
| | 4.15 | % | | |
| | |
| 4.28 | % | | |
| | |
| | 4.14 | % | | |
| | |
|
The projected benefit obligations for pension benefits in the preceding table reflect the actuarial present value of benefits accrued based on services rendered to date and include the estimated effect of future salary increases. The accumulated benefit obligations, which are presented below for all plans in the aggregate at December 31, are based on services rendered to date, but exclude the effect of future salary increases (in thousands)millions):
|
| | | | | | | |
| | 2014 | | 2013 |
| Accumulated benefit obligation | $ | 801,749 |
| | $ | 676,320 |
|
|
| | | | | | | |
| | 2017 | | 2016 |
| Accumulated benefit obligation | $ | 830.8 |
| | $ | 764.8 |
|
On November 27, 2017, the Company purchased annuities to cover post-65 retiree medical benefits for current retirees as of the purchase date. The annuity purchase settled post-65 medical benefits (i.e., Health Reimbursement Account, or “HRA”, amounts) for affected participants, with the insurer taking responsibility for all benefit payments on and after January 1, 2019. The Company retained the obligation for 2018 benefit payments. The Company determined that this annuity purchase resulted in a full settlement of the post-65 medical obligation and as a result the entirety of the annuity purchase was treated as a settlement and resulted in a settlement loss of $5.8 million, calculated as of December 31, 2017.
On August 10, 2016, the Company communicated changes to the participants in its postretirement benefits plan, which was previously frozen to new entrants in 2008. Based on these changes, effective as of January 1, 2017, eligible participants now receive a health reimbursement account that provides a fixed dollar benefit per year. The impact of these changes to the plan and related, as of August 10, 2016, are presented in the table below (in millions):
|
| | | | | | | | | | | |
| | Liability increase (decrease) | | Accumulated other comprehensive income (loss) | | Deferred tax liability increase (decrease) |
| Plan change benefit | $ | (39.9 | ) | | $ | 25.9 |
| | $ | 14.0 |
|
| Remeasurement loss | 5.2 |
| | (3.4 | ) | | (1.8 | ) |
| Actuarial loss | 5.2 |
| | (3.3 | ) | | (1.9 | ) |
| Total | $ | (29.5 | ) | | $ | 19.2 |
| | $ | 10.3 |
|
During 2016, the Rowan SERP had a one-time settlement charge recognized in net periodic pension costs under US GAAP of $0.5 million as of December 31, 2016, attributable to lump sum payments during 2016 which exceeded the sum of the service cost and interest cost, the threshold that requires recognition of a settlement loss.
In 2016, the Norwegian Onshore and Offshore pension plans both experienced plan curtailments. Across Rowan Norway Limited, which employs participants of both the Onshore and Offshore pension plans, there was an employment reduction resulting in an approximate 50% reduction in active participants of the plans in early 2017. Since Rowan provided affected employees redundancy letters in November 2016, the curtailment was recognized effective December 31, 2016. The Company recognized a $0.4 million curtailment gain in net periodic pension costs for 2016.
During 2015, the Company amended the eligibility requirement with respect to the Retiree Medical Plan to exclude any participant that was previously eligible and was under the age of 50 as of January 1, 2016. The effect of the change was to reduce the projected benefit obligation by $7.2 million, which was net of an estimated $4.4 million payment to be made in early 2016 to the affected participants. The actual payment made in 2016 was $2.6 million and the Company recognized a related $0.1 million settlement loss.
Effective January 1, 2016, the Company changed its estimate of the service and interest cost components of net periodic benefit costs for its significant defined benefit pension and other postretirement benefit plans. Previously, the Company estimated the service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation. The new estimate utilizes a full yield curve approach in the estimation of these components by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The new estimate provides a more precise measurement of service and interest costs by improving the correlation between projected benefit cash flows and their corresponding spot rates. While the benefit obligation measured under this approach is unchanged, more granular application of the spot rates reduced the service and interest cost for fiscal 2016.
Each of the Company’s pension plans has a benefit obligation that exceeds the fair value of plan assets.
The Company estimates the following amounts, which are classified in accumulated other comprehensive loss, a component of shareholders’ equity, will be recognized as net periodic benefit cost in 20152018 (in thousands)millions):
| | | | Pension benefits | | Other retirement benefits | | Total | Pension benefits | | Other retirement benefits | | Total |
| Actuarial (loss) gain | $ | (25,587 | ) | | $ | — |
| | $ | (25,587 | ) | $ | (35.6 | ) | | $ | (0.7 | ) | | $ | (36.3 | ) |
| Prior service credit | 4,519 |
| | — |
| | 4,519 |
| 5.0 |
| | 13.3 |
| | 18.3 |
|
| Total amortization | $ | (21,068 | ) | | $ | — |
| | $ | (21,068 | ) | $ | (30.6 | ) | | $ | 12.6 |
| | $ | (18.0 | ) |
Cumulative gains and losses in excess of 10% of the greater of projected benefit obligation or market-related value of plan assets are amortized over the expected average remaining service of the current active membership.
In 2012Each unrecognized prior service cost base is amortized on a pensionstraight line basis over the average remaining service period of participants expected to receive a benefit and who are active at the date of the plan that was assumedamendment. If all or almost all of the plan’s participants offered a benefit by the Company in connection withplan amendment are inactive, the saleamortization is based on their average remaining life expectancy instead of its former manufacturing operations made lump sum payments totaling $19.0 million, which exceeded the threshold that required the recognition of a settlement loss in the amount of $8.7 million. Such amount is classified within material charges and other operating expenses on the Consolidated Statements of Income.average remaining service.
The components of net periodic pension cost and the weighted-average assumptions used to determine net cost were as follows (dollars in thousands)millions):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Service cost | $ | 14,573 |
| | $ | 12,309 |
| | $ | 10,742 |
|
| Interest cost | 32,680 |
| | 29,984 |
| | 30,613 |
|
| Expected return on plan assets | (41,592 | ) | | (38,305 | ) | | (36,958 | ) |
| Recognized actuarial loss | 19,861 |
| | 28,454 |
| | 25,504 |
|
| Amortization of prior service cost | (4,507 | ) | | (4,736 | ) | | (4,647 | ) |
| Settlement loss recognized | — |
| | — |
| | 8,742 |
|
| Net periodic pension cost | $ | 21,015 |
| | $ | 27,706 |
| | $ | 33,996 |
|
| Less: Discontinued operations | — |
| | — |
| | (402 | ) |
| Continuing operations | $ | 21,015 |
| | $ | 27,706 |
| | $ | 33,594 |
|
| | | | | | |
| Discount rate | 4.83 | % | | 4.16 | % | | 4.58 | % |
| Expected return on plan assets | 8.00 | % | | 8.00 | % | | 8.00 | % |
| Rate of compensation increase | 4.15 | % | | 4.15 | % | | 4.15 | % |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Service cost | $ | 12.3 |
| | $ | 16.3 |
| | $ | 18.3 |
|
| Interest cost | 25.5 |
| | 26.3 |
| | 31.9 |
|
| Expected return on plan assets | (37.7 | ) | | (39.6 | ) | | (41.6 | ) |
| Recognized actuarial loss | 23.3 |
| | 21.0 |
| | 25.7 |
|
| Amortization of prior service cost | (5.1 | ) | | (5.0 | ) | | (4.5 | ) |
| Curtailment gain recognized | — |
| | (0.4 | ) | | — |
|
| Settlement loss recognized | — |
| | 0.5 |
| | — |
|
| Net periodic pension cost | $ | 18.3 |
| | $ | 19.1 |
| | $ | 29.8 |
|
| | | | | | |
| Discount rate | 4.29 | % | | 4.53 | % | | 3.97 | % |
| Expected return on plan assets | 7.13 | % | | 7.28 | % | | 7.45 | % |
| Rate of compensation increase | 4.14 | % | | 4.14 | % | | 4.15 | % |
The components of net periodic cost of other postretirement benefits and the weighted average discount rate used to determine net cost were as follows (dollars in thousands)millions):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Service cost | $ | 1,067 |
| | $ | 1,445 |
| | $ | 1,660 |
|
| Interest cost | 3,025 |
| | 3,006 |
| | 3,501 |
|
| Amortization of transition obligation | — |
| | — |
| | 475 |
|
| Amortization of prior service cost | (32 | ) | | (147 | ) | | (147 | ) |
| Amortization of net (gain) loss | (237 | ) | | — |
| | — |
|
| Net periodic cost of other postretirement benefits | $ | 3,823 |
| | $ | 4,304 |
| | $ | 5,489 |
|
| | | | | | |
| Discount rate | 4.74 | % | | 3.89 | % | | 4.46 | % |
The assumed health care cost trend rates used to measure the expected cost of retirement health benefits was 7.0% for 2015, gradually decreasing to 4.5% for 2026 and thereafter. A one-percentage-point change in the assumed health care cost trend rates would change the reported amounts as follows (in thousands):
|
| | | | | | | |
| | One-percentage-point change |
| | Increase | | Decrease |
| Effect on total service and interest cost components for the year | $ | 269 |
| | $ | (229 | ) |
| Effect on postretirement benefit obligation at year-end | 3,570 |
| | (3,097 | ) |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Service cost | $ | 0.1 |
| | $ | 0.3 |
| | $ | 1.3 |
|
| Interest cost | 0.9 |
| | 1.6 |
| | 2.9 |
|
| Amortization of prior service credit | (13.3 | ) | | (6.4 | ) | | — |
|
| Amortization of net (gain) loss | 0.7 |
| | 0.3 |
| | — |
|
| Settlement loss | 5.8 |
| | 0.1 |
| | — |
|
| Net periodic cost of other postretirement benefits | $ | (5.8 | ) | | $ | (4.1 | ) | | $ | 4.2 |
|
| | | | | | |
| Discount rate | 3.91 | % | | 4.18 | % | | 3.95 | % |
The pension plans’ investment objectives for fund assets are: to achieve over the life of the plans a return equal to the plans’ expected investment return or the inflation rate plus 3%, whichever is greater; to invest assets in a manner such that contributions are minimized and future assets are available to fund liabilities; to maintain liquidity sufficient to pay benefits when due; and to diversify among asset classes so that assets earn a reasonable return with an acceptable level of risk. The plans employ several active managers with proven long-term records in their specific investment discipline.
Target allocations among asset categories and the fair values of each category of plan assets as of December 31, 20142017 and 2013,2016, classified by level within the US GAAP fair value hierarchy is presented below. The plans will periodically reallocate assets in accordance with the allocation targets, after giving consideration to the expected level of cash required to pay current benefits and plan expenses (dollars in thousands)millions):
| | | | Target range | | Total | | Quoted prices in active markets for identical assets (Level 1) | | Significant observable inputs (Level 2) | | Significant unobservable inputs (Level 3) | Target range | | Total | | Quoted prices in active markets for identical assets (Level 1) | | Significant observable inputs (Level 2) | | Significant unobservable inputs (Level 3) |
| December 31, 2014: | | | | | | | | | | |
| December 31, 2017: | | | | | | | | | | |
| Equities: | 53% to 69% | | | | | | | | | 53% to 69% | | | | | | | | |
| U.S. large cap | 22% to 28% | | $ | 159,541 |
| | $ | — |
| | $ | 159,541 |
| | $ | — |
| 22% to 28% | | $ | 158.2 |
| | $ | — |
| | $ | 158.2 |
| | $ | — |
|
| U.S. small cap | 4% to 10% | | 38,106 |
| | — |
| | 38,106 |
| | — |
| 4% to 10% | | 45.3 |
| | — |
| | 45.3 |
| | — |
|
| International all cap | 21% to 29% | | 135,947 |
| | — |
| | 135,947 |
| | — |
| 21% to 29% | | 156.2 |
| | — |
| | 156.2 |
| | — |
|
| International small cap | 2% to 8% | | 29,736 |
| | — |
| | 29,736 |
| | — |
| 2% to 8% | | 36.3 |
| | — |
| | 36.3 |
| | — |
|
| Real estate equities | 0% to 13% | | 45,758 |
| | — |
| | 45,758 |
| | — |
| 0% to 13% | | 50.6 |
| | — |
| | 50.6 |
| | — |
|
| Fixed income: | 25% to 35% | |
|
| | |
| | |
| | |
| 25% to 35% | |
|
| | |
| | |
| | |
|
| Cash and equivalents | 0% to 10% | | 8,416 |
| | 1 |
| | 8,415 |
| | — |
| 0% to 10% | | 6.2 |
| | — |
| | 6.2 |
| | — |
|
| Aggregate | 9% to 19% | | 85,412 |
| | — |
| | 85,412 |
| | — |
| 9% to 19% | | 74.9 |
| | — |
| | 74.9 |
| | — |
|
| Core plus | 9% to 19% | | 86,325 |
| | 86,325 |
| | — |
| | — |
| 9% to 19% | | 78.1 |
| | 78.1 |
| | — |
| | — |
|
| Group annuity contracts | | 2,719 |
| | — |
| | 2,719 |
| | — |
| | 3.9 |
| | — |
| | 3.9 |
| | — |
|
| Total | | | $ | 591,960 |
| | $ | 86,326 |
| | $ | 505,634 |
| | $ | — |
| | | $ | 609.7 |
| | $ | 78.1 |
| | $ | 531.6 |
| | $ | — |
|
| | | | | | | | | | | | | | | | | |
| December 31, 2013: | | | |
| | |
| | |
| | |
| |
| December 31, 2016: | | | | |
| | |
| | |
| | |
|
| Equities: | 53% to 69% | | |
| | |
| | |
| | |
| 53% to 69% | | |
| | |
| | |
| | |
|
| U.S. large cap | 22% to 28% | | $ | 125,061 |
| | $ | — |
| | $ | 125,061 |
| | $ | — |
| 22% to 28% | | $ | 141.6 |
| | $ | — |
| | $ | 141.6 |
| | $ | — |
|
| U.S. small cap | 4% to 10% | | 36,330 |
| | — |
| | 36,330 |
| | — |
| 4% to 10% | | 41.5 |
| | — |
| | 41.5 |
| | — |
|
| International all cap | 21% to 29% | | 118,530 |
| | — |
| | 118,530 |
| | — |
| 21% to 29% | | 134.4 |
| | — |
| | 134.4 |
| | — |
|
| International small cap | 2% to 8% | | 31,270 |
| | — |
| | 31,270 |
| | — |
| 2% to 8% | | 27.4 |
| | — |
| | 27.4 |
| | — |
|
| Real estate equities | 0% to 13% | | 40,055 |
| | — |
| | 40,055 |
| | — |
| 0% to 13% | | 47.1 |
| | — |
| | 47.1 |
| | — |
|
| Fixed income: | 25% to 35% | |
|
| | |
| | |
| | |
| 25% to 35% | |
|
| | |
| | |
| | |
|
| Cash and equivalents | 0% to 10% | | 59,301 |
| | — |
| | 59,301 |
| | — |
| 0% to 10% | | 4.6 |
| | — |
| | 4.6 |
| | — |
|
| Aggregate | 9% to 19% | | 66,074 |
| | — |
| | 66,074 |
| | — |
| 9% to 19% | | 72.4 |
| | — |
| | 72.4 |
| | — |
|
| Core plus | 9% to 19% | | 65,828 |
| | 65,828 |
| | — |
| | — |
| 9% to 19% | | 73.0 |
| | 73.0 |
| | — |
| | — |
|
| Group annuity contracts | | | 2.6 |
| | — |
| | 2.6 |
| | — |
|
| Total | | | $ | 542,449 |
| | $ | 65,828 |
| | $ | 476,621 |
| | $ | — |
| | | $ | 544.6 |
| | $ | 73.0 |
| | $ | 471.6 |
| | $ | — |
|
Assets in the U.S. equities category include investments in common and preferred stocks (and equivalents such as American Depository Receipts and convertible bonds) and may be held through separate accounts, commingled funds or an institutional mutual fund. Assets in the international equities category include investments in a broad range of international equity securities, including both developed and emerging markets, and may be held through a commingled or institutional mutual fund. The real estate category includes investments in pooled and commingled funds whose objectives are diversified equity investments in income-producing properties. Each real estate fund is intended to provide broad exposure to the real estate market by property type, geographic location and size and may invest internationally. Securities in both the aggregate and core plus fixed income categories include U.S. government, corporate, mortgage- and asset-backed securities and Yankee bonds, and both categories target an average credit rating of “A” or better at all times. Individual securities in the aggregate fixed income category must be investment grade or above at the time of purchase, whereas securities in the core plus category may have a rating of “B” or above. Additionally, the core plus category may invest in non-U.S. securities. Assets in the aggregate and core plus fixed income categories are held primarily through a commingled fund and an institutional mutual fund, respectively. Group annuity contracts are invested in a combination of equity, real estate, bond and other investments in connection with a pension plan in Norway.
The following is a description of the valuation methodologies used for the pension plan assets at December 31, 20142017, and 2013:2016:
Fair values of all U.S. equity securities, the international all cap equity securities and aggregate fixed income securities categorized as Level 2 were held in commingled funds which were valued daily based on a net asset value.
Fair value of international small cap equity securities categorized as Level 2 were held in a limited partnership fund which was valued monthly based on a net asset value.
The real estate categorized as Level 2 was held in two accounts (a commingled fund and a limited partnership). The assets in the commingled fund were valued monthly based on a net asset value and the assets in the limited partnership were valued quarterly based on a net asset value.
Cash and equivalents categorized as Level 2 were valued at cost, which approximates fair value.
Fair value of mutual fund investments in core plus fixed income securities categorized as Level 1 were based on quoted market prices which represent the net asset value of shares held.
To develop the expected long-term rate of return on assets assumption, the Company considered the current level of expected returns on risk-free investments (primarily government bonds), the historical level of the risk premium associated with the plans’ other asset classes and the expectations for future returns of each asset class. The expected return for each asset class was then weighted based upon the current asset allocation to develop the expected long-term rate of return on assets assumption for the plans, which was reduced at 7.45%to 6.70% at December 31, 2014,2017, from 8%7.15% at December 31, 2013.2016.
The Company's estimates for its net benefit expense (income) are partially based on the expected return on pension plan assets. The Company uses a market-related value of plan assets to determine the expected return on pension plan assets. In determining the market-related value of plan assets, differences between expected and actual asset returns are deferred and recognized over two years. If the Company used the fair value of its plan assets instead of the market-related value of plan assets in determining the expected return on pension plan assets, its net benefit expense would have been $2.7 million higher for the year ended December 31, 2017.
The Company bases its determination of the asset return component of pension expense on a market-related valuation of assets, which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a two-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the fair value of assets. Since the market-related value of assets recognizes gains or losses over a two-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded. As of January 1, 2018, cumulative asset gains of approximately $31.7 million remained to be recognized in the calculation of the market-related value of assets.
The Company currently expects to contribute approximately $2225 million to its pension plans in 20152018 and to directly pay other postretirement benefits of approximately $42 million, net of estimated Medicare subsidy receipts..
Estimated future annual benefit payments from plan assets are presented below. Such amounts are based on existing benefit formulas and include the effect of future service (in thousands)millions):
|
| | | | | | | |
| | Pension benefits | | Other postretirement benefits |
| Year ended December 31, | | | |
| 2015 | $ | 66,000 |
| | $ | 4,690 |
|
| 2016 | 40,420 |
| | 4,940 |
|
| 2017 | 40,950 |
| | 5,130 |
|
| 2018 | 42,520 |
| | 5,370 |
|
| 2019 | 43,730 |
| | 5,640 |
|
| 2020 through 2023 | 236,460 |
| | 25,220 |
|
|
| | | | | | | |
| | Pension benefits | | Other postretirement benefits |
| Year ended December 31, | | | |
| 2018 | $ | 99.4 |
| | $ | 2.5 |
|
| 2019 | 46.5 |
| | 1.6 |
|
| 2020 | 47.5 |
| | 1.4 |
|
| 2021 | 48.0 |
| | 1.3 |
|
| 2022 | 48.8 |
| | 1.2 |
|
| 2023 through 2027 | 244.1 |
| | 5.7 |
|
The Company sponsors defined contribution plans covering substantially all employees. Employer contributions to such plans are expensed as incurred and totaled $12.5 million in 2017, $19.016.7 million in 2014,2016 and $14.320.0 million in 2013 and $9.6 million in 2012.2015.
NOTE 1011 – SHAREHOLDERS’ EQUITY
Reclassifications from Accumulated Other Comprehensive Loss
The following table sets forth the significant amounts reclassified out of each component of accumulated other comprehensive loss and their effect on net income (loss) for the period (in thousands)millions):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Amounts recognized as a component of net periodic pension and other postretirement benefit cost: | | | | | |
| Amortization of net loss | $ | (19,624 | ) | | $ | (28,454 | ) | | $ | (34,245 | ) |
| Amortization of transition obligation | — |
| | — |
| | (474 | ) |
| Amortization of prior service credit | 4,539 |
| | 4,882 |
| | 4,794 |
|
| Total before tax | (15,085 | ) | | (23,572 | ) | | (29,925 | ) |
| Tax (expense) benefit | 5,261 |
| | 8,250 |
| | 10,474 |
|
| Total reclassifications for the period, net of tax | $ | (9,824 | ) | | $ | (15,322 | ) | | $ | (19,451 | ) |
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| Amounts recognized as a component of net periodic pension and other postretirement benefit cost: | | | | | |
| Amortization of net loss | $ | (29.8 | ) | | $ | (21.9 | ) | | $ | (25.7 | ) |
| Amortization of prior service credit | 18.4 |
| | 10.7 |
| | 4.5 |
|
| Total before income taxes | (11.4 | ) | | (11.2 | ) | | (21.2 | ) |
| Income tax benefit | — |
| | 3.8 |
| | 7.4 |
|
| Total reclassifications for the period, net of income taxes | $ | (11.4 | ) | | $ | (7.4 | ) | | $ | (13.8 | ) |
Cash Dividends
PriorUnder English law, a public company may only declare dividends and make other distributions to 2014,shareholders (such as a share buyback) if the company has sufficient distributable reserves and meets certain net asset requirements. If the Company does not have sufficient distributable reserves or cannot meet the net asset requirements, the Company may be limited in its ability to timely pay dividends and effect other distributions to its shareholders.
In January 2016, the Company announced that it had not paid a regulardiscontinued its quarterly dividend.
During 2015, the Board approved quarterly cash dividend since 2008. On April 25, 2014, the Board of Directors approved a quarterly cash dividenddividends of $0.10 per Class A ordinary share, which were paid on May 20, 2014, to shareholders of record at the close of business on May 5, 2014. On July 31, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on August 26, 2014, to shareholders of record at the close of business on August 11, 2014. On October 30, 2014, the Board of Directors approved a quarterly cash dividend of $0.10 per share, paid on November 25, 2014, to shareholders of record at the close of business on November 11, 2014. On January 29, 2015, the Board of Directors approved a quarterly cash dividend of $0.10 per share payable on March 3, May 26, August 25, and November 23, 2015, to shareholders of record at the close of business on February 9, 2015.May 12, August 11, and November 9, 2015, respectively.
In September 2014 we completed a capital reduction under U.K. law, which increased the Company's distributable reserves and will provide the Company with greater flexibility to increase shareholder return in the form of dividends and share repurchases. The capital reduction was authorized by our Board of Directors and approved by our shareholders at a general meeting in August 2014. The capital reduction was achieved through the issuance and cancellation of $2.0 billion of newly created Class C shares pursuant to a customary, court approved process in the U.K.
The capital reduction shares had no substantive economic rights, provided no voting rights and otherwise provided extremely limited rights (e.g., no right to receive any dividends or other distributions). The capital reduction shares were cancelled in September 2014, and $2.0 billion of shareholders’ equity of Rowan plc that was not previously available for distribution under U.K. law became available for dividends, future distributions or share repurchases, as may be determined by our Board of Directors, subject to compliance with applicable rules and limitations under U.K. law.
The capital reduction did not involve any distribution or repayment of capital, nor did it have an impact on the underlying net assets of the Company. There was no net impact on our shareholders’ equity as a result of the capital reduction.
Share Repurchase Program
The ability to make share repurchases is subject to the discretion of the Board of Directors and the limitations set forth in the Companies Act, which generally provide that share repurchases may only be made out of distributable reserves. In addition, U.K. law also generally prohibits a company from repurchasing its own shares through “off-market purchases” without the prior approval of shareholders, which approval lasts for a maximum period of five years. Prior to and in connection with the redomestication, the Company obtained approval to purchase its own shares. To effect such repurchases, the Company entered into a purchase agreement with a specified dealer in July 2012, pursuant to which the Company may purchase up to a maximum of 50,000,000 shares over a five-year period, subject to an annual cap of 10 percent of the shares outstanding at the beginning of each applicable year. Subject to Board approval, share repurchases may be commenced or suspended from time to time without prior notice and, in accordance with the shareholder approval and U.K. law, any shares repurchased by the Company will be canceled. The authority to repurchase shares terminates in April 2017 unless otherwise reapproved by the Company’s shareholders prior to that time. U.K. law prohibits the Company from purchasing its shares in the open market because they are not traded on a recognized investment exchange in the U.K.
NOTE 1112 – INCOME TAXES
RCI, our predecessorRowan plc, the parent company, wasis domiciled in the U.S.U.K. and subject to a statutory rate of 35%. As a result of our redomestication to the U.K., we becameis subject to the U.K. statutory rate of 24% for the financial year beginning April 1, 2012; 23% for the financial year beginning April 1, 2013; and 21% for the financial year beginning Aprilperiod January 1 2014. The rate reduces tothrough March 31, 2015; 20% for the financial year beginning April 1, 2015. We have2015; and 19% for the financial year beginning April 1, 2017. On September 15, 2016, the U.K. enacted tax law to reduce the tax rate to 17% for the financial year beginning April 1, 2020. The computed our statutory tax rate for 20142017 is using a weighted average U.K. rate of 21.5%19.25%.
The U.S. Tax Act requires complex computations to be performed that were not previously provided in U.S. tax law. As such, additional work is necessary as these computations require the preparation and analysis of information not previously relevant or regularly produced. Although the Company has not completed its accounting of the U.S. Tax Act, reasonable estimates were used in accordance with the SEC Staff Accounting Bulletin No. 118. The reasonable estimates made primarily include a one-time transition tax of $34.1 million, a tax on non-U.S. subsidiaries of $38.3 million, and additional tax due to the remeasurement of the U.S. deferred tax assets and liabilities for the tax rate change of $56.7 million, totaling $129.1 million. These charges do not materially impact the financials as they are fully offset by unbenefited net operating losses utilized of $72.4 million and adjustments to the valuation allowance of $56.7 million related to the deferred tax asset and liability remeasurement. The Company must finalize, in addition to other factors, the amount of the post-1986 non-U.S. earnings and profits, the amount of the U.S. tax on non-U.S. subsidiaries, and the earnings held in cash and other assets. As the Company completes its analysis of the U.S. Tax Act including finalizing the calculations and interpreting existing regulatory guidance, there may be adjustments to the provisional amounts. The provisional estimates will be finalized within one year from the date of enactment.
The significant components of income taxes attributable to continuing operations are presented below (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Current: | | | | | | | | | | |
| U.S. | $ | (62,332 | ) | | $ | (38,025 | ) | | $ | (69,934 | ) | $ | (14.9 | ) | | $ | 10.0 |
| | $ | 7.4 |
|
| Non - U.S. | 53,494 |
| | 31,932 |
| | 23,931 |
| 16.8 |
| | 32.9 |
| | 50.8 |
|
| State | 151 |
| | (5,141 | ) | | 100 |
| — |
| | — |
| | 0.1 |
|
| Current expense (benefit) | (8,687 | ) | | (11,234 | ) | | (45,903 | ) | 1.9 |
| | 42.9 |
| | 58.3 |
|
| Deferred: | | | | | | | | | | |
| U.S. | (140,305 | ) | | 20,827 |
| | 45,794 |
| (1.2 | ) | | (20.9 | ) | | (6.3 | ) |
| Non - U.S. | (1,740 | ) | | (930 | ) | | (19,720 | ) | 25.9 |
| | (17.0 | ) | | 12.4 |
|
| Deferred provision (benefit) | (142,045 | ) | | 19,897 |
| | 26,074 |
| 24.7 |
| | (37.9 | ) | | 6.1 |
|
| Total provision (benefit) | $ | (150,732 | ) | | $ | 8,663 |
| | $ | (19,829 | ) | $ | 26.6 |
| | $ | 5.0 |
| | $ | 64.4 |
|
DifferencesThe reconciliation of differences between ourthe Company's provision for income taxes and the amount determined by applying the U.K. statutory rate to income before income taxes are set forth below (dollars in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| U.K. Statutory rate | 21.5 | % | | 23.25 | % | | 24.5 | % | |
| U.K. statutory rate | | 19.25 | % | | 20.00 | % | | 20.25 | % |
| Tax at statutory rate | $ | (57,965 | ) | | $ | 60,738 |
| | $ | 44,950 |
| $ | 19.1 |
| | $ | 65.1 |
| | $ | 31.9 |
|
| Increase (decrease) due to: | |
| | |
| | |
| |
| | |
| | |
|
| Capitalized interest transactions | (20,145 | ) | | (11,317 | ) | | (39,204 | ) | — |
| | — |
| | (5.7 | ) |
| Tax audit settlements | 10,449 |
| | — |
| | — |
| |
| Foreign rate differential | 38,216 |
| | (27,078 | ) | | (27,591 | ) | (39.5 | ) | | (92.7 | ) | | (30.0 | ) |
| Deferred intercompany gain/loss | (86,635 | ) | | (9,062 | ) | | (8,749 | ) | — |
| | (20.1 | ) | | (33.8 | ) |
| Foreign asset basis difference | | (38.1 | ) | | 405.9 |
| | — |
|
| Luxembourg restructuring operating loss | | — |
| | (1,180.2 | ) | | — |
|
| Change in valuation allowance | (3,570 | ) | | 8,381 |
| | 2,806 |
| (29.4 | ) | | 814.7 |
| | 106.0 |
|
| Prior period adjustments | 7,511 |
| | (9,837 | ) | | 4,482 |
| 3.6 |
| | (4.1 | ) | | (6.9 | ) |
| Unrecognized tax benefits | (35,791 | ) | | 17,544 |
| | 2,463 |
| (24.1 | ) | | 7.1 |
| | 9.7 |
|
| Excess compensation | 657 |
| | 1,022 |
| | 1,432 |
| |
| Foreign taxes of subsidiaries for which U.S. federal income taxes have been provided | — |
| | 9,155 |
| | — |
| |
| U.S. tax on RCI non-U.S. subsidiaries | | 5.4 |
| | 6.3 |
| | — |
|
Enactment of tax reform (1) | | 129.1 |
| | — |
| | — |
|
| Termination of local country activity | | — |
| | — |
| | (6.3 | ) |
| Foreign tax credits/deductions | (4,925 | ) | | (31,078 | ) | | (1,632 | ) | (0.8 | ) | | (1.5 | ) | | (2.2 | ) |
| Other, net | 1,466 |
| | 195 |
| | 1,214 |
| 1.3 |
| | 4.5 |
| | 1.7 |
|
| Total provision (benefit) | $ | (150,732 | ) | | $ | 8,663 |
| | $ | (19,829 | ) | $ | 26.6 |
| | $ | 5.0 |
| | $ | 64.4 |
|
| | | | | | | |
| (1) 2017 includes the U.S. tax rate reduction, one-time transition tax, and U.S. tax on applicable non-U.S. subsidiaries earnings. The impact of these items are fully offset in the Change in valuation allowance above. | | (1) 2017 includes the U.S. tax rate reduction, one-time transition tax, and U.S. tax on applicable non-U.S. subsidiaries earnings. The impact of these items are fully offset in the Change in valuation allowance above. |
In 2016, organizational restructuring resulted in a Luxembourg net operating loss of $4,534 million resulting in a deferred tax asset of $1,180 million with an offsetting deferred tax liability for book over tax asset basis difference of $409 million and a valuation allowance of $747 million for the net deferred tax asset that is not expected to be realized.
Temporary differences and carryforwards which gave rise to deferred tax assets and liabilities at December 31 were as follows (in thousands)millions):
| | | | 2014 | | 2013 | | | | | |
| | Current | | Noncurrent | | Current | | Noncurrent | 2017 | | 2016 |
| Deferred tax assets: | | | | | | | | | | |
| Accrued employee benefit plan costs | $ | 30,912 |
| | $ | 118,096 |
| | $ | 27,295 |
| | $ | 76,619 |
| $ | 46.2 |
| | $ | 81.1 |
|
| U.S. net operating loss | — |
| | 46,675 |
| | — |
| | 28,486 |
| 39.3 |
| | 111.2 |
|
| U.K. net operating loss | — |
| | 2,708 |
| | — |
| | 8,280 |
| 2.4 |
| | 2.8 |
|
| Norway net operating loss | — |
| | — |
| | — |
| | 13,949 |
| |
| Trinidad net operating loss | — |
| | 13,034 |
| | — |
| | — |
| 5.9 |
| | 6.5 |
|
| Luxembourg net operating loss | | 1,163.2 |
| | 1,180.2 |
|
| Suriname net operating loss | | 3.9 |
| | 3.9 |
|
| Other NOLs and tax credit carryforwards | 819 |
| | 23,634 |
| | — |
| | — |
| 38.1 |
| | 36.8 |
|
| Other | 888 |
| | 28,069 |
| | 700 |
| | 28,744 |
| 16.3 |
| | 31.2 |
|
| Total deferred tax assets | 32,619 |
| | 232,216 |
| | 27,995 |
| | 156,078 |
| 1,315.3 |
| | 1,453.7 |
|
| Less: valuation allowance | — |
| | (22,339 | ) | | — |
| | (25,909 | ) | (869.9 | ) | | (889.8 | ) |
| Deferred tax assets, net of valuation allowance | 32,619 |
| | 209,877 |
| | 27,995 |
| | 130,169 |
| 445.4 |
| | 563.9 |
|
| | | | | | | | | | | |
| Deferred tax liabilities: | |
| | |
| | |
| | |
| |
| | |
|
| Property, plant and equipment | — |
| | 369,095 |
| | — |
| | 514,612 |
| |
| Property and equipment | | 412.8 |
| | 712.8 |
|
| Other | 5,134 |
| | 51,764 |
| | 5,858 |
| | 45,212 |
| 11.9 |
| | 12.3 |
|
| Total deferred tax liabilities | 5,134 |
| | 420,859 |
| | 5,858 |
| | 559,824 |
| 424.7 |
| | 725.1 |
|
| Net deferred tax asset (liability) | $ | 27,485 |
| | $ | (210,982 | ) | | $ | 22,137 |
| | $ | (429,655 | ) | $ | 20.7 |
| | $ | (161.2 | ) |
Management continues to assess available positive and negative evidence to evaluate the existing deferred tax assets’ ability to be realized including determining if there is sufficient future taxable income. The Company records the portion of the deferred tax assets that is more likely to be realized. There have been no changes on the prior assessment regarding the ability to realize the U.S. and Luxembourg deferred tax assets and the Company has assessed the need for a valuation allowance as of December 31, 2017. The Company increased the valuation allowance on the Luxembourg deferred tax assets by $19.8 million to $766.5 million, at December 31, 2017, primarily due to lower current year earnings than expected. In 2017, the U.S. valuation allowance on U.S. deferred tax assets was decreased by $41.7 million primarily due to a decrease of provisional estimate of $56.7 million for the remeasurement to the lower U.S. corporate income tax rate, a decrease of provisional estimate of $52.1 million for current year activity, and an increase of $60.3 million for a deferred intra-entity asset transfer.
As of December 31, 2016, an additional valuation allowance of $747 million was recorded on Luxembourg deferred tax assets primarily related to net operating losses. The valuation allowance on the U.S. deferred tax assets was increased by $12 million to $132 million, primarily due to the changes in deferred tax assets related to net operating loss, interest limitations and depreciation.
The amount of the deferred tax assets considered realizable, however, could be adjusted if estimates of future taxable income during the carryforward period are reduced or increased or if negative evidence in the form of cumulative losses is no longer present, and additional weight may be given to evidence such as projections for growth. As of each reporting date, the Company’s management considers new evidence, both positive and negative, that could impact management’s view with regard to future realization of deferred tax assets.
At December 31, 2014,2017, the Company had approximately $84$306 million of net operating loss carryforwards (NOLs)NOLs in the U.S., which expire at various times between 20352034 and 2041; $492041 and which is subject to a valuation allowance as discussed in the preceding paragraphs; $49 million of NOLs in the U.S. attributable to the Company’s non-U.S. subsidiaries expiring in 2032 and which is subject to a valuation allowance of $36$49 million; $4,472 million at December 31, 2014; $13.6of non-expiring NOLs in Luxembourg of which $2,947 million is subject to a valuation allowance; $14 million of non-expiring NOLs in the U.K., of which $13.6$14 million is subject to a valuation allowance; and $52$23 million of non-expiring NOLs in Trinidad, of which $25$23 million is subject to a valuation allowance. In addition, at December 31, 2014,2017, the Company had $6$15 million of non-expiring NOLs in other foreign jurisdictions, of which $4$15 million is subject to a valuation allowance. A U.S. foreign tax credit of $29 million is intended to be carried back and does not have a valuation allowance. Due to the uncertainty of realization, the Company has a tax-effected valuation allowance as of December 31, 2017, in the amount of $870 million against the deferred tax assets for foreign tax credits, NOL carryforwards, and other deferred tax assets that may not be realizable, primarily relating to countries where the Company no longer operates or does not expect to generate sufficient future taxable income. Management has determined that no other valuation allowances were necessary at December 31, 2014,2017, as
anticipated future tax benefits relating to all recognized deferred income tax assets are expected to be fully realized when measured against a more likely than not standard.
The NOL carryforwards included unrecognized tax benefits taken in prior years. The NOLs for which a deferred tax asset is recognized for financial statement purposes in accordance with ASC 740 are presented net of these unrecognized tax benefits.
The Company has not provided deferred income taxes on certain undistributed earnings of the Company’s non-U.K. subsidiaries, including RCI’s non-U.S. subsidiaries. It is the Company’s policy and intention to permanently reinvest earnings of non-U.S. subsidiariesNo subsidiary of RCI outside the U.S. The earnings of non-U.K. subsidiaries that are not subsidiaries of RCI can be distributed to Rowan plc without the imposition of either U.K. or local country tax.
As of December 31, 2014, RCI's portion of the unremitted earnings of its non-U.S. subsidiaries was approximately $205 million. Should the non-U.S. subsidiaries of RCI makehas a distribution from these earnings, we may be subject to additional U.S. income taxes. It is not practicable to estimate the amount of deferred tax liability related to the undistributed earnings, and RCI's non-U.S. subsidiaries have no plan to distribute earnings to RCI in a manner that would cause themthose earnings to be subject to U.S., U.K., or other local country taxation.
If facts and circumstances cause a change in expectations regarding future tax consequences, the resulting tax impact could have a material effect on the Company's consolidated financial statements.
At December 31, 2014, 20132017, 2016 and 2012, we had approximately $48 million, $75 million and $58 million, respectively, of2015, the net unrecognized tax benefits attributable to continuing operations.operations was approximately $41 million, $59 million and $62 million, respectively. At December 31, 2014, $482017, $41 million would reduce the Company’s income tax provision if recognized. The Company believes it is reasonably possible that a decrease of up to $16 million may be necessary within the next twelve months.
The following table sets forth the changes in the Company’s gross unrecognized tax benefits for the years ended December 31 (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Gross unrecognized tax benefits - beginning of year | $ | 81,920 |
| | $ | 58,900 |
| | $ | 55,300 |
| $ | 120.1 |
| | $ | 65.1 |
| | $ | 54.7 |
|
| Gross increases - tax positions in prior period | 19,928 |
| | 11,021 |
| | 700 |
| 1.4 |
| | 46.2 |
| | 4.4 |
|
| Gross decreases - tax positions in prior period | (10,649 | ) | | (4,114 | ) | | — |
| (5.6 | ) | | (0.6 | ) | | (3.7 | ) |
| Gross increases - current period tax positions | 9,458 |
| | 16,674 |
| | 2,900 |
| 3.1 |
| | 10.9 |
| | 9.7 |
|
| Settlements | (37,809 | ) | | — |
| | — |
| (0.8 | ) | | (1.5 | ) | | — |
|
| Lapse of statute of limitations | (8,188 | ) | | (561 | ) | | — |
| |
| Lapse of statutes of limitation | | (16.2 | ) | | — |
| | — |
|
| Gross unrecognized tax benefit - end of year | $ | 54,660 |
| | $ | 81,920 |
| | $ | 58,900 |
| $ | 102.0 |
| | $ | 120.1 |
| | $ | 65.1 |
|
Interest and penalties relating to income taxes are included in income tax expense. At December 31, 2014, 20132017, 2016 and 2012,2015, accrued interest was $5.5$1.4 million,, $2.4 $11.8 million and $2.5$7.9 million,, respectively, and accrued penalties were $2.6$2.2 million,, $1.7 $3.1 million and $1.4$2.8 million,, respectively. Accrued interest and penalties relating to uncertain tax positions that are not actually assessed will be reversed in the year of the resolution.
InThe Company has been advised by the IRS of proposed unfavorable tax adjustments of $85 million including applicable penalties for the open tax years 2009 through 2012. The unfavorable tax adjustments primarily related to the Company recognized certainfollowing items: 2009 tax benefits recognized as a result of applying the facts of a third-party tax case to the Company’s situation. That casethat provided a more favorable tax treatment for certain foreignnon-U.S. contracts entered into in prior years. Our position was challengedyears to the Company’s situation; transfer pricing; and domestic production activity deduction. The Company has protested the proposed adjustment. However, the IRS does not agree with the Company's protest and they have submitted the proposed unfavorable tax adjustments to be reviewed by the IRS. We appealed their findingsIRS appeals group. In years subsequent to 2012, the Company has similar positions that could be subject to adjustments for the open years. The Company has provided for amounts that it believes will be ultimately payable under the proposed adjustments and reached a settlement agreement in September 2014 with respect to three of the four years under review in the amount of approximately $36 million, including interest, which we collected in October 2014. A remaining year continues to be under examination. We planintends to vigorously defend our position.
its positions; however, if the Company determines the provisions for these matters to be inadequate due to new information or the Company is required to pay a significant amount of additional U.S. taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, the Company's consolidated results of operations and cash flows could be materially and adversely affected.
The Company’s U.S. federal tax returns for 2009 through 20132012 are currently under audit by the IRS. The U.S. tax years open for examination are for periods 2014 and subsequent years. Various state tax returns for 2009 and subsequent years remain open for examination. In the Company’s non-U.S. tax jurisdictions, returns for 2006 and subsequent years remain open for examination. We areThe Company is undergoing other routine tax examinations in various U.S. and non-US.non-U.S. taxing jurisdictions in which the Company has operated. These examinations cover various tax years and are in various stages of finalization. The Company believes that any income taxes ultimately assessed by any taxing authorities will not materially exceed amounts for which the Company has already provided.provided, however, if it is determined that the provisions for these matters are inadequate due to new information or that taxing authorities assess a significant amount of additional taxes and applicable penalties and interest in excess of amounts that have been provided for these matters, consolidated results of operations and cash flows could be materially and adversely affected.
The components of income (loss) from continuing operations before income taxes were as follows (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| U.S. | $ | (198,300 | ) | | $ | 163,400 |
| | $ | 9,800 |
| $ | (63.7 | ) | | $ | (180.2 | ) | | $ | (174.1 | ) |
| Non-U.S. | (71,300 | ) | | 97,800 |
| | 173,700 |
| 163.0 |
| | 505.8 |
| | 331.8 |
|
| Total | | $ | 99.3 |
| | $ | 325.6 |
| | $ | 157.7 |
|
NOTE 1213 – SEGMENT AND GEOGRAPHIC AREA INFORMATION
Prior to ARO commencing operations on October 17, 2017 (see Note 1), the Company operated in two segments: Deepwater and Jack-ups. The Company now operates in three principal operating segments: Deepwater, which consists of its drillship operations, Jack-ups, which is composed of the Company's jack-up operations and results associated with the Company's arrangements with ARO primarily under the Transition Services Agreement (direct operating costs only), Rig Management Agreement and Secondment Agreement (see Note 1 and Note 3), and ARO a company formed to own, manage and operate offshore drilling units in Saudi Arabia. These segments provide one primary service – contract drilling. The Company evaluates performance primarily based on income from operations. "Gain on sale of assets to unconsolidated subsidiary" is related to the sale of three jack-ups and related assets to ARO and is included in the Jack-ups segment (see Note 1 and Note 14). Depreciation and amortization and Selling, general and administrative expenses related to the Company's corporate function and other administrative offices have not been allocated to its operating segments for purposes of measuring segment operating income and are included in "Unallocated and other." In addition, revenue and general and administrative costs related to providing transition services to ARO are included in "Unallocated and other" (see Note 3). "Other operating items" consists of, to the extent applicable, non-cash impairment charges, gains and losses on asset sales and litigation related items. Segment results are presented below:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years ended December 31, |
| | Deepwater | | Jack-ups | | ARO | | Unallocated and other | | Reportable segments total | | Eliminations and adjustments | | Consolidated |
| | (In millions) |
| 2017 | | | | | | | | | | | | | |
| Revenue | $ | 467.9 |
| | $ | 807.5 |
| | $ | 48.6 |
| | $ | 7.4 |
| | $ | 1,331.4 |
| | $ | (48.6 | ) | | $ | 1,282.8 |
|
| Operating expenses: | | | | | | | | | | | | | |
| Direct operating costs (excluding items below) | 151.4 |
| | 533.4 |
| | 22.2 |
| | — |
| | 707.0 |
| | (22.2 | ) | | 684.8 |
|
| Depreciation and amortization | 111.6 |
| | 289.4 |
| | 12.9 |
| | 2.7 |
| | 416.6 |
| | (12.9 | ) | | 403.7 |
|
| Selling, general and administrative | — |
| | — |
| | 6.1 |
| | 104.9 |
| | 111.0 |
| | (6.1 | ) | | 104.9 |
|
| Gain on sale of assets to unconsolidated subsidiary | — |
| | (157.4 | ) | | — |
| | — |
| | (157.4 | ) | | — |
| | (157.4 | ) |
| Other operating items - expense (income) | 0.1 |
| | 9.3 |
| | (0.1 | ) | | — |
| | 9.3 |
| | 0.1 |
| | 9.4 |
|
| Equity in earnings of unconsolidated subsidiary | — |
| | — |
| | — |
| | — |
| | — |
| | 0.9 |
| | 0.9 |
|
| Income (loss) from operations | $ | 204.8 |
| | $ | 132.8 |
| | $ | 7.5 |
| | $ | (100.2 | ) | | $ | 244.9 |
| | $ | (6.6 | ) | | $ | 238.3 |
|
| | | | | | | | | | | | | | |
| 2016 | | | | | | | | | | | | | |
| Revenue | $ | 827.5 |
| | $ | 1,015.7 |
| | $ | — |
| | $ | — |
| | $ | 1,843.2 |
| | $ | — |
| | $ | 1,843.2 |
|
| Operating expenses: | | | | | | | | | | | | | |
| Direct operating costs (excluding items below) | 222.0 |
| | 556.2 |
| | — |
| | — |
| | 778.2 |
| | — |
| | 778.2 |
|
| Depreciation and amortization | 115.0 |
| | 282.6 |
| | — |
| | 5.3 |
| | 402.9 |
| | — |
| | 402.9 |
|
| Selling, general and administrative | — |
| | — |
| | — |
| | 102.1 |
| | 102.1 |
| | — |
| | 102.1 |
|
| Other operating items - expense | 0.1 |
| | 40.9 |
| | — |
| | 0.6 |
| | 41.6 |
| | — |
| | 41.6 |
|
| Income (loss) from operations | $ | 490.4 |
| | $ | 136.0 |
| | $ | — |
| | $ | (108.0 | ) | | $ | 518.4 |
| | $ | — |
| | $ | 518.4 |
|
| | | | | | | | | | | | | | |
| 2015 | | | | | | | | | | | | | |
| Revenue | $ | 747.8 |
| | $ | 1,389.2 |
| | $ | — |
| | $ | — |
| | $ | 2,137.0 |
| | $ | — |
| | $ | 2,137.0 |
|
| Operating expenses: | | | | | | | | | | | | | |
| Direct operating costs (excluding items below) | 276.6 |
| | 716.5 |
| | — |
| | — |
| | 993.1 |
| | — |
| | 993.1 |
|
| Depreciation and amortization | 94.6 |
| | 283.9 |
| | — |
| | 12.9 |
| | 391.4 |
| | — |
| | 391.4 |
|
| Selling, general and administrative | — |
| | — |
| | — |
| | 115.8 |
| | 115.8 |
| | — |
| | 115.8 |
|
| Other operating items - expense | — |
| | 328.8 |
| | — |
| | 0.8 |
| | 329.6 |
| | — |
| | 329.6 |
|
| Income (loss) from operations | $ | 376.6 |
| | $ | 60.0 |
| | $ | — |
| | $ | (129.5 | ) | | $ | 307.1 |
| | $ | — |
| | $ | 307.1 |
|
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Capital expenditures: | (In millions) |
| Deepwater | $ | 8.3 |
| | $ | 31.5 |
| | $ | 555.1 |
|
| Jack-ups | 86.4 |
| | 84.3 |
| | 128.8 |
|
| Unallocated and other | 5.9 |
| | 1.8 |
| | 39.0 |
|
| Total | $ | 100.6 |
| | $ | 117.6 |
| | $ | 722.9 |
|
A cash deposit of $7.7 million was made toward the purchase of two jack-up rigs. See Note 19 for more details on the purchase of these rigs. Not all assets are associated with specific segments. Those assets specific to segments include receivables, certain identified property, plant and equipment (including rigs), investment in unconsolidated subsidiary and note receivable from unconsolidated subsidiary. The remaining assets, such as cash and equivalents, are considered to be shared among the segments and therefore reported in Unallocated and other.
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| Total assets: | (In millions) |
| Deepwater | $ | 2,857.6 |
| | $ | 3,037.7 |
|
| Jack-ups | 4,173.7 |
| | 4,285.8 |
|
| Unallocated and other | 1,427.0 |
| | 1,352.1 |
|
| Total | $ | 8,458.3 |
| | $ | 8,675.6 |
|
The classifications of revenuesrevenue and assets among geographic areas in the tables which follow were determined based on the physical location of assets. Because the Company’s offshore drilling rigs are mobile, classifications by area are dependent on the rigs’ location at the time revenues arerevenue is earned and may vary from one period to the next.
|
| | | | | | | | | | | |
| | Years ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | (In millions) |
| Revenue: | | | | | |
| United States | $ | 510.7 |
| | $ | 852.8 |
| | $ | 704.6 |
|
| Saudi Arabia | 390.6 |
| | 363.9 |
| | 408.7 |
|
| Norway | 193.8 |
| | 312.6 |
| | 403.6 |
|
| Trinidad | 127.0 |
| | 130.4 |
| | 141.7 |
|
| United Kingdom | 58.2 |
| | 120.6 |
| | 163.0 |
|
Other (1) | 2.5 |
| | 62.9 |
| | 315.4 |
|
| Total | $ | 1,282.8 |
| | $ | 1,843.2 |
| | $ | 2,137.0 |
|
Revenues by geographic area are set forth below (in thousands):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Saudi Arabia | $ | 443,873 |
| | $ | 412,799 |
| | $ | 376,406 |
|
| United Kingdom | 288,248 |
| | 327,217 |
| | 385,174 |
|
| United States | 283,835 |
| | 240,820 |
| | 209,296 |
|
| Norway | 213,393 |
| | 168,931 |
| | 131,251 |
|
| Indonesia | 125,851 |
| | 90,027 |
| | 13,677 |
|
| Trinidad | 94,722 |
| | 101,262 |
| | 98,764 |
|
| Malaysia | 93,962 |
| | 127,216 |
| | 88,960 |
|
| Angola | 80,499 |
| | — |
| | — |
|
| Qatar | 53,522 |
| | 21,938 |
| | 26,298 |
|
| Spain (Canary Islands) | 36,956 |
| | — |
| | — |
|
| Morocco | 33,027 |
| | — |
| | — |
|
| Egypt | 32,426 |
| | 89,074 |
| | 25,435 |
|
| Namibia | 25,479 |
| | — |
| | — |
|
| Tunisia | 18,590 |
| | — |
| | — |
|
| Vietnam | — |
| | — |
| | 37,346 |
|
| Consolidated revenues | $ | 1,824,383 |
| | $ | 1,579,284 |
| | $ | 1,392,607 |
|
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | (In millions) |
| Long-lived assets: | | | |
| United States | $ | 3,065.6 |
| | $ | 3,199.5 |
|
| Saudi Arabia | 633.9 |
| | 818.4 |
|
| Norway | 862.8 |
| | 813.7 |
|
| Trinidad | 599.5 |
| | 622.0 |
|
| United Kingdom | 1,067.2 |
| | 1,229.9 |
|
Other (1) | 354.6 |
| | 376.5 |
|
| Total | $ | 6,583.6 |
| | $ | 7,060.0 |
|
| | | | |
| (1) Other represents countries in which the Company operates that individually had revenue and long-lived assets representing less than 10% of total revenue or long-lived assets. |
Long-lived assets by geographic area at December 31 are set forth below (in thousands):
|
| | | | | | | | | | | |
| | 2014 | | 2013 | | 2012 |
| Norway | $ | 1,394,994 |
| | $ | 503,308 |
| | $ | 495,518 |
|
| United States | 1,374,420 |
| | 868,147 |
| | 903,823 |
|
| Rigs under construction | 1,023,647 |
| | 1,009,382 |
| | 756,245 |
|
| Saudi Arabia | 932,714 |
| | 1,204,915 |
| | 1,103,220 |
|
| United Kingdom | 842,666 |
| | 1,336,400 |
| | 1,555,324 |
|
| Spain (Canary Islands) | 759,275 |
| | — |
| | — |
|
| Malaysia | 383,308 |
| | 386,402 |
| | 447,949 |
|
| Trinidad | 238,697 |
| | 254,671 |
| | 250,765 |
|
| Indonesia | 221,512 |
| | 251,169 |
| | 184,706 |
|
| Tunisia | 214,790 |
| | — |
| | — |
|
| Qatar | 46,156 |
| | 85,240 |
| | 153,282 |
|
| Angola | 33 |
| | — |
| | — |
|
| Netherlands | — |
| | 270,409 |
| | — |
|
| Egypt | — |
| | 215,712 |
| | 220,897 |
|
| Consolidated long-lived assets | $ | 7,432,212 |
| | $ | 6,385,755 |
| | $ | 6,071,729 |
|
NOTE 1314 – GAIN ON SALE OF ASSETS TO UNCONSOLIDATED SUBSIDIARY
On October 17, 2017, pursuant to an Asset Transfer and Contribution Agreement, as amended, with ARO, the Company agreed to sell three rigs to ARO: the JP Bussell, the Bob Keller and the Gilbert Rowe and related assets for a total cash consideration of $357.7 million. The book value of these assets was approximately $200.3 million. As a result of this sale transaction with ARO, the Company recognized a gain on the disposal of rig assets in the amount of $157.4 million in 2017. See Note 1 and Note 3 for more details of the ARO joint venture. NOTE 15 – MATERIAL CHARGES AND OTHER OPERATING EXPENSESITEMS
Operating expenses in 2014 included noncashfor 2016 include (i) non-cash asset impairment charges aggregating $574.0totaling $34.3 million including $565.7on five jack-up drilling units (see Note 7) and (ii) a $1.4 million reversal of an estimated liability for settlement of a withholding tax matter during a tax amnesty period which was related to a legal settlement for a 2014 termination of a contract for refurbishment work on the Rowan Gorilla III, as noted below in the 2015 period. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and interest. Operating expenses for 2015 include non-cash asset impairment charges totaling $329.8 million on ten jack-up drilling units (see Note 7) and an adjustment of $7.6 million to an estimated liability for the 2014 contract termination in connection with twelve of the Company's oldest jack-up drilling units and $8.3 million for a Company aircraft, which we sold later in 2014 at an immaterial loss.
Operating expenses in 2013 included a $4.5 million noncash impairment chargerefurbishment work on a dock and storage facility.
Operating expenses in 2012 included $13.8 million of legal and consulting fees incurred in connection with the Company’s redomestication, $12.0 million of repair costs for the Rowan EXL IGorilla III following its collision with a tanker,$8.7 million. A settlement agreement for this matter was signed during the third quarter of pension settlement costs in connection with lump sum pension payments to employees of the Company’s former manufacturing subsidiary,
$8.1 million of noncash asset impairment charges, and $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee.2015.
NOTE 1416 – SUPPLEMENTAL CASH FLOW INFORMATION
NoncashNon-cash investing and financing activities and other supplemental cash flow information follows (in thousands)millions):
| | | | 2014 | | 2013 | | 2012 | 2017 | | 2016 | | 2015 |
| Accrued but unpaid additions to property and equipment at December 31 | $ | 48,646 |
| | $ | 49,220 |
| | $ | 41,754 |
| $ | 21.4 |
| | $ | 21.0 |
| | $ | 32.2 |
|
| Cash interest payments in excess of interest capitalized | 78,744 |
| | 65,824 |
| | 44,579 |
| 150.2 |
| | 159.2 |
| | 143.8 |
|
| Net cash income tax payments (refunds) | 8,549 |
| | (5,929 | ) | | 13,150 |
| |
| Income tax payments (refunds), net | | 30.0 |
| | 38.1 |
| | 37.5 |
|
NOTE 1517 – GUARANTEES OF REGISTERED SECURITIES
Rowan plc and its 100%-owned subsidiary, RCI, have entered into agreements providing for, among other things, the full, unconditional and irrevocable guarantee by Rowan plc of the prompt payment, when due, of any amount owed to the holders of RCI's Senior Notes.
Notes and amounts outstanding under RCI’s Revolving Credit Facility, if any.
The condensed consolidating financial information that follows is presented on the equity method of accounting in accordance with Rule 3-10 of Regulation S-X in connection with Rowan plc’s guarantee of the Senior Notes and reflects the corporate ownership
structure as of December 31, 2014.2017. Financial information as of December 31, 2013,2016, and for the years ended December 31, 20132016 and 20122015 has been recast to reflect changes to the corporate ownership structure that occurred in 20142017 and is presented as though the structure at December 31, 2014,2017, was in place at January 1, 2012.2015.
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance SheetsStatements of Operations
Year ended December 31, 20142017
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| CURRENT ASSETS: | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | 45,909 |
| | $ | 48,580 |
| | $ | 244,665 |
| | $ | — |
| | $ | 339,154 |
|
| Receivables - trade and other | 26 |
| | 4,317 |
| | 540,861 |
| | — |
| | 545,204 |
|
| Other current assets | 424 |
| | 47,986 |
| | 8,328 |
| | — |
| | 56,738 |
|
| Assets of discontinued operations | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current assets | 46,359 |
| | 100,883 |
| | 793,854 |
| | — |
| | 941,096 |
|
| | | | | | | | | | |
| Property, plant and equipment - gross | — |
| | 610,063 |
| | 8,190,119 |
| | — |
| | 8,800,182 |
|
| Less accumulated depreciation and amortization | — |
| | 271,293 |
| | 1,096,677 |
| | — |
| | 1,367,970 |
|
| Property, plant and equipment - net | — |
| | 338,770 |
| | 7,093,442 |
| | — |
| | 7,432,212 |
|
| | | | | | | | | | |
| Investments in subsidiaries | 4,624,874 |
| | 5,863,509 |
| | — |
| | (10,488,383 | ) | | — |
|
| Due from affiliates | 36,586 |
| | 1,412,860 |
| | 71,867 |
| | (1,521,313 | ) | | — |
|
| Other assets | — |
| | 18,103 |
| | 19,781 |
| | — |
| | 37,884 |
|
| | $ | 4,707,819 |
| | $ | 7,734,125 |
| | $ | 7,978,944 |
| | $ | (12,009,696 | ) | | $ | 8,411,192 |
|
| | | | | | | | | | |
| CURRENT LIABILITIES: | |
| | |
| | |
| | |
| | |
|
| Accounts payable - trade | $ | 912 |
| | $ | 8,576 |
| | $ | 93,285 |
| | $ | — |
| | $ | 102,773 |
|
| Deferred revenues | — |
| | — |
| | 36,189 |
| | — |
| | 36,189 |
|
| Accrued liabilities | 400 |
| | 100,167 |
| | 93,692 |
| | — |
| | 194,259 |
|
| Liabilities of discontinued operations | — |
| | — |
| | — |
| | — |
| | — |
|
| Total current liabilities | 1,312 |
| | 108,743 |
| | 223,166 |
| | — |
| | 333,221 |
|
| | | | | | | | | | |
| Long-term debt | — |
| | 2,807,324 |
| | — |
| | — |
| | 2,807,324 |
|
| Due to affiliates | 9,282 |
| | 45,457 |
| | 1,466,574 |
| | (1,521,313 | ) | | — |
|
| Other liabilities | 5,826 |
| | 312,575 |
| | 49,865 |
| | — |
| | 368,266 |
|
| Deferred income taxes - net | — |
| | 507,281 |
| | 167,094 |
| | (463,393 | ) | | 210,982 |
|
| Shareholders' equity | 4,691,399 |
| | 3,952,745 |
| | 6,072,245 |
| | (10,024,990 | ) | | 4,691,399 |
|
| | $ | 4,707,819 |
| | $ | 7,734,125 |
| | $ | 7,978,944 |
| | $ | (12,009,696 | ) | | $ | 8,411,192 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUE | $ | — |
| | $ | 48.7 |
| | $ | 1,283.2 |
| | $ | (49.1 | ) | | $ | 1,282.8 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 0.5 |
| | 727.3 |
| | (43.0 | ) | | 684.8 |
|
| Depreciation and amortization | — |
| | 18.3 |
| | 385.4 |
| | — |
| | 403.7 |
|
| Selling, general and administrative | 29.2 |
| | 0.5 |
| | 81.3 |
| | (6.1 | ) | | 104.9 |
|
| Gain on sale of assets to unconsolidated subsidiary | — |
| | — |
| | (157.4 | ) | | — |
| | (157.4 | ) |
| Loss on disposals of property and equipment | — |
| | 1.7 |
| | 7.7 |
| | — |
| | 9.4 |
|
| Total costs and expenses | 29.2 |
| | 21.0 |
| | 1,044.3 |
| | (49.1 | ) | | 1,045.4 |
|
| | | | | | | | | | |
| Equity in earnings of unconsolidated subsidiary | — |
| | — |
| | 0.9 |
| | — |
| | 0.9 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (29.2 | ) | | 27.7 |
| | 239.8 |
| | — |
| | 238.3 |
|
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense | — |
| | (155.8 | ) | | (0.5 | ) | | 0.6 |
| | (155.7 | ) |
| Interest income | — |
| | 3.6 |
| | 12.4 |
| | (0.6 | ) | | 15.4 |
|
| Gain on extinguishment of debt | — |
| | 1.7 |
| | — |
| | — |
| | 1.7 |
|
| Other - net | 20.4 |
| | (20.4 | ) | | (0.4 | ) | | — |
| | (0.4 | ) |
| Total other income (expense) - net | 20.4 |
| | (170.9 | ) | | 11.5 |
| | — |
| | (139.0 | ) |
| | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | (8.8 | ) | | (143.2 | ) | | 251.3 |
| | — |
| | 99.3 |
|
| Provision (benefit) for income taxes | — |
| | (330.1 | ) | | 34.8 |
| | 321.9 |
| | 26.6 |
|
| Equity in earnings of consolidated subsidiaries, net of tax | 81.5 |
| | 151.4 |
| | — |
| | (232.9 | ) | | — |
|
| | | | | | | | | | |
| NET INCOME | $ | 72.7 |
| | $ | 338.3 |
| | $ | 216.5 |
| | $ | (554.8 | ) | | $ | 72.7 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance SheetsStatements of Operations
Year ended December 31, 20132016
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| CURRENT ASSETS: | | | | | | | | | |
| Cash and cash equivalents | $ | 64,292 |
| | $ | 92,116 |
| | $ | 936,436 |
| | $ | — |
| | $ | 1,092,844 |
|
| Receivables - trade and other | 58 |
| | 10,254 |
| | 334,234 |
| | — |
| | 344,546 |
|
| Other current assets | 289 |
| | 43,612 |
| | 23,774 |
| | — |
| | 67,675 |
|
| Assets of discontinued operations | — |
| | 23,813 |
| | — |
| | — |
| | 23,813 |
|
| Total current assets | 64,639 |
| | 169,795 |
| | 1,294,444 |
| | — |
| | 1,528,878 |
|
| | | | | | | | | | |
| Property, plant and equipment - gross | — |
| | 593,606 |
| | 7,604,109 |
| | — |
| | 8,197,715 |
|
| Less accumulated depreciation and amortization | — |
| | 243,666 |
| | 1,568,294 |
| | — |
| | 1,811,960 |
|
| Property, plant and equipment - net | — |
| | 349,940 |
| | 6,035,815 |
| | — |
| | 6,385,755 |
|
| | | | | | | | | | |
| Investments in subsidiaries | 4,860,492 |
| | 5,292,282 |
| | — |
| | (10,152,774 | ) | | — |
|
| Due from affiliates | 136 |
| | 1,491,831 |
| | 231,164 |
| | (1,723,131 | ) | | — |
|
| Other assets | — |
| | 60,343 |
| | 785 |
| | — |
| | 61,128 |
|
| | $ | 4,925,267 |
| | $ | 7,364,191 |
| | $ | 7,562,208 |
| | $ | (11,875,905 | ) | | $ | 7,975,761 |
|
| | | | | | | | | | |
| CURRENT LIABILITIES: | |
| | |
| | |
| | |
| | |
|
| Accounts payable - trade | $ | 1,359 |
| | $ | 13,409 |
| | $ | 109,208 |
| | $ | — |
| | $ | 123,976 |
|
| Deferred revenues | — |
| | — |
| | 54,515 |
| | — |
| | 54,515 |
|
| Accrued liabilities | — |
| | 101,478 |
| | 54,493 |
| | — |
| | 155,971 |
|
| Liabilities of discontinued operations | — |
| | 20,122 |
| | — |
| | — |
| | 20,122 |
|
| Total current liabilities | 1,359 |
| | 135,009 |
| | 218,216 |
| | — |
| | 354,584 |
|
| | | | | | | | | | |
| Long-term debt | — |
| | 2,008,700 |
| | — |
| | — |
| | 2,008,700 |
|
| Due to affiliates | 22,012 |
| | 226,847 |
| | 1,474,272 |
| | (1,723,131 | ) | | — |
|
| Other liabilities | 8,135 |
| | 236,307 |
| | 44,619 |
| | — |
| | 289,061 |
|
| Deferred income taxes - net | — |
| | 574,828 |
| | 320,532 |
| | (465,705 | ) | | 429,655 |
|
| Shareholders' equity | 4,893,761 |
| | 4,182,500 |
| | 5,504,569 |
| | (9,687,069 | ) | | 4,893,761 |
|
| | $ | 4,925,267 |
| | $ | 7,364,191 |
| | $ | 7,562,208 |
| | $ | (11,875,905 | ) | | $ | 7,975,761 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUE | $ | — |
| | $ | 40.4 |
| | $ | 1,836.9 |
| | $ | (34.1 | ) | | $ | 1,843.2 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 12.2 |
| | 795.1 |
| | (29.1 | ) | | 778.2 |
|
| Depreciation and amortization | — |
| | 19.2 |
| | 382.7 |
| | 1.0 |
| | 402.9 |
|
| Selling, general and administrative | 28.5 |
| | 5.4 |
| | 74.2 |
| | (6.0 | ) | | 102.1 |
|
| Loss on disposals of property and equipment | — |
| | 0.9 |
| | 7.8 |
| | — |
| | 8.7 |
|
| Material charges and other operating items | — |
| | — |
| | 32.9 |
| | — |
| | 32.9 |
|
| Total costs and expenses | 28.5 |
| | 37.7 |
| | 1,292.7 |
| | (34.1 | ) | | 1,324.8 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (28.5 | ) | | 2.7 |
| | 544.2 |
| | — |
| | 518.4 |
|
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense | — |
| | (155.5 | ) | | (4.1 | ) | | 4.1 |
| | (155.5 | ) |
| Interest income | — |
| | 5.1 |
| | 2.8 |
| | (4.1 | ) | | 3.8 |
|
| Loss on extinguishment of debt | — |
| | (31.2 | ) | | — |
| | — |
| | (31.2 | ) |
| Other - net | 21.2 |
| | (21.2 | ) | | (9.9 | ) | | — |
| | (9.9 | ) |
| Total other income (expense) - net | 21.2 |
| | (202.8 | ) | | (11.2 | ) | | — |
| | (192.8 | ) |
| | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | (7.3 | ) | | (200.1 | ) | | 533.0 |
| | — |
| | 325.6 |
|
| Provision (benefit) for income taxes | — |
| | 46.9 |
| | (6.7 | ) | | (35.2 | ) | | 5.0 |
|
| Equity in earnings (losses) of consolidated subsidiaries, net of tax | 327.9 |
| | (17.2 | ) | | — |
| | (310.7 | ) | | — |
|
| | | | | | | | | | |
| NET INCOME (LOSS) | $ | 320.6 |
| | $ | (264.2 | ) | | $ | 539.7 |
| | $ | (275.5 | ) | | $ | 320.6 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Income Statements
Year ended December 31, 2014
(in thousands)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUES | $ | — |
| | $ | 63,811 |
| | $ | 1,824,623 |
| | $ | (64,051 | ) | | $ | 1,824,383 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 3,699 |
| | 1,048,235 |
| | (60,594 | ) | | 991,340 |
|
| Depreciation and amortization | — |
| | 13,767 |
| | 307,693 |
| | 1,181 |
| | 322,641 |
|
| Selling, general and administrative | 26,337 |
| | 17 |
| | 104,118 |
| | (4,638 | ) | | 125,834 |
|
| Loss (gain) on disposals of property and equipment | — |
| | (4,986 | ) | | 3,208 |
| | — |
| | (1,778 | ) |
| Litigation settlement | — |
| | — |
| | (20,875 | ) | | — |
| | (20,875 | ) |
| Material charges and other operating expenses | — |
| | 12,191 |
| | 561,759 |
| | — |
| | 573,950 |
|
| Total costs and expenses | 26,337 |
| | 24,688 |
| | 2,004,138 |
| | (64,051 | ) | | 1,991,112 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (26,337 | ) | | 39,123 |
| | (179,515 | ) | | — |
| | (166,729 | ) |
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense, net of interest capitalized | — |
| | (103,934 | ) | | (3,102 | ) | | 3,102 |
| | (103,934 | ) |
| Interest income | 340 |
| | 3,558 |
| | 1,065 |
| | (3,102 | ) | | 1,861 |
|
| Dividends | — |
| | — |
| | — |
| | — |
| | — |
|
| Other - net | 22,402 |
| | (22,291 | ) | | (916 | ) | | — |
| | (805 | ) |
| Total other income (expense) - net | 22,742 |
| | (122,667 | ) | | (2,953 | ) | | — |
| | (102,878 | ) |
| | | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (3,595 | ) | | (83,544 | ) | | (182,468 | ) | | — |
| | (269,607 | ) |
Provision (benefit) for income taxes
| — |
| | (116,790 | ) | | (36,255 | ) | | 2,313 |
| | (150,732 | ) |
| | | | | | | | | | |
| NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (3,595 | ) | | 33,246 |
| | (146,213 | ) | | (2,313 | ) | | (118,875 | ) |
| | | | | | | | | | |
| DISCONTINUED OPERATIONS, NET OF TAX | — |
| | 4,023 |
| | — |
| | — |
| | 4,023 |
|
| | | | | | | | | | |
| EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX | (111,257 | ) | | (142,289 | ) | | — |
| | 253,546 |
| | — |
|
| | | | | | | | | | |
| NET INCOME | $ | (114,852 | ) | | $ | (105,020 | ) | | $ | (146,213 | ) | | $ | 251,233 |
| | $ | (114,852 | ) |
Rowan Companies plc and Subsidiaries
Condensed Consolidating Income StatementsOperations
Year ended December 31, 20132015
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUES | $ | — |
| | $ | 114,673 |
| | $ | 1,573,111 |
| | $ | (108,500 | ) | | $ | 1,579,284 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 11,421 |
| | 957,972 |
| | (108,500 | ) | | 860,893 |
|
| Depreciation and amortization | — |
| | 39,658 |
| | 231,350 |
| | — |
| | 271,008 |
|
| Selling, general and administrative | 28,456 |
| | 3,119 |
| | 99,798 |
| | — |
| | 131,373 |
|
| Loss (gain) on disposals of property and equipment | — |
| | 130 |
| | (20,249 | ) | | — |
| | (20,119 | ) |
| Material charges and other operating expenses | — |
| | — |
| | 4,453 |
| | — |
| | 4,453 |
|
| Total costs and expenses | 28,456 |
| | 54,328 |
| | 1,273,324 |
| | (108,500 | ) | | 1,247,608 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (28,456 | ) | | 60,345 |
| | 299,787 |
| | — |
| | 331,676 |
|
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense, net of interest capitalized | — |
| | (69,794 | ) | | (213 | ) | | 213 |
| | (69,794 | ) |
| Interest income | 210 |
| | 528 |
| | 1,053 |
| | (213 | ) | | 1,578 |
|
| Loss on debt extinguishment | — |
| | — |
| | — |
| | — |
| | — |
|
| Other - net | 9,997 |
| | (9,915 | ) | | (2,303 | ) | | — |
| | (2,221 | ) |
| Total other income (expense) - net | 10,207 |
| | (79,181 | ) | | (1,463 | ) | | — |
| | (70,437 | ) |
| | | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (18,249 | ) | | (18,836 | ) | | 298,324 |
| | — |
| | 261,239 |
|
| Provision (benefit) for income taxes | — |
| | (21,757 | ) | | 54,865 |
| | (24,445 | ) | | 8,663 |
|
| | | | | | | | | | |
| NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (18,249 | ) | | 2,921 |
| | 243,459 |
| | 24,445 |
| | 252,576 |
|
| | | | | | | | | | |
| DISCONTINUED OPERATIONS, NET OF TAX | — |
| | — |
| | — |
| | — |
| | — |
|
| | | | | | | | | | |
| EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX | 270,825 |
| | 114,805 |
| | — |
| | (385,630 | ) | | — |
|
| | | | | | | | | | |
| NET INCOME | $ | 252,576 |
| | $ | 117,726 |
| | $ | 243,459 |
| | $ | (361,185 | ) | | $ | 252,576 |
|
Rowan Companies plc and Subsidiaries |
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUE | $ | — |
| | $ | 60.0 |
| | $ | 2,133.4 |
| | $ | (56.4 | ) | | $ | 2,137.0 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 15.0 |
| | 1,028.5 |
| | (50.4 | ) | | 993.1 |
|
| Depreciation and amortization | — |
| | 19.5 |
| | 370.4 |
| | 1.5 |
| | 391.4 |
|
| Selling, general and administrative | 26.2 |
| | 5.4 |
| | 91.7 |
| | (7.5 | ) | | 115.8 |
|
| (Gain) loss on disposals of property and equipment | — |
| | 0.9 |
| | (8.6 | ) | | — |
| | (7.7 | ) |
| Gain on litigation settlement | — |
| | — |
| | — |
| | — |
| | — |
|
| Material charges and other operating items | — |
| | — |
| | 337.3 |
| | — |
| | 337.3 |
|
| Total costs and expenses | 26.2 |
| | 40.8 |
| | 1,819.3 |
| | (56.4 | ) | | 1,829.9 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (26.2 | ) | | 19.2 |
| | 314.1 |
| | — |
| | 307.1 |
|
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense, net of interest capitalized | — |
| | (145.3 | ) | | (22.8 | ) | | 22.8 |
| | (145.3 | ) |
| Interest income | 0.8 |
| | 22.1 |
| | 1.0 |
| | (22.8 | ) | | 1.1 |
|
| Loss on extinguishment of debt | — |
| | (1.5 | ) | | — |
| | — |
| | (1.5 | ) |
| Other - net | 22.3 |
| | (22.0 | ) | | (4.0 | ) | | — |
| | (3.7 | ) |
| Total other income (expense) - net | 23.1 |
| | (146.7 | ) | | (25.8 | ) | | — |
| | (149.4 | ) |
| | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | (3.1 | ) | | (127.5 | ) | | 288.3 |
| | — |
| | 157.7 |
|
| Provision for income taxes | — |
| | 32.9 |
| | 48.6 |
| | (17.1 | ) | | 64.4 |
|
| Equity in earnings (losses) of consolidated subsidiaries, net of tax | 96.4 |
| | (128.5 | ) | | — |
| | 32.1 |
| | — |
|
| | | | | | | | | | |
| NET INCOME (LOSS) | $ | 93.3 |
| | $ | (288.9 | ) | | $ | 239.7 |
| | $ | 49.2 |
| | $ | 93.3 |
|
Condensed Consolidating Income Statements
Year ended December 31, 2012
(in thousands)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| REVENUES | $ | — |
| | $ | 133,346 |
| | $ | 1,362,955 |
| | $ | (103,694 | ) | | $ | 1,392,607 |
|
| | | | | | | | | | |
| COSTS AND EXPENSES: | |
| | |
| | |
| | |
| | |
|
| Direct operating costs (excluding items below) | — |
| | 35,057 |
| | 820,810 |
| | (103,694 | ) | | 752,173 |
|
| Depreciation and amortization | — |
| | 50,377 |
| | 197,523 |
| | — |
| | 247,900 |
|
| Selling, general and administrative | 17,508 |
| | 14,686 |
| | 67,518 |
| | — |
| | 99,712 |
|
| Loss (gain) on disposals of property and equipment | — |
| | (572 | ) | | (1,930 | ) | | — |
| | (2,502 | ) |
| Litigation settlement | — |
| | (4,700 | ) | | — |
| | — |
| | (4,700 | ) |
| Material charges and other operating expenses | 13,835 |
| | 19,176 |
| | 11,961 |
| | — |
| | 44,972 |
|
| Total costs and expenses | 31,343 |
| | 114,024 |
| | 1,095,882 |
| | (103,694 | ) | | 1,137,555 |
|
| | | | | | | | | | |
| INCOME (LOSS) FROM OPERATIONS | (31,343 | ) | | 19,322 |
| | 267,073 |
| | — |
| | 255,052 |
|
| | | | | | | | | | |
| OTHER INCOME (EXPENSE): | |
| | |
| | |
| | |
| | |
|
| Interest expense, net of interest capitalized | — |
| | (50,513 | ) | | (279 | ) | | 75 |
| | (50,717 | ) |
| Interest income | 74 |
| | 362 |
| | 384 |
| | (75 | ) | | 745 |
|
| Loss on debt extinguishment | — |
| | (21,603 | ) | | (620 | ) | | — |
| | (22,223 | ) |
| Other - net | 4,920 |
| | (5,065 | ) | | 758 |
| | — |
| | 613 |
|
| Total other income (expense) - net | 4,994 |
| | (76,819 | ) | | 243 |
| | — |
| | (71,582 | ) |
| | | | | | | | | | |
| INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES | (26,349 | ) | | (57,497 | ) | | 267,316 |
| | — |
| | 183,470 |
|
| Provision (benefit) for income taxes | — |
| | (87,065 | ) | | 59,010 |
| | 8,226 |
| | (19,829 | ) |
| | | | | | | | | | |
| NET INCOME (LOSS) FROM CONTINUING OPERATIONS | (26,349 | ) | | 29,568 |
| | 208,306 |
| | (8,226 | ) | | 203,299 |
|
| | | | | | | | | | |
| DISCONTINUED OPERATIONS, NET OF TAX | — |
| | (22,697 | ) | | — |
| | — |
| | (22,697 | ) |
| | | | | | | | | | |
| EQUITY IN EARNINGS OF SUBSIDIARIES, NET OF TAX | 206,951 |
| | 124,677 |
| | — |
| | (331,628 | ) | | — |
|
| | | | | | | | | | |
| NET INCOME | $ | 180,602 |
| | $ | 131,548 |
| | $ | 208,306 |
| | $ | (339,854 | ) | | $ | 180,602 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 20142017
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET LOSS | $ | (114,852 | ) | | $ | (105,020 | ) | | $ | (146,213 | ) | | $ | 251,233 |
| | $ | (114,852 | ) |
| | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME (LOSS): | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes | (87,293 | ) | | (87,293 | ) | | — |
| | 87,293 |
| | (87,293 | ) |
| Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes | 9,824 |
| | 9,824 |
| | — |
| | (9,824 | ) | | 9,824 |
|
| | | | | | | | — |
| | |
| | (77,469 | ) | | (77,469 | ) | | — |
| | 77,469 |
| | (77,469 | ) |
| | | | | | | | | | |
| COMPREHENSIVE LOSS | $ | (192,321 | ) | | $ | (182,489 | ) | | $ | (146,213 | ) | | $ | 328,702 |
| | $ | (192,321 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET INCOME | $ | 72.7 |
| | $ | 338.3 |
| | $ | 216.5 |
| | $ | (554.8 | ) | | $ | 72.7 |
|
| | | | | | | | | | |
| OTHER COMPREHENSIVE LOSS: | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income (loss), net of income taxes | (33.3 | ) | | (33.3 | ) | | — |
| | 33.3 |
| | (33.3 | ) |
| Net reclassification adjustment for amounts recognized in net income as a component of net periodic benefit cost, net of income taxes | 11.4 |
| | 11.4 |
| | — |
| | (11.4 | ) | | 11.4 |
|
| | | | | | | | — |
| | |
| | (21.9 | ) | | (21.9 | ) | | — |
| | 21.9 |
| | (21.9 | ) |
| | | | | | | | | | |
| COMPREHENSIVE INCOME | $ | 50.8 |
| | $ | 316.4 |
| | $ | 216.5 |
| | $ | (532.9 | ) | | $ | 50.8 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 20132016
(in thousands)
In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET INCOME | $ | 252,576 |
| | $ | 117,726 |
| | $ | 243,459 |
| | $ | (361,185 | ) | | $ | 252,576 |
|
| | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes | 63,315 |
| | 63,315 |
| | — |
| | (63,315 | ) | | 63,315 |
|
| Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes | 15,322 |
| | 15,322 |
| | — |
| | (15,322 | ) | | 15,322 |
|
| | | | | | | | | | |
| | 78,637 |
| | 78,637 |
| | — |
| | (78,637 | ) | | 78,637 |
|
| | | | | | | | | | |
| COMPREHENSIVE INCOME | $ | 331,213 |
| | $ | 196,363 |
| | $ | 243,459 |
| | $ | (439,822 | ) | | $ | 331,213 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET INCOME (LOSS) | $ | 320.6 |
| | $ | (264.2 | ) | | $ | 539.7 |
| | $ | (275.5 | ) | | $ | 320.6 |
|
| | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income (loss), net of income taxes | (5.1 | ) | | (5.1 | ) | | — |
| | 5.1 |
| | (5.1 | ) |
| Net reclassification adjustment for amounts recognized in net income (loss) as a component of net periodic benefit cost, net of income taxes | 7.4 |
| | 7.4 |
| | — |
| | (7.4 | ) | | 7.4 |
|
| | | | | | | | | | |
| | 2.3 |
| | 2.3 |
| | — |
| | (2.3 | ) | | 2.3 |
|
| | | | | | | | | | |
| COMPREHENSIVE INCOME (LOSS) | $ | 322.9 |
| | $ | (261.9 | ) | | $ | 539.7 |
| | $ | (277.8 | ) | | $ | 322.9 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Comprehensive Income (Loss)
Year ended December 31, 20122015
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET INCOME | $ | 180,602 |
| | $ | 131,548 |
| | $ | 208,306 |
| | $ | (339,854 | ) | | $ | 180,602 |
|
| | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income, net of income taxes | (14,862 | ) | | (14,862 | ) | | — |
| | 14,862 |
| | (14,862 | ) |
| Net reclassification adjustments for amount recognized in net income as a component of net periodic benefit cost, net of income taxes | 19,451 |
| | 19,451 |
| | — |
| | (19,451 | ) | | 19,451 |
|
| | | | | | | | | | |
| | 4,589 |
| | 4,589 |
| | — |
| | (4,589 | ) | | 4,589 |
|
| | | | | | | | | | |
| COMPREHENSIVE INCOME | $ | 185,191 |
| | $ | 136,137 |
| | $ | 208,306 |
| | $ | (344,443 | ) | | $ | 185,191 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET INCOME (LOSS) | $ | 93.3 |
| | $ | (288.9 | ) | | $ | 239.7 |
| | $ | 49.2 |
| | $ | 93.3 |
|
| | | | | | | | | | |
| OTHER COMPREHENSIVE INCOME: | |
| | |
| | |
| | |
| | |
|
| Net changes in pension and other postretirement plan assets and benefit obligations recognized in other comprehensive income (loss), net of income taxes | 7.0 |
| | 7.0 |
| | — |
| | (7.0 | ) | | 7.0 |
|
| Net reclassification adjustment for amounts recognized in net income (loss) as a component of net periodic benefit cost, net of income taxes | 13.8 |
| | 13.8 |
| | — |
| | (13.8 | ) | | 13.8 |
|
| | | | | | | | | | |
| | 20.8 |
| | 20.8 |
| | — |
| | (20.8 | ) | | 20.8 |
|
| | | | | | | | | | |
| COMPREHENSIVE INCOME (LOSS) | $ | 114.1 |
| | $ | (268.1 | ) | | $ | 239.7 |
| | $ | 28.4 |
| | $ | 114.1 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2017
(In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| CURRENT ASSETS: | |
| | |
| | |
| | |
| | |
|
| Cash and cash equivalents | $ | 0.2 |
| | $ | 206.3 |
| | $ | 1,125.6 |
| | $ | — |
| | $ | 1,332.1 |
|
| Receivables - trade and other | — |
| | 1.2 |
| | 211.6 |
| | — |
| | 212.8 |
|
| Prepaid expenses and other current assets | 0.3 |
| | 10.7 |
| | 4.5 |
| | — |
| | 15.5 |
|
| Total current assets | 0.5 |
| | 218.2 |
| | 1,341.7 |
| | — |
| | 1,560.4 |
|
| | | | | | | | | | |
| Property and equipment - gross | — |
| | 241.9 |
| | 8,592.0 |
| | — |
| | 8,833.9 |
|
| Less accumulated depreciation and amortization | — |
| | 121.4 |
| | 2,159.8 |
| | — |
| | 2,281.2 |
|
| Property and equipment - net | — |
| | 120.5 |
| | 6,432.2 |
| | — |
| | 6,552.7 |
|
| | | | | | | | | | |
| Investments in consolidated subsidiaries | 5,401.1 |
| | 6,253.5 |
| | — |
| | (11,654.6 | ) | | — |
|
| Due from affiliates | 0.2 |
| | 680.0 |
| | 11.5 |
| | (691.7 | ) | | — |
|
| Long-term note receivable from unconsolidated subsidiary | — |
| | — |
| | 270.2 |
| | — |
| | 270.2 |
|
| Investment in unconsolidated subsidiary | — |
| | — |
| | 30.9 |
| | — |
| | 30.9 |
|
| Other assets | — |
| | 5.2 |
| | 7.6 |
| | 31.3 |
| | 44.1 |
|
| | $ | 5,401.8 |
| | $ | 7,277.4 |
| | $ | 8,094.1 |
| | $ | (12,315.0 | ) | | $ | 8,458.3 |
|
| | | | | | | | | | |
| CURRENT LIABILITIES: | |
| | |
| | |
| | |
| | |
|
| Accounts payable - trade | $ | 0.7 |
| | $ | 12.9 |
| | $ | 83.6 |
| | $ | — |
| | $ | 97.2 |
|
| Deferred revenue | — |
| | — |
| | 1.1 |
| | — |
| | 1.1 |
|
| Accrued liabilities | 0.1 |
| | 95.6 |
| | 63.4 |
| | — |
| | 159.1 |
|
| Total current liabilities | 0.8 |
| | 108.5 |
| | 148.1 |
| | — |
| | 257.4 |
|
| | | | | | | | | | |
| Long-term debt, less current portion | — |
| | 2,510.3 |
| | — |
| | — |
| | 2,510.3 |
|
| Due to affiliates | 11.2 |
| | 11.4 |
| | 669.1 |
| | (691.7 | ) | | — |
|
| Other liabilities | 3.8 |
| | 261.2 |
| | 28.6 |
| | — |
| | 293.6 |
|
| Deferred income taxes - net | (0.1 | ) | | 182.7 |
| | 10.9 |
| | (182.6 | ) | | 10.9 |
|
| Shareholders' equity | 5,386.1 |
| | 4,203.3 |
| | 7,237.4 |
| | (11,440.7 | ) | | 5,386.1 |
|
| | $ | 5,401.8 |
| | $ | 7,277.4 |
| | $ | 8,094.1 |
| | $ | (12,315.0 | ) | | $ | 8,458.3 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Balance Sheets
December 31, 2016
(In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| CURRENT ASSETS: | | | | | | | | | |
| Cash and cash equivalents | $ | 3.7 |
| | $ | 532.0 |
| | $ | 719.8 |
| | $ | — |
| | $ | 1,255.5 |
|
| Receivables - trade and other | — |
| | 1.8 |
| | 299.5 |
| | — |
| | 301.3 |
|
| Prepaid expenses and other current assets | 0.3 |
| | 12.9 |
| | 10.3 |
| | — |
| | 23.5 |
|
| Total current assets | 4.0 |
| | 546.7 |
| | 1,029.6 |
| | — |
| | 1,580.3 |
|
| | | | | | | | | | |
| Property and equipment - gross | — |
| | 631.0 |
| | 8,469.8 |
| | — |
| | 9,100.8 |
|
| Less accumulated depreciation and amortization | — |
| | 273.8 |
| | 1,767.0 |
| | — |
| | 2,040.8 |
|
| Property and equipment - net | — |
| | 357.2 |
| | 6,702.8 |
| | — |
| | 7,060.0 |
|
| | | | | | | | | | |
| Investments in consolidated subsidiaries | 5,115.8 |
| | 6,054.6 |
| | — |
| | (11,170.4 | ) | | — |
|
| Due from affiliates | 0.4 |
| | 437.2 |
| | 64.2 |
| | (501.8 | ) | | — |
|
| Other assets | — |
| | 5.6 |
| | 29.7 |
| | — |
| | 35.3 |
|
| | 5,120.2 |
| | 7,401.3 |
| | 7,826.3 |
| | (11,672.2 | ) | | 8,675.6 |
|
| | | | | | | | | | |
| CURRENT LIABILITIES: | |
| | |
| | |
| | |
| | |
|
| Current portion of long-term debt | — |
| | 126.8 |
| | — |
| | — |
| | 126.8 |
|
| Accounts payable - trade | 0.4 |
| | 22.4 |
| | 71.5 |
| | — |
| | 94.3 |
|
| Deferred revenue | — |
| | 0.1 |
| | 103.8 |
| | — |
| | 103.9 |
|
| Accrued liabilities | 0.3 |
| | 107.4 |
| | 51.1 |
| | — |
| | 158.8 |
|
| Total current liabilities | 0.7 |
| | 256.7 |
| | 226.4 |
| | — |
| | 483.8 |
|
| | | | | | | | | | |
| Long-term debt, less current portion | — |
| | 2,553.4 |
| | — |
| | — |
| | 2,553.4 |
|
| Due to affiliates | 0.4 |
| | 63.9 |
| | 437.5 |
| | (501.8 | ) | | — |
|
| Other liabilities | 5.2 |
| | 283.9 |
| | 49.7 |
| | — |
| | 338.8 |
|
| Deferred income taxes - net | — |
| | 582.1 |
| | 139.3 |
| | (535.7 | ) | | 185.7 |
|
| Shareholders' equity | 5,113.9 |
| | 3,661.3 |
| | 6,973.4 |
| | (10,634.7 | ) | | 5,113.9 |
|
| | $ | 5,120.2 |
| | $ | 7,401.3 |
| | $ | 7,826.3 |
| | $ | (11,672.2 | ) | | $ | 8,675.6 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 20142017
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 63,769 |
| | $ | 82,504 |
| | $ | 452,905 |
| | $ | (176,219 | ) | | $ | 422,959 |
|
| | | | | | | | | | |
| INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Property, plant and equipment additions | — |
| | (21,079 | ) | | (1,937,148 | ) | | — |
| | (1,958,227 | ) |
| Proceeds from disposals of property, plant and equipment | — |
| | 14,574 |
| | 7,413 |
| | — |
| | 21,987 |
|
| Investments in consolidated subsidiaries | — |
| | (105,261 | ) | | — |
| | 105,261 |
| | — |
|
| | | | | | | | | | |
| Net cash used in investing activities | — |
| | (111,766 | ) | | (1,929,735 | ) | | 105,261 |
| | (1,936,240 | ) |
| | | | | | | | | | |
| FINANCING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Advances (to) from affiliates | (49,182 | ) | | (731,835 | ) | | 782,198 |
| | (1,181 | ) | | — |
|
| Contributions from parent | — |
| | — |
| | 105,261 |
| | (105,261 | ) | | — |
|
| Proceeds from borrowings | — |
| | 793,380 |
| | — |
| | — |
| | 793,380 |
|
| Debt issue costs | — |
| | (687 | ) | | — |
| | — |
| | (687 | ) |
| Dividends paid | (37,695 | ) | | (75,000 | ) | | (102,400 | ) | | 177,400 |
| | (37,695 | ) |
| Excess tax benefits from share-based compensation | — |
| | (132 | ) | | — |
| | — |
| | (132 | ) |
| Proceeds from exercise of share options | 4,725 |
| | — |
| | — |
| | — |
| | 4,725 |
|
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | (82,152 | ) | | (14,274 | ) | | 785,059 |
| | 70,958 |
| | 759,591 |
|
| | | | | | | | | | |
| DECREASE IN CASH AND CASH EQUIVALENTS | (18,383 | ) | | (43,536 | ) | | (691,771 | ) | | — |
| | (753,690 | ) |
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 64,292 |
| | 92,116 |
| | 936,436 |
| | — |
| | 1,092,844 |
|
| | | | | | | | | | |
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 45,909 |
| | $ | 48,580 |
| | $ | 244,665 |
| | $ | — |
| | $ | 339,154 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | $ | (10.0 | ) | | $ | (11.3 | ) | | $ | 336.2 |
| | $ | (15.1 | ) | | $ | 299.8 |
|
| | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Capital expenditures | — |
| | (18.3 | ) | | (82.3 | ) | | — |
| | (100.6 | ) |
| Deposit on purchase of rigs | — |
| | — |
| | (7.7 | ) | | — |
| | (7.7 | ) |
| Investment in unconsolidated subsidiary | — |
| | — |
| | (30.0 | ) | | — |
| | (30.0 | ) |
| Contributions to unconsolidated subsidiary for note receivable | — |
| | — |
| | (357.7 | ) | | — |
| | (357.7 | ) |
| Proceeds from sale of assets to unconsolidated subsidiary | — |
| | — |
| | 357.7 |
| | — |
| | 357.7 |
|
| Repayments of note receivable from unconsolidated subsidiary | — |
| | — |
| | 87.5 |
| | — |
| | 87.5 |
|
| Proceeds from disposals of property and equipment | — |
| | 1.0 |
| | 2.3 |
| | — |
| | 3.3 |
|
| Investments in consolidated subsidiaries | — |
| | 32.6 |
| | — |
| | (32.6 | ) | | — |
|
| | | | | | | | | | |
| Net cash provided by (used in) investing activities | — |
| | 15.3 |
| | (30.2 | ) | | (32.6 | ) | | (47.5 | ) |
| | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Advances (to) from affiliates | 12.2 |
| | (159.7 | ) | | 147.5 |
| | — |
| | — |
|
| Distributions to issuer | — |
| | — |
| | (32.6 | ) | | 32.6 |
| | — |
|
| Reductions of long-term debt | — |
| | (170.0 | ) | | — |
| | — |
| | (170.0 | ) |
| Dividends paid | — |
| | — |
| | (15.1 | ) | | 15.1 |
| | — |
|
| Shares repurchased for tax withholdings on vesting of restricted share units | (5.7 | ) | | — |
| | — |
| | — |
| | (5.7 | ) |
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | 6.5 |
| | (329.7 | ) | | 99.8 |
| | 47.7 |
| | (175.7 | ) |
| | | | | | | | | | |
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (3.5 | ) | | (325.7 | ) | | 405.8 |
| | — |
| | 76.6 |
|
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD | 3.7 |
| | 532.0 |
| | 719.8 |
| | — |
| | 1,255.5 |
|
| | | | | | | | | | |
CASH AND CASH EQUIVALENTS,
END OF PERIOD | $ | 0.2 |
| | $ | 206.3 |
| | $ | 1,125.6 |
| | $ | — |
| | $ | 1,332.1 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 20132016
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | $ | (13,993 | ) | | $ | 160,703 |
| | $ | 476,466 |
| | $ | — |
| | $ | 623,176 |
|
| | | | | | | | | | |
| INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Property, plant and equipment additions | — |
| | (49,594 | ) | | (557,717 | ) | | — |
| | (607,311 | ) |
| Proceeds from disposals of property, plant and equipment | — |
| | 2,432 |
| | 42,118 |
| | — |
| | 44,550 |
|
| Investments in consolidated subsidiaries | (100 | ) | | (162,379 | ) | | — |
| | 162,479 |
| | — |
|
| | | | | | | | | | |
| Net cash used in investing activities | (100 | ) | | (209,541 | ) | | (515,599 | ) | | 162,479 |
| | (562,761 | ) |
| | | | | | | | | | |
| FINANCING ACTIVITES: | |
| | |
| | |
| | |
| | |
|
| Advances (to) from affiliates | 15,026 |
| | (90,821 | ) | | 75,795 |
| | — |
| | — |
|
| Contributions from parent | — |
| | — |
| | 162,479 |
| | (162,479 | ) | | — |
|
Proceeds from exercise of share options
| 2,911 |
| | — |
| | — |
| | — |
| | 2,911 |
|
| Excess tax benefits from share-based compensation | — |
| | 3,690 |
| | — |
| | — |
| | 3,690 |
|
| Other | 1,820 |
| | — |
| | — |
| | — |
| | 1,820 |
|
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | 19,757 |
| | (87,131 | ) | | 238,274 |
| | (162,479 | ) | | 8,421 |
|
| | | | | | | | | | |
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | 5,664 |
| | (135,969 | ) | | 199,141 |
| | — |
| | 68,836 |
|
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 58,628 |
| | 228,085 |
| | 737,295 |
| | — |
| | 1,024,008 |
|
| | | | | | | | | | |
CASH AND CASH EQUIVALENTS, END OF PERIOD
| $ | 64,292 |
| | $ | 92,116 |
| | $ | 936,436 |
| | $ | — |
| | $ | 1,092,844 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY (USED IN) OPERATIING ACTIVITIES | $ | (6.4 | ) | | $ | (82.8 | ) | | $ | 1,101.3 |
| | $ | (106.5 | ) | | $ | 905.6 |
|
| | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Capital expenditures | — |
| | (44.5 | ) | | (73.1 | ) | | — |
| | (117.6 | ) |
| Proceeds from disposals of property and equipment | — |
| | 0.4 |
| | 5.8 |
| | — |
| | 6.2 |
|
| Collections on note receivable from consolidated subsidiary | — |
| | 689.7 |
| | — |
| | (689.7 | ) | | — |
|
| Investments in consolidated subsidiaries | (0.2 | ) | | (80.6 | ) | | — |
| | 80.8 |
| | — |
|
| | | | | | | | | | |
| Net cash provided by (used in) investing activities | (0.2 | ) | | 565.0 |
| | (67.3 | ) | | (608.9 | ) | | (111.4 | ) |
| | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITES: | |
| | |
| | |
| | |
| | |
|
| Advances (to) from affiliates | (2.0 | ) | | 58.2 |
| | (53.0 | ) | | (3.2 | ) | | — |
|
| Contributions from parent/issuer | — |
| | — |
| | 80.8 |
| | (80.8 | ) | | — |
|
| Proceeds from borrowings | — |
| | 500.0 |
| | — |
| | — |
| | 500.0 |
|
| Reductions of long-term debt | — |
| | (511.8 | ) | | (689.7 | ) | | 689.7 |
| | (511.8 | ) |
| Dividends paid | — |
| | — |
| | (109.7 | ) | | 109.7 |
| | — |
|
| Debt issue costs | — |
| | (8.7 | ) | | — |
| | — |
| | (8.7 | ) |
| Shares repurchased for tax withholdings on vesting of restricted share units | (5.0 | ) | | — |
| | — |
| | — |
| | (5.0 | ) |
| Excess tax benefits from share-based compensation | — |
| | 2.6 |
| | — |
| | — |
| | 2.6 |
|
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | (7.0 | ) | | 40.3 |
| | (771.6 | ) | | 715.4 |
| | (22.9 | ) |
| | | | | | | | | | |
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (13.6 | ) | | 522.5 |
| | 262.4 |
| | — |
| | 771.3 |
|
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD | 17.3 |
| | 9.5 |
| | 457.4 |
| | — |
| | 484.2 |
|
| | | | | | | | | | |
CASH AND CASH EQUIVALENTS,
END OF PERIOD | $ | 3.7 |
| | $ | 532.0 |
| | $ | 719.8 |
| | $ | — |
| | $ | 1,255.5 |
|
Rowan Companies plc and Subsidiaries
Condensed Consolidating Statements of Cash Flows
Year ended December 31, 20122015
(in thousands)In millions)
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan Companies plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY OPERATING ACTIVITIES | $ | 33,797 |
| | $ | 94,628 |
| | $ | 406,149 |
| | $ | (140,865 | ) | | $ | 393,709 |
|
| | | | | | | | | | |
| INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Property, plant and equipment additions | — |
| | (94,009 | ) | | (591,247 | ) | | — |
| | (685,256 | ) |
| Proceeds from disposals of property, plant and equipment | — |
| | 6,406 |
| | 4,094 |
| | — |
| | 10,500 |
|
| Investments in consolidated subsidiaries | — |
| | (256,160 | ) | | — |
| | 256,160 |
| | — |
|
| | | | | | | | | | |
| Net cash used in investing activities | — |
| | (343,763 | ) | | (587,153 | ) | | 256,160 |
| | (674,756 | ) |
| | | | | | | | | | |
| FINANCING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Repayments of borrowings | — |
| | (200,446 | ) | | (38,007 | ) | | — |
| | (238,453 | ) |
| Advances (to) from affiliates | 3,359 |
| | (611,666 | ) | | 608,307 |
| | — |
| | — |
|
| Contributions from parent | — |
| | — |
| | 256,160 |
| | (256,160 | ) | | — |
|
| Proceeds from borrowings | — |
| | 1,104,929 |
| | — |
| | — |
| | 1,104,929 |
|
| Debt issue costs | — |
| | (2,026 | ) | | — |
| | — |
| | (2,026 | ) |
| Dividends paid | — |
| | — |
| | (140,865 | ) | | 140,865 |
| | — |
|
| Proceeds from exercise of share options | — |
| | 588 |
| | — |
| | — |
| | 588 |
|
| Excess tax benefits from share-based compensation | — |
| | 1,164 |
| | — |
| | — |
| | 1,164 |
|
| | | | | | | | | | |
| Net cash provided by (used in) financing activities | 3,359 |
| | 292,543 |
| | 685,595 |
| | (115,295 | ) | | 866,202 |
|
| | | | | | | | | | |
| INCREASE IN CASH AND CASH EQUIVALENTS | 37,156 |
| | 43,408 |
| | 504,591 |
| | — |
| | 585,155 |
|
| CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD | 21,472 |
| | 184,677 |
| | 232,704 |
| | — |
| | 438,853 |
|
| | | | | | | | | | |
| CASH AND CASH EQUIVALENTS, END OF PERIOD | $ | 58,628 |
| | $ | 228,085 |
| | $ | 737,295 |
| | $ | — |
| | $ | 1,024,008 |
|
|
| | | | | | | | | | | | | | | | | | | |
| | Rowan plc (Parent) | | RCI (Issuer) | | Non-guarantor subsidiaries | | Consolidating adjustments | | Consolidated |
| NET CASH PROVIDED BY (USED IN) OPERATING ACTIVITIES | $ | (6.3 | ) | | $ | 4.7 |
| | $ | 1,047.1 |
| | $ | (47.4 | ) | | $ | 998.1 |
|
| | | | | | | | | | |
| CASH FLOWS FROM INVESTING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Capital expenditures | — |
| | (23.2 | ) | | (699.7 | ) | | — |
| | (722.9 | ) |
| Proceeds from disposals of property and equipment | — |
| | 2.9 |
| | 16.5 |
| | — |
| | 19.4 |
|
| Advances on note receivable from consolidated subsidiary | — |
| | (481.3 | ) | | — |
| | 481.3 |
| | — |
|
| Collections on note receivable from consolidated subsidiary | 36.6 |
| | 503.5 |
| | — |
| | (540.1 | ) | | — |
|
| Investments in consolidated subsidiaries | 0.2 |
| | (37.7 | ) | | — |
| | 37.5 |
| | — |
|
| | | | | | | | | | |
| Net cash provided by (used in) investing activities | 36.8 |
| | (35.8 | ) | | (683.2 | ) | | (21.3 | ) | | (703.5 | ) |
| | | | | | | | | | |
| CASH FLOWS FROM FINANCING ACTIVITIES: | |
| | |
| | |
| | |
| | |
|
| Advances (to) from affiliates | (7.4 | ) | | 89.9 |
| | (80.9 | ) | | (1.6 | ) | | — |
|
| Contributions from parent/issuer | — |
| | — |
| | 37.5 |
| | (37.5 | ) | | — |
|
| Proceeds from borrowings | — |
| | 220.0 |
| | 481.3 |
| | (481.3 | ) | | 220.0 |
|
| Reductions of long-term debt | — |
| | (317.9 | ) | | (540.1 | ) | | 540.1 |
| | (317.9 | ) |
| Dividends paid | (50.5 | ) | | — |
| | (49.0 | ) | | 49.0 |
| | (50.5 | ) |
| Shares repurchased for tax withholdings on vesting of restricted share units | (1.2 | ) | | — |
| | — |
| | — |
| | (1.2 | ) |
| | | | | | | | | | |
| Net cash used in financing activities | (59.1 | ) | | (8.0 | ) | | (151.2 | ) | | 68.7 |
| | (149.6 | ) |
| | | | | | | | | | |
| INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS | (28.6 | ) | | (39.1 | ) | | 212.7 |
| | — |
| | 145.0 |
|
CASH AND CASH EQUIVALENTS,
BEGINNING OF PERIOD | 45.9 |
| | 48.6 |
| | 244.7 |
| | — |
| | 339.2 |
|
| | | | | | | | | | |
CASH AND CASH EQUIVALENTS,
END OF PERIOD | $ | 17.3 |
| | $ | 9.5 |
| | $ | 457.4 |
| | $ | — |
| | $ | 484.2 |
|
NOTE 18 – RELATED PARTIES
On October 17, 2017 the Company entered into a series of agreements with Saudi Aramco to form a joint venture, ARO. In connection with these transactions the Company has a number of relationships which are related party in nature. See Note 1 and Note 3 for a description of the Company's relationship with ARO and the related party transactions that have resulted from the commencement of this joint venture. Mr. Tore Sandvold is a director of the Company and a director of Schlumberger, a provider of equipment and services to the Company. The Company has engaged in transactions in the ordinary course of business with Schlumberger totaling $20.9 million
and $28.4 million in 2017 and 2016, respectively, for the purchase of equipment and services. At December 31, 2017, the Company had a payable to Schlumberger of $8.3 million. These transactions were on an arm’s-length basis and Mr. Sandvold was not involved in such transactions in any way.
NOTE 19 – SUBSEQUENT EVENT
On January 5, 2018, the Company purchased two 2013 Le Tourneau Super 116E jack-up rigs, the P-59 and P-60, which were both delivered new into service in 2013, in a public auction from a subsidiary of ContentsPetroleo Brasileiro S.A. (“Petrobras”). The purchase price was $38.5 million per unit, or an aggregate $77.0 million, of which $7.7 million was paid as a deposit in December 2017. As previously reported on the Company's Current Report on Form 8-K dated May 11, 2017, Rowan was the high bidder in a Petrobras public auction with a bid price of $30.0 million per rig. Rowan's bid was not accepted by Petrobras; however, after negotiations, both parties agreed to the revised price.
SELECTED QUARTERLY FINANCIAL DATA (UNAUDITED)
Unaudited quarterly financial data for each full quarter within the two most recent fiscal years follows (in thousandsmillions except per share amounts):
|
| | | | | | | | | | | | | | | | |
| | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| 2014: | | | | | | | | |
| Revenues | | $ | 377,602 |
| | $ | 422,878 |
| | $ | 467,692 |
| | $ | 556,211 |
|
| Income (loss) from continuing operations | | 76,557 |
| | 62,321 |
| | 106,184 |
| | (411,791 | ) |
| Net income (loss) from continuing operations | | 55,552 |
| | 32,864 |
| | 119,597 |
| | (326,888 | ) |
| Net income (loss) | | 59,595 |
| | 32,844 |
| | 119,597 |
| | (326,888 | ) |
| | | | | | | | | |
| Basic earnings (loss) per share: | | |
| | |
| | |
| | |
|
| Continuing operations | | $ | 0.45 |
| | $ | 0.26 |
| | $ | 0.96 |
| | $ | (2.63 | ) |
| Net income (loss) | | 0.48 |
| | 0.26 |
| | 0.96 |
| | (2.63 | ) |
| | | | | | | | | |
| Diluted earnings (loss) per share: | | |
| | |
| | |
| | |
|
| Continuing operations | | $ | 0.45 |
| | $ | 0.26 |
| | $ | 0.96 |
| | $ | (2.63 | ) |
| Net income (loss) | | 0.48 |
| | 0.26 |
| | 0.96 |
| | (2.63 | ) |
| | | | | | | | | |
| 2013: | | |
| | |
| | |
| | |
|
| Revenues | | $ | 394,238 |
| | $ | 408,883 |
| | $ | 382,808 |
| | $ | 393,355 |
|
| Income from continuing operations | | 90,414 |
| | 112,267 |
| | 68,509 |
| | 60,486 |
|
| Net income from continuing operations | | 68,134 |
| | 82,844 |
| | 51,900 |
| | 49,698 |
|
| Net income | | 68,134 |
| | 82,844 |
| | 51,900 |
| | 49,698 |
|
| | | | | | | | | |
| Basic earnings per share: | | |
| | |
| | |
| | |
|
| Continuing operations | | $ | 0.55 |
| | $ | 0.67 |
| | $ | 0.42 |
| | $ | 0.40 |
|
| Net income | | 0.55 |
| | 0.67 |
| | 0.42 |
| | 0.40 |
|
| | | | | | | | | |
| Diluted earnings per share: | | |
| | |
| | |
| | |
|
| Continuing operations | | $ | 0.55 |
| | $ | 0.67 |
| | $ | 0.42 |
| | $ | 0.40 |
|
| Net income | | 0.55 |
| | 0.67 |
| | 0.42 |
| | 0.40 |
|
|
| | | | | | | | | | | | | | | | |
| | | First Quarter | | Second Quarter | | Third Quarter | | Fourth Quarter |
| 2017: | | | | | | | | |
| Revenue | | $ | 374.3 |
| | $ | 320.2 |
| | $ | 291.6 |
| | $ | 296.7 |
|
| Income (loss) from operations | | 77.8 |
| | 26.1 |
| | (7.0 | ) | | 141.4 |
|
| Net income (loss) | | 10.3 |
| | (28.7 | ) | | (20.9 | ) | | 112.0 |
|
| Basic earnings (loss) per share | | 0.08 |
| | (0.23 | ) | | (0.17 | ) | | 0.89 |
|
| Diluted earnings (loss) per share | | 0.07 |
| | (0.23 | ) | | (0.17 | ) | | 0.89 |
|
| | | | | | | | | |
| 2016: | | |
| | |
| | |
| | |
|
| Revenue | | $ | 500.2 |
| | $ | 611.9 |
| | $ | 379.4 |
| | $ | 351.8 |
|
| Income from operations | | 167.4 |
| | 276.2 |
| | 33.6 |
| | 41.2 |
|
| Net income (loss) | | 122.8 |
| | 216.7 |
| | 5.5 |
| | (24.4 | ) |
| Basic earnings (loss) per share | | 0.98 |
| | 1.73 |
| | 0.04 |
| | (0.19 | ) |
| Diluted earnings (loss) per share | | 0.98 |
| | 1.72 |
| | 0.04 |
| | (0.19 | ) |
The sum of the per-share amounts for the quarters may not equal the per-share amounts for the full year due to differences in the computation of weighted average shares for the quarters and full year.
Income from continuing operations in the first, second, and fourth quartersquarter of 2014 includes2017 included a $20.9$157.4 million gain on settlementthe disposal of rig assets as a lawsuit, an $8.3 million noncash asset impairment charge,result of the sale of three rigs: the JP Bussell, the Bob Keller and a $565.7 million noncash asset impairment charge, respectively.
the Gilbert Rowe and related assets to ARO in October 2017.
Income from continuing operations in the second and fourth quartersthird quarter 2016 included a $34.3 million noncash impairment charge to reduce the carrying values of 2013 includesfive jack-up drilling units, partially offset by a $19.1$1.4 million gainreversal 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 sale of the Rowan Paris Gorilla III. Payment of such withholding taxes during the tax amnesty period resulted in the waiver of applicable penalties and a $4.5 million noncash asset impairment charge, respectively.interest.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
The Company’s management has evaluated, with the participation of the Company’s Chief Executive Officer and Chief Financial Officer, the effectiveness of the Company’s disclosure controls and procedures, as of the end of the period covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon that evaluation, the Company’s Chief Executive Officer along with the Company’sand Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2014.2017.
Management's Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining internal control over financial reporting (ICFR)as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act ("ICFR"). Our internal control system was designed to provide reasonable assurance to the Company’s management and Board of Directors regarding the preparation and fair presentation of published financial statements. All internal control systems, no matter how well designed,
have inherent limitations, and therefore can only provide reasonable assurance with respect to financial statement preparation and presentation.
Our management’s assessment is that the Company did maintain effective ICFR as of December 31, 2014,2017, within the context of the Internal Control - Integrated Framework (2013) established by the Committee of Sponsoring Organizations of the Treadway Commission, (COSO), and that the Company did not have a material change in ICFR during the fourth quarter of 2014.2017.
See “Management’s Report on Internal Control over Financial Reporting” included in Item 8 of this Form 10-K.
Changes in Internal Control Over Financial Reporting
There have been no changes to our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) during the quarter ended December 31, 2017 that have materially affected, or that are reasonably likely to materially affect, our internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
Not applicable
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE OFFICERS OF THE REGISTRANT
The names, positions and ages of the executive officers of the Company as of February 28, 2018, are listed below. Our executive officers are appointed by the Board and serve at the discretion of the Board. There are no family relationships among these officers, nor any arrangements or understandings between any officer and any other person pursuant to which the officer was selected.
|
| | |
| Name | Position | Age |
| Thomas P. Burke | President and Chief Executive Officer | 50 |
| Stephen M. Butz | Executive Vice President and Chief Financial Officer | 46 |
| Mark Mai | Executive Vice President, General Counsel and Company Secretary | 53 |
| Dennis Baldwin | Chief Accounting Officer | 57 |
| T. Fred Brooks | Executive Vice President, Operations and Engineering | 60 |
| Alan Quintero | Senior Vice President, Business Development | 54 |
| Kelly McHenry | Chief Executive Officer, ARO | 46 |
| Jason Anderson | Vice President, Human Resources | 42 |
Dr. Burke was appointed President and Chief Executive Officer and elected a director of the Company in April 2014. He served as Chief Operating Officer beginning in July 2011 and was appointed President in March 2013. Dr. Burke first joined the Company in December 2009, serving as Chief Executive Officer and President of LeTourneau Technologies until the sale of LeTourneau in June 2011. From 2006 to 2009, Dr. Burke was a Division President at Complete Production Services, an oilfield services company, and from 2004 to 2006, served as its Vice President for Corporate Development.
Mr. Butz became Executive Vice President and Chief Financial Officer upon joining the Company in December 2014, and also served as Treasurer from December 2014 through February 2016. Prior to joining the Company, Mr. Butz served as Executive Vice President and Chief Financial Officer at Hercules Offshore, Inc. He was Senior Vice President and Chief Financial Officer of Hercules Offshore from 2010 to 2013 and held a number of other key positions after joining Hercules Offshore in 2005, including Director of Corporate Development and Vice President, Finance and Treasurer. Prior to joining Hercules Offshore, Mr. Butz held positions in both investment and commercial banking.
Mr. Mai became Executive Vice President, General Counsel and Company Secretary in May 2017. Prior to joining the Company, he was at Dresser-Rand Group Inc. from October 2007 to August 2015, serving as its Vice President, General Counsel and Secretary. Prior to this time, Mr. Mai served in various roles at Cooper Industries, including Associate General Counsel, Corporate and Litigation, and was a partner at the law firm of Thompson & Knight LLP.
Mr. Baldwin became Chief Accounting Officer in April 2016. Prior to joining the Company, he served as Vice President, Controller and Chief Accounting Officer for Cameron International Corporation from March 2014 until March 2016. Prior to such time, he was Senior Vice President and Chief Accounting Officer of KBR, Inc. from August 2010 to March 2014, and Vice President and Chief Accounting Officer of McDermott International from October 2007 to August 2010. He also previously served at Integrated Electrical Services and Veritas DGC.
Mr. Brooks became Executive Vice President, Operations and Engineering in February 2017. Prior to that time, he served as Senior Vice President, Operations from October 2012 through January 2017, and as Vice President, Deepwater Operations from March 2011 through September 2012. Prior to joining the Company, Mr. Brooks served as Senior Vice President of Operations at Northern Offshore from 2008 through 2010. He also served in various management positions at GlobalSantaFe from 1998 through 2007, including Vice President of West Africa Operations, and Vice President of Worldwide Deepwater & Gulf of Mexico Operations.
Mr. Quintero became Senior Vice President, Business Development in January 2018, after serving as Senior Vice President, Chief Technology Officer since June 2017. Prior to joining the Company, Mr. Quintero served as Senior Vice President at Transocean from 2010 through 2015 overseeing Operations, Asset Management, and Major Capital Projects. He also served in various management roles at Atwood Oceanics from 1993 through 2010, where he ended as Senior Vice President with responsibilities
over Operations, Technical Services, Supply Chain, Projects, Quality Assurance, and Maintenance. Immediately prior to joining Rowan, Mr. Quintero was a Partner at Trenegy Incorporated, a management consulting firm.
Mr. McHenry was appointed Chief Executive Officer of ARO Drilling upon its inception in May 2017. Prior to this time, Mr. McHenry managed Rowan’s Middle East and Southeast Asia operations for 10 years. He served Rowan most recently as Vice President, Drilling Operations from 2013 to 2017 and in several other key operations management positions from 2004 through 2013. Mr. McHenry has more than 27 years of experience in the drilling industry.
Mr. Anderson became Vice President, Human Resources in May 2017, after serving as Senior Director, Human Resources since March 2016. He previously served in several key human resources and compliance positions since joining the Company in May 2007. Prior to this time, Mr. Anderson served in various audit and consulting roles.
Information concerning our directors will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A of the Exchange Act (Regulation 14A) on or before April 30, 2015,2018 under the caption “Election of Directors.” Such information is incorporated herein by reference.
Information concerning our executive officers appears in Part I under the caption “Executive Officers of the Registrant” of this Form 10-K.
Information concerning our Audit, CommitteeCompensation and Nominating Committees will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A on or before April 30, 2015, under the caption “Committees“Board of the Board of Directors.Directors Information.” Such information is incorporated herein by reference.
Our committee charters and corporate governance guidelines are available on our website, www.rowan.com.
Information concerning compliance with Section 16(a) of the Securities Exchange Act will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A on or before April 30, 2015, under the caption “Additional Information - Section 16(a) Beneficial Ownership Reporting Compliance.” Such information is incorporated herein by reference.
We have adopted a code of ethics that applies to the Company’s directors, officers and employees, including the Chief Executive Officer, Chief Financial Officer, Chief Accounting Officer and other persons performing similar functions. Our code of ethics is available on our website, www.rowan.com. We will disclose on our website any amendment to or waiver from our code of ethics on behalf of any of our executive officers or directors.
ITEM 11. EXECUTIVE COMPENSATION
Information concerning director and executive compensation will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A on or before April 30, 2015, under the captions “Director“Non-Executive Director Compensation, and Attendance,” “Compensation Discussion &and Analysis,” “Compensation Committee Report,” and “Executive Compensation.” Such information is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Information concerning the security ownership of management will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A on or before April 30, 2015, under the caption “Security Ownership of Management and Certain Beneficial Owners and Management.Owners.” Such information is incorporated herein by reference.
The business address of all directors is the principal executive offices of the Company as set forth on the cover page of this Form 10-K.
Equity Compensation Plan Information
The following table provides information about our ordinary shares that may be issued under equity compensation plans as of December 31, 2014.2017.
| | | | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (1) (a) | Weighted-average exercise price of outstanding options, warrants and rights (2) (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) | | Number of securities to be issued upon exercise of outstanding options, warrants and rights (1) (a) | Weighted-average exercise price of outstanding options, warrants and rights (2) (b) | Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a)) (c) |
| Equity compensation plans approved by security holders | Equity compensation plans approved by security holders | 284,816 | $21.02 | 5,619,212 | Equity compensation plans approved by security holders | 454,946 | $17.08 | 8,548,953 |
| Equity compensation plans not approved by security holders | Equity compensation plans not approved by security holders | — | — | — | Equity compensation plans not approved by security holders | — | — | — |
| Total | Total | 284,816 | $21.02 | 5,619,212 | Total | 454,946 | $17.08 | 8,548,953 |
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| (1) | The number of securities to be issued includes (i) 185,404454,946 options and 99,412no shares issuable under outstanding SARs (see note (2) below). |
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| (2) | The weighted-average exercise price in column (b) is based on (i) 185,404454,946 shares under outstanding options with a weighted average exercise price of $22.96$17.08 per share, and (ii) 99,412no shares of stock that would be issuable in connection with 1,761,270 stock appreciation rights (SARs)1,028,532 SARs outstanding at December 31, 2014.2017. The number of shares issuable under SARs is equal in value to the excess of the Company’s share price on the date of exercise over the exercise price. The number of shares issuable under SARs included in column (a) was based on a December 31, 20142017 closing stock price of $23.32$15.66 and a weighted-average exercise price of $30.94$31.03 per share. |
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
Information concerning director and executive related party transactions will appear in our proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A on or before April 30, 2015, within the section and under the captions “Director“Corporate Governance - Director Independence” and “Related“Corporate Governance - Related Party Transactions.Transaction Policy.” Such information is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Information concerning principal accounting fees and services will appearrequired by this Item is included in ourthe proxy statement for the 20152018 annual general meeting of shareholders to be filed pursuant to Regulation 14A no later than April 30, 2015, in the last paragraph under the caption “Fees“Audit Committee Report - Approval of Audit Firm.Fees.” Such information is incorporated herein by reference.
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) Index to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial Statements
(2) Financial Statement Schedules
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| SCHEDULE II |
| ROWAN COMPANIES PLC AND SUBSIDIARIES |
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| VALUATION AND QUALIFYING ACCOUNTS AND ALLOWANCES |
| FOR THE THREE YEARS ENDED DECEMBER 31, 2017 |
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| | | | | Additions | | | | |
| | | Balance at | | | | | | | | Balance at |
| | | Beginning | | Charged to | | | | | | End of |
| Description | | of Period | | Expense, Net | | Adjustments | | Deductions | | Period |
| | | (In millions) |
| Year Ended December 31, 2017: | | | | | | | | | | |
| Valuation allowance of deferred tax assets | | $ | 889.8 |
| | $ | — |
| | $ | — |
| | $ | (19.9 | ) | | $ | 869.9 |
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| Year Ended December 31, 2016: | | | | | | | | | | |
| Valuation allowance of deferred tax assets | | $ | 128.3 |
| | $ | 761.5 |
| | $ | — |
| | $ | — |
| | $ | 889.8 |
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| Year Ended December 31, 2015: | | | | | | | | | | |
| Valuation allowance of deferred tax assets | | $ | 22.3 |
| | $ | 106.0 |
| | $ | — |
| | $ | — |
| | $ | 128.3 |
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For the year ended December 31, 2017, management has assessed the need for continued valuation allowances on deferred tax assets. The changes to the valuation allowance balance is discussed in Note 12 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. For the year ended December 31, 2016, management assessed negative and positive evidence and determined the need to establish a valuation allowance against the Luxembourg deferred tax assets of $747 million as discussed in Note 12 to our consolidated financial statements in Part II, Item 8 of this Annual Report on Form 10-K. For the year ended December 31, 2015, an additional valuation allowance of $62 million on the U.S. 2014 and prior years’ deferred tax assets and an additional valuation allowance of $43 million on the U.S. 2015 deferred tax assets has been recorded in 2015 to recognize only the portion of the deferred tax assets that is more likely to be realized.
Financial Statement Schedules I, II, III, IV, and V are not included in this Form 10-K because such schedules are not required, the required information is not significant, or the information is presented elsewhere in the financial statements.
(3) Exhibits
Unless otherwise indicated below as being incorporated by reference to another filing of the Company with the Securities and Exchange Commission, each of the following exhibits is filed herewith:
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2.1 |
| | Agreement and Plan of Merger and Reorganization by and between Rowan Companies, Inc. and Rowan Mergeco, LLC dated February 27, 2012, incorporated by reference to Annex A of the Registration Statement on Form S-4 filed by Rowan Companies Limited (now Rowan Companies plc) on February 28, 2012 with the Securities and Exchange Commission (File No. 333-179749). |
2.2 |
| | Amendment No. 1 to Agreement and Plan of Merger and Reorganization dated April 12, 2012, incorporated by reference to Exhibit 2.1 to the Company’s Current Report on Form 8-K filed on April 12, 2012 (File No. 1-5491). |
3.1 |
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* 10.1 |
| | Restated 1988 Nonqualified Stock Option Plan,Eighth Supplemental Indenture dated as amended, incorporated by reference to Appendix C to the Proxy Statement dated March 20, 2002 (File No. 1-5491)of December 19, 2016, among Rowan Companies, Inc., Rowan Companies plc and Form of Stock Option Agreement related thereto,U.S. Bank National Association, as trustee, incorporated by reference to Exhibit 10a to4.2 of the Company’s Current Report on Form 10-K for the year ended8-K filed on December 31, 200419, 2016 (File No. 1-5491). |
*10.2 |
| | 1998 Nonemployee Director Stock Option Plan, |
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10.3 |
| | Memorandum Agreement dated January 26, 2006 between Rowan Companies, Inc. and C. R. Palmer, incorporated by reference to Exhibit 10jj to Form 10-K for year ended December 31, 2005 (File No. 1-5491). |
*10.4 |
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| | Form of Non-Employee Director 2005 Restricted Stock Unit Grant, Form of Non-Employee Director 2006 Restricted Stock Unit Grant, Form of 2005 Restricted Stock Grant Agreement, Form of 2005 Nonqualified Stock Option Agreement, Form of 2005 Performance Share Award Agreement related thereto, each incorporated by reference to ExhibitsExhibit 10c 10d, 10e, 10f and 10g, respectively, to Form 10-Q for the quarterly period ended June 30, 2005 (File No. 1-5491).
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*10.7 |
10.10 | | |
10.8 |
| | Share Purchase Agreement dated July 1, 2010, among Rowan Companies, Inc., Skeie Technology AS, Skeie Tech Invest AS and Wideluck Enterprises Limited and Pre-Acceptance Letters from Skeie Holding AS and Trafalgar AS, each relating to the purchase of shares of common stock of Skeie Drilling & Production ASA, incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on August 19, 2010 (File No. 1-5491). |
10.9 |
| | Amended and Restated Credit Agreement dated January 23, 2014 among Rowan Companies, Inc., as Borrower, Rowan Companies plc, as Parent, the Lenders named therein, Wells Fargo Bank, National Association, as Administrative Agent, Issuing Lender and Swingline Lender and Citibank, N.A., DnB Bank ASA, New York Branch, Royal Bank of Canada, Bank of America, N.A., Barclays Bank PLC and Goldman Sachs Bank USA, as Co-Syndication Agents), incorporated by reference to Exhibit 10.1 of the Company’s Current Report on Form 8-K filed on January 28, 2014 (File No. 1-5491). |
10.10 |
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10.11 |
| | Stock Purchase Agreement dated May 13, 2011, between Rowan Companies, Inc., as seller, and Joy Global Inc., as buyer, relating to the sale of all the outstanding equity interests in LeTourneau Technologies, Inc., a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on May 18, 2011 (File No. 1-5491). |
10.12 |
| | Purchase and Sale Agreement dated July 19, 2011, among Rowan Companies, Inc., as seller, and Ensign United States Drilling (S.W.) Inc., as buyer, and Ensign Energy Services Inc., as guarantor of the buyer’s performance under the agreement, relating to the sale of all the outstanding equity interests in Rowan Drilling Company LLC, a wholly owned subsidiary of the Company, incorporated by reference to Exhibit 2.1 of the Company’s Current Report on Form 8-K filed on July 20, 2011 (File No. 1-5491). |
*10.13 |
| | Amendment to the Rowan Companies, Inc. Restated 1988 Nonqualified Stock Option Plan, effective May 4, 2012, incorporated by reference to Exhibit 10.9 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491). |
*10.14 |
| | Amendment to the Rowan Companies, Inc. 1998 Nonemployee Director Stock Option Plan, effective May 4, 2012, incorporated by reference to Exhibit 10.10 to the Company’s Current Report on Form 8-K filed on May 4, 2012 (File No. 1-5491). |
*10.15 |
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*10.23 |
10.21 | | Retirement Agreement with William H. Wells dated September 7, 2012, incorporated by reference to Exhibit 10.14 of the Company’s Form 10-Q for the quarter ended September 30, 2012 (File No. 1-5491). |
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*10.30 |
10.27 | | Summary of the Company’s Annual Incentive Plan. |
*10.31 |
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*10.32 |
10.28 | | |
*10.33 |
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²101.INS |
| | XBRL Instance Document. |
²101.SCH |
| | XBRL Taxonomy Extension Schema Document. |
²101.CAL |
| | XBRL Taxonomy Extension Calculation Linkbase Document. |
²101.DEF |
| | XBRL Taxonomy Extension Definition Linkbase Document. |
²101.LAB |
| | XBRL Taxonomy Extension Label Linkbase Document. |
²101.PRE |
| | XBRL Taxonomy Extension Presentation Linkbase Document. |
__________
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| * | Executive compensatory plan or arrangement. |
| ² | Filed herewith. |
| v | Confidential Information has been omitted and filed separately with the Securities and Exchange Commission. Confidential treatment has been requested with respect to this omitted information. |
| ª | Schedules and exhibits have been omitted pursuant to Item 601(b)(2) of Regulation S-K. The registrant agrees to furnish supplementally a copy of the omitted schedules and exhibits to the Securities and Exchange Commission upon request.
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Rowan agrees to furnish to the Commission upon request a copy of all instruments defining the rights of holders of long-term debt of the Company and its subsidiaries.
ITEM 16. FORM 10-K SUMMARY
Not applicable
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
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| | ROWAN COMPANIES plcPLC |
| | (Registrant) |
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| | By: /s/ THOMAS P. BURKE |
| | Thomas P. Burke |
| | President and Chief Executive Officer |
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| | Date: March 2, 2015February 28, 2018 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities and on the date indicated.
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| Signature | Title | Date |
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| /s/ THOMAS P. BURKE | President and Chief Executive Officer and Director (Principal Executive Officer) | March 2, 2015February 28, 2018 |
| (Thomas P. Burke) | | |
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| /s/ STEPHEN M. BUTZ | PrincipalExecutive Vice President and Chief Financial Officer (Principal Financial Officer) | March 2, 2015February 28, 2018 |
| (Stephen M. Butz) | | |
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/s/ GREGORY M. HATFIELDDENNIS S. BALDWIN | PrincipalChief Accounting Officer (Principal Accounting Officer) | March 2, 2015February 28, 2018 |
(Gregory M. Hatfield)Dennis S. Baldwin) | | |
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/s/ WILLIAM T. FOX III E. ALBRECHT | DirectorChairman of the Board | March 2, 2015February 28, 2018 |
(William T. Fox III)E. Albrecht) | | |
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SIR GRAHAM HEARNE | Director | March 2, 2015 |
(Sir Graham Hearne) | | |
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| /s/ THOMAS R. HIX | Director | March 2, 2015February 28, 2018 |
| (Thomas R. Hix) | | |
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LORD MOYNIHAN /s/ JACK B. MOORE | Director | March 2, 2015February 28, 2018 |
(Lord Moynihan)Jack B. Moore) | | |
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| /s/ SUZANNE P. NIMOCKS | Director | March 2, 2015February 28, 2018 |
| (Suzanne P. Nimocks) | | |
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P. DEXTER PEACOCK /s/ THIERRY PILENKO | Director | March 2, 2015February 28, 2018 |
(P. Dexter Peacock)Thierry Pilenko) | | |
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| /s/ JOHN J. QUICKE | Director | March 2, 2015February 28, 2018 |
| (John J. Quicke) | | |
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W. MATT RALLS/s/ TORE I. SANDVOLD | Chairman of the BoardDirector | March 2, 2015February 28, 2018 |
(W. Matt Ralls)Tore I. Sandvold) | | |
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TORE I. SANDVOLD/s/ CHARLES L. SZEWS | Director | March 2, 2015February 28, 2018 |
(Tore I. Sandvold)Charles L. Szews) | | |
