10-K 1 form10k2012.htm 2012 10-K form10k2012.htm




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

FORM 10-K

R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the year ended December 31, 2012
 
OR
 
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________

Commission File Number: 1-5491
 
logo
Rowan Companies plc
 
(Exact name of registrant as specified in its charter)
England and Wales
98-1023315
(State or other jurisdiction of incorporation or organization)
(I.R.S. Employer Identification No.)

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

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

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

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

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes R   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 R

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 R   No £

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

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

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes £   No R

The aggregate market value of common equity held by non-affiliates of the registrant was approximately $3.986 billion as of June 30, 2012, based upon the closing price of the registrant’s ordinary shares on the New York Stock Exchange Composite Tape of $32.33 per share.

The number of Class A ordinary shares, $0.125 par value, outstanding at January 31, 2013, was 124,251,953.

DOCUMENTS INCORPORATED BY REFERENCE

Document
Part of Form 10-K
Portions of the Proxy Statement for the 2013 Annual General Meeting of Shareholders
Part III, Items 10-14




 
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FORWARD-LOOKING STATEMENTS

Statements contained in this report that are not historical facts are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934.  Forward-looking statements include words or phrases such as “anticipate,” “believe,” “estimate,” “expect,” “intend,” “plan,” “project,” “could,” “may,” “might,” “should,” “will,” “forecast,” “potential,” “scheduled,” “predict,” “will be,” “will continue,” “will likely result,” and similar words and specifically include statements regarding expected financial performance; growth strategies; expected utilization, day rates, revenues, operating expenses, contract terms, contract backlog, capital expenditures, tax rates, insurance coverages, access to financing and funding sources; the availability, delivery, mobilization, contract commencement, relocation or other movement of rigs and the timing thereof; future rig construction (including construction in progress and completion thereof), enhancement, upgrade or repair and costs and timing thereof; the suitability of rigs for future contracts; general market, business and industry conditions, trends and outlook; future operations; the impact of increasing regulatory  requirements and complexity; expected contributions from our new rigs and our entry into the ultra-deepwater market; expense management; the likely outcome of legal proceedings or insurance or other claims and the timing thereof; activity levels in the offshore drilling market; customer drilling programs; and commodity prices. Such statements are subject to numerous risks, uncertainties and assumptions that may cause actual results to vary materially from those indicated, including:

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

·  
governmental regulatory, legislative and permitting requirements affecting drilling operations in the areas in which our rigs operate;

·  
tax matters, including our effective tax rates, tax positions, changes in tax laws, treaties and regulations, tax assessments and liabilities for taxes;

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

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

·  
downtime, lost revenue and other risks associated with rig operations, operating hazards, or rig relocations and transportation, including rig or equipment failure, collisions, damage and other unplanned repairs, the limited availability of transport vessels, hazards, self-imposed drilling limitations and other delays due to weather conditions or otherwise, and the limited availability or high cost of insurance coverage for certain offshore perils or associated removal of wreckage or debris;

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

·  
possible cancellation or suspension of drilling contracts as a result of mechanical difficulties, delays, performance or other reasons;

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

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

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


·  
our ability to attract and retain skilled personnel on commercially reasonable terms, whether due to competition from other contract drillers, labor regulations or otherwise;

·  
governmental action and political and economic uncertainties, including uncertainty or 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 of the Middle East or other geographic areas, which may result in extended business interruptions, suspended operations, or result in claims by our customers of a force majeure situation and payment disputes;

·  
terrorism, piracy, political instability, hostilities, nationalization, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in our areas of operations, including the Middle East;

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

·  
potential long-lived asset impairments;

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

·  
impacts of any global financial or economic downturn;

·  
effects of accounting changes and adoption of accounting policies;

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

·  
other important factors described from time to time in the reports filed by us with the Securities and Exchange Commission (the Commission), and the New York Stock Exchange (NYSE).

All forward-looking statements contained in this Form 10-K speak only as of the date of this document.  We undertake no obligation to update or revise publicly any revisions to any such forward-looking statements that may be made to reflect events or circumstances after the date of this Form 10-K, or to reflect the occurrence of unanticipated events, except as required by applicable law.

Other relevant factors are included in Item 1A, “Risk Factors,” of this Form 10-K.




On May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales (Rowan UK), became the successor issuer to Rowan Companies, Inc. (Rowan Delaware) pursuant to an agreement and plan of merger and reorganization (the “redomestication”) approved by the stockholders of Rowan Delaware on April 16, 2012.  As a result of the redomestication, Rowan UK 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 reporting requirements, the mandates of the Sarbanes-Oxley Act and the applicable corporate governance rules of the NYSE, and we will continue to report our consolidated financial results in U.S. dollars and in accordance with accounting principles generally accepted in the United States of America (US GAAP).  We also must comply with additional reporting requirements of English law.  The redomestication was accounted for as an internal reorganization of entities under common control; therefore, for purposes of these consolidated financial statements, 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 UK (or Rowan Delaware for periods prior to the redomestication) and its consolidated subsidiaries.


In June 2011, we completed the sale of our wholly owned manufacturing subsidiary, LeTourneau Technologies, Inc. (LeTourneau), and in September 2011, we completed the sale of our land drilling operations.  Prior to 2011 our manufacturing operations were reported as the Drilling Products and Systems and the Mining, Forestry and Steel Products segments, and our land drilling operations were reported as a component of our Drilling Services segment.  See Note 3 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K for further information.

The Company does not currently segment its continuing offshore drilling business for reporting purposes.  Information with respect to our revenues and assets by geographic areas of operation is presented in Note 12 of “Notes to Consolidated Financial Statements” in Item 8 of this Form 10-K.

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

Overview

The Company is a major provider of offshore oil and gas contract drilling services internationally and provides its services utilizing a fleet of 31 self-elevating mobile offshore “jack-up” drilling units.  The Company’s primary focus is on high-specification and premium jack-up rigs, which its customers use for exploratory and development drilling and, in certain areas, well workover operations.  Additionally, the Company has four ultra-deepwater drillships under construction, the first of which is scheduled for delivery in December 2013.

The Company conducts offshore drilling operations in various markets throughout the world including the U.K. and Norwegian sectors of the North Sea, Middle East, Southeast Asia, the United States Gulf of Mexico (US GOM), Trinidad and Egypt, among others.

During 2012, we generated revenues of $1.393 billion and operating income of $255.1 million, compared with $939.2 million and $149.6 million, respectively, in 2011.  Our results of operations are further discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Item 7 of this Form 10-K.

Drilling Fleet

We operate large jack-up rigs capable of drilling depths up to 35,000 feet in maximum water depths ranging from 250 to 550 feet, depending on rig size and location.  Our jack-ups are 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 the ocean floor, and the hull is jacked up to the elevation required to drill the well.

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

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

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

 
Three conventional or slot jack-up rigs with skid-off capability.

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


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

Our three Super Gorilla class rigs were delivered during the period from 1998 to 2002 and are enhanced versions of our Gorilla class rigs that can be equipped for simultaneous drilling and production operations.  They can operate year-round in 400 feet of water south of the 61st parallel in the North Sea, within the worst-case combination of 100-year storm criteria for waves, wave periods, winds and currents.  The Bob Palmer, which was delivered in 2003, is an enhanced version of the Super Gorilla class jack-up and is designated a Super Gorilla XL.  With 713 feet of leg, 139 feet more than the Super Gorillas, and 30% larger spud cans, this rig can operate in water depths to 550 feet in typically benign environments like the US GOM and the Middle East or in water depths to 400 feet in the hostile environments of the North Sea and offshore eastern Canada.

Our four Tarzan Class rigs were delivered during the period from 2004 to 2008 and 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 to 400 feet.  The first and second 240Cs, the Rowan Mississippi and Ralph Coffman, were added to the fleet in 2008 and 2009, respectively.  The third 240C, the Joe Douglas, was added to the fleet in the fourth quarter of 2011.

Our four EXL class rigs employ the latest technology to enable drilling of HPHT and extended-reach wells in most of the prominent jack-up markets throughout the world, and are equipped with the hook-load and horsepower required to efficiently drill beyond 30,000 feet.  The first three EXL class rigs were delivered in 2010, and the EXL IV was delivered in the fourth quarter of 2011.

Our three N-Class rigs are capable of drilling up to 35,000 feet in harsh environments such as the North Sea and in maximum water depths of 450 feet.  The N-Class rigs, which were designed for operation in the highly regulated Norwegian sector of the North Sea, can be equipped to perform drilling and production operations simultaneously.  Our first N-Class rig, the Rowan Viking, was delivered in October 2010, and the Rowan Stavanger and Rowan Norway were delivered in January and June 2011, respectively.

In 2011 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction of three ultra-deepwater drillships, the Rowan Renaissance, Rowan Resolute and Rowan Reliance, which are scheduled for delivery in December 2013, June 2014 and October 2014, respectively.  In 2012 we exercised our option with Hyundai for the construction of a fourth ultra-deepwater drillship, the Rowan Relentless, which is scheduled for delivery in March 2015.  The agreement with Hyundai also includes an option for a similar fifth drillship exercisable in the first quarter of 2013, for delivery in the third quarter of 2015.  We may seek to extend the option prior to its termination.  The drillships, which are being constructed at Hyundai’s Ulsan, South Korea, shipyard, will be capable of drilling wells to depths of 40,000 feet in waters of up to 12,000 feet.  The DP-3 compliant, dynamically-positioned drillships will be equipped with retractable thrusters, dual-activity capability, five mud pumps, dual mud systems and a maximum hook-load capacity of 1,250 tons.  Each will also be equipped with a seven-ram BOP incorporating full acoustic backup control plus a second BOP on board.  They will feature hull integration with below-deck riser storage, four million pounds riser tensioning, main load path active-heave drawworks, three 100-ton knuckle boom cranes, an active-heave 165-ton crane for simultaneous deployment of subsea equipment, a variable deck load capacity of 20,000 tons and accommodations for 210 personnel.

Our drilling operations are subject to many hazards, including blowouts, well fires and severe weather, which could cause personal injury, suspend drilling operations, seriously damage or destroy equipment, and cause substantial damage to producing formations and the surrounding environment.  Damage to a jack-up rig’s legs can occur in the event they punch through the ocean floor.  Offshore drilling rigs are also subject to marine hazards, either while on site or under tow, such as vessel capsizing, collision or grounding.  Raising and lowering the legs of jack-up rigs into the ocean floor requires skillful handling to avoid capsizing or other serious damage.  Drilling into high-pressure formations is a complex process and problems can frequently occur.  See Item 1A, “Risk Factors,” of this Form 10-K for additional information.

See Item 2, “Properties,” of this Form 10-K for additional information with respect to the rigs in our fleet.

Contracts

Our drilling contracts generally provide for a fixed amount of compensation per day, known as the day rate, and are usually obtained either through competitive bidding or individual negotiations.


Our drilling contracts are either “well-to-well,” “multiple-well” or for a fixed term generally ranging from one month to multiple years. Well-to-well contracts are cancelable by either party upon completion of drilling.  Fixed-term contracts usually provide for termination by either party 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, some can continue for periods longer than the original terms, and 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 and, in certain cases, such option rates are agreed upon at the outset of the contract.  Many of our drilling contracts provide for separate lump-sum payments for rig mobilization and demobilization, for which we recognize the revenues and related expenses over the primary contract term, and for reimbursement of certain other costs, for which we recognize both revenues and expenses when incurred.  Our contracts for work in foreign countries generally provide for payment in United States dollars except for amounts required by applicable law to be paid in the local currency or amounts required to meet local expenses.

A number of factors affect our ability to obtain contracts at profitable rates within a given area.  Such factors, which are discussed further under “Competition,” include the 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 accepted lower rates in an attempt to keep our rigs working and to mitigate the substantial costs of maintaining and reactivating stacked rigs.  In 2010, however, we chose to cold-stack two of our least competitive rigs and in 2011 we stacked a third rig, rather than making the substantial capital expenditures required in order to secure ongoing work.  In periods of strong demand and rising day rates, we strive to maintain a mix of short- and long-term contracts to enable us to both take advantage of potential higher future rates (and cover potential higher operating costs) as well as provide down-side protection when markets inevitably decline.

Our offshore drilling revenue backlog was estimated to be approximately $3.6 billion at February 21, 2013, up from approximately $3.1 billion at February 27, 2012.  See “Outlook” in Management’s Discussion and Analysis of Financial Condition and Results of Operations in Item 7 of this Form 10-K for further information with respect to the Company’s backlog.

Competition

The contract drilling industry is highly competitive, and success in obtaining contracts involves many factors, including price, rig capability, operating and safety performance and reputation.

Currently, we compete with several offshore drilling contractors that together have 782 mobile rigs available worldwide, including 481 jack-ups.  We estimate that 39 or 8% of the world’s existing jack-up fleet are high-specification, including the 19 high-specification rigs that we own.  Eighty-eight additional jack-up rigs are under construction for delivery through 2015, 32 of which are considered high-specification.

There are currently 84 drillships operating worldwide plus another 74 under construction or on order for delivery through 2020, including our four.  We estimate that 51, or approximately 61% of the world’s existing drillship fleet, are capable of drilling in water depths of 10,000 feet or more, and 72 of the 74 under construction will have 10,000-foot water depth capabilities.

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

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



Governmental Regulation

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

Generally, we are indemnified under our drilling contracts for pollution, well and environmental damages, 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 the pollutant, environmental remediation and claims by third parties for damages.

Our customers often require us to assume responsibility for pollution damages where we are at fault.  In each of these instances, we seek to limit our liability exposure to a non-material amount, or an amount within the limits of our available insurance coverage. For example, a contract may provide that we will assume the first $500,000 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 $500,000.  We can provide no assurance, however, that we will be able to negotiate indemnities and/or limitation of liability provisions for all of our contracts or that such indemnification and/or limitation of liability provisions can be enforced or will be sufficient.  Our customers may challenge the validity or enforceability of the indemnity provision for several reasons, including but not limited to, applicable law, judicial decisions, the language of the indemnity provision, reasons of public policy, degree of fault and/or the circumstances resulting in the pollution.

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

Pursuant to the Clean Water Act, the owner of a lease (the Operator) is required to obtain a National Pollutant Discharge Elimination Permit (NPDES permit).  For drilling operations conducted in the US GOM, these permits are issued and administered by the Environmental Protection Agency (EPA).  As a contract driller in the US GOM, we operate in accordance with the Operator’s NPDES permit.   According to the NPDES permit, the Operator 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.  In addition, pursuant to the International Maritime Organization, to which the United States is a signatory, we are required to have for each of our drilling units a Shipboard Oil Pollution Emergency Plan (SOPEP), which is administered by the United States Coast Guard (USCG). 

In support of compliance with these permits and regulations, our SOPEP details procedures for rapid and effective response to spill events that may occur as a result of our operations or those of the Operator. This plan is reviewed annually and updated as necessary. Onboard drills are conducted periodically to maintain effectiveness of the plan and each rig is outfitted with equipment to respond to minor spills.  The drills include participation of key personnel, spill response contractors and representatives of governmental agencies.  For operations in the United States, our SOPEPs are subject to review and approval by various organizations including the USCG, EPA and the Bureau of Safety and Environmental Enforcement (BSEE), formerly the Bureau of Ocean Energy Management, Regulatory and Enforcement (BOEMRE), and are recertified by the American Bureau of Shipping every five years.

As the designated responsible party, the Operator has the primary responsibility for spill response, including having contractual arrangements in place with emergency spill response organizations to supplement any onboard spill response equipment.  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 spill response provider has been in business since 1994 and specializes in helping industries prevent and clean up oil and other hydrocarbon spills throughout the Gulf Coast, with response centers in Texas and Louisiana with 24-hour response capabilities and equipment.  Our provider’s website states that it holds all necessary licenses, certifications and permits to respond to emergencies in the US GOM and that it has significant spill response resources to meet the needs of its customers.


We believe these resources have adequate equipment 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 may also have similar regulations and requirements.

In addition, we are actively involved in various industry-led initiatives and task forces, including the American Petroleum Institute’s newly formed Center for Offshore Safety, that are engaged in various initiatives to improve safety and protect the environment.

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

In the United States, we are subject to the requirements of the Occupational Safety and Health Act of 1970 (OSHA) and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations.  There are comparable requirements in other non-U.S. jurisdictions in which we operate.

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

Insurance

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

Our current insurance policies provide coverage for loss or damage to our fleet of drilling rigs on an agreed value basis (which varies by unit) subject to a deductible of $25 million per occurrence.  This coverage does not include damage 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), auto liability and aviation 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 in cases of removal-of-rig-wreck due to a US GOM named windstorm, which has a self-insured retention of $200 million).

Our rig physical damage and liability insurance renews each June.  Due to industry losses in recent years, including the 2010 Macondo incident, it may be impossible to secure coverage of a similar nature and with similar limits, or such coverage may be available only at higher costs.

Employees

At December 31, 2012, we had 3,119 employees worldwide, compared to 2,719 and 5,217 at December 31, 2011 and 2010, respectively.  The number of employees at December 31, 2010, included 2,976 employees attributable to operations that were sold in 2011.  Certain of our employees and contractors in international markets, such as Trinidad and Norway, are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation.  We consider relations with our employees to be satisfactory.

Customers

Saudi Aramco and Total Exploration & Production accounted for 29% and 11%, respectively, of our 2012 consolidated revenues.




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

We operate in a volatile business that is heavily dependent upon commodity prices and other factors beyond our control.

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

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

·  
worldwide demand for drilling services;
 
·  
worldwide demand and prices for oil and natural gas;
 
·  
the level of exploration and development expenditures by energy companies;
 
·  
the willingness and ability of the Organization of Petroleum Exporting Countries, or OPEC, to limit production levels and influence prices;
 
·  
the level of production in non-OPEC countries;
 
·  
the effect of increased economic sanctions that affect the energy industry;
 
·  
the general economy, including inflation;
 
·  
the condition of global capital markets;
 
·  
weather and climate conditions in our principal operating areas, including possible disruption of exploration and development activities due to hurricanes and other severe 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;
 
·  
domestic and international tax policies;
 
·  
political and military conflicts in oil-producing areas and the effects of terrorism;                                                                                                                            ;
 
·  
advances in exploration and development technology, such as unconventional drilling and the development of shale resources;
 
·  
the development and exploitation of alternative fuels;
 
·  
further consolidation of our customer base, and
 
·  
further consolidation of our competitors.
 

Our drilling operations have been and will continue to be adversely affected by dramatic declines in oil and natural gas prices, but we cannot predict such events.  Nor can we assure you that a reduction in offshore drilling activity will not occur for other reasons.

An oversupply of drilling units may lead to a reduction in rig utilization and day rates and therefore may materially impact our profitability.
 
During the recent period of high utilization and day rates, industry participants have increased the supply of drilling units by ordering construction of new offshore drilling units.  Historically, this has resulted in an oversupply of drilling units and has


caused a subsequent decline in utilization and day rates when the drilling units have entered the market, sometimes for extended periods of time until the new units have been absorbed into the active fleet.  According to industry sources, there were 481 jack-ups and 84 drillships in the worldwide fleets as of January 23, 2013, and an additional 88 jack-ups and 74 drillships were under construction or on order.  A large number of the drilling units currently under construction have not been contracted for future work, which could intensify price competition as scheduled delivery dates grow near and lead to a reduction in day rates.  Lower utilization and day rates could adversely affect our revenues and profitability.  Prolonged periods of low utilization and day rates could also result in the recognition of impairment charges on our drilling units if future cash flow estimates, based upon information available to management at the time, indicate that their carrying value may not be recoverable. See “Impairment of Long-lived Assets” in Note 2 of Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for information regarding impairment charges recognized in 2012.

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

Our business is capital intensive, and we have significant future commitments to construct additional rigs.
 
Our total estimated project cost for the four ultra-deepwater drillships currently under construction is approximately $3.0 billion, of which approximately $2.2 billion has not yet been incurred.

Construction, enhancement, upgrades, conversions and repairs of rigs and drillships is subject to risks, including delays and cost overruns, which could have an adverse impact on our available cash resources and results of operations.

We have entered into contracts for the construction of four ultra-deepwater newbuild drillships with Hyundai Heavy Industries Co. Ltd. at a cost of approximately $3.0 billion.  All four of our drillships are or will be constructed at Hyundai’s Ulsan shipyard in South Korea.  Although there is certain insurance coverage and financial and bank guarantees associated with the drillship construction contracts, in the event Hyundai is, for any reason, unable to perform under its agreements, 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.  Some of these expenditures could be unplanned. These projects together with our existing construction projects and other efforts of this type are subject to risks of cost overruns or delays inherent in any large construction project 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 of ordered materials and equipment or shipyard construction;
 
 
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;
 
 
shipyard failures and difficulties;
 
 
unanticipated delays in delivery or cost increases of necessary equipment;
 
 
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 drillships or upgrade projects. Delays in the delivery of these drillships 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 newbuilding contracts, such as our contractual rights to recover amounts paid as installments under such contracts. The occurrence of any of these events may have a material adverse effect on our results of operations, financial position or cash flows.

Our markets are highly competitive, and satisfactory price levels are difficult to maintain.

Our drilling markets are highly competitive, and no single participant is dominant.  Some of our competitors may have greater financial or other resources than we do.  The drilling industry has experienced consolidation in the past and may experience additional consolidation, which could create additional competitors larger than us.  Drilling contracts are often awarded on a competitive-bid basis, and intense price competition is frequently the primary factor determining which qualified contractor is awarded the job.  Relocation of offshore rigs from areas of lower activity, such as the US GOM in recent years, to more active international markets has further increased the competition among rigs looking for work in those areas.  The anticipated delivery of 88 new jack-ups and 74 drillships over the next three and seven years, respectively, and ongoing consolidation by oil and gas exploration and production companies will further increase the supply of rigs while reducing the number of available customers.  This consolidation has also resulted in drilling projects being delayed.  We may have to reduce our prices in order to remain competitive, which would have an adverse effect on our operating results and cash flows.

If we or our customers are unable to acquire or renew permits and approvals required for drilling operations, we may be forced to suspend or cease our operations, and our revenues 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, particularly in the US GOM.  If we or our customers are not able to obtain necessary permits and approvals, our operations will be adversely affected.  Obtaining all necessary permits and approvals may necessitate substantial expenditures to comply with the requirements of these permits and approvals, future changes to these permits or approvals, or any adverse change in the interpretation of existing permits and approvals.  In addition, such regulatory requirements and restrictions could also delay or curtail our operations and could have a significant impact on our financial condition or results of operations and may create a risk of expensive delays or loss of value if a project is unable to function as planned due to changing requirements.

In 2010, the Bureau of Ocean Energy Management, Regulation and Enforcement, which was replaced October 1, 2011, by the Bureau of Ocean Energy Management (BOEM) and the Bureau of Safety and Environmental Enforcement (BSEE), issued Notices to Lessees (NTLs) implementing new environmental and safety regulations applicable to drilling operations in the US GOM.  These NTLs have 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.  The BSEE, which is responsible for implementation and enforcement of the new regulations, subsequently issued new regulations in October 2011 which formalized many of the requirements set forth in the NTLs and issued additional environmental and safety requirements in November 2011.  We have been evaluating our own environmental and safety programs and are working with the BSEE, our customers and various industry organizations to meet these requirements; however, compliance with these new regulatory requirements may result in interruption of operations, reduced revenues and higher operating costs.


We are subject to governmental laws and regulations that could expose us to significant costs and liability for environmental and natural resource damages.
 
Many aspects of our operations are subject to governmental regulation, including equipping and operating vessels, drilling practices and methods, and taxation.  In addition, the United States, United Kingdom and other countries in which we operate have regulations relating to environmental protection and pollution control.  We could become liable for damages resulting from pollution of offshore waters and, under United States regulations, we must document financial responsibility.  Generally, we are substantially indemnified under our drilling contracts for pollution damages, except in certain cases of pollution emanating above the surface of water from spills of pollutants, or pollutants emanating from our drilling rigs.  We can provide no assurance, however, that such indemnification provisions can be enforced or will be sufficient to cover potential environmental liabilities.

In the United States, we are subject to the requirements of OSHA and comparable state statutes. OSHA requires us to provide our employees with information about the chemicals used in our operations.  There are comparable requirements in other non-U.S. jurisdictions in which we operate.  Operations in certain areas, such as the North Sea, are highly regulated and have higher compliance and operating costs in general.

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

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

Most of our term drilling contracts are cancelable by the customer without penalty upon the occurrence of events beyond our control, such as the loss or destruction of the rig, or the suspension of drilling operations for a specified period of time as a result of a breakdown of major equipment, and require the customer to pay a termination fee in the event of a cancelation without cause.  Not all of our contracts require the customer to make an early termination payment upon cancellation.  Any early termination payments that may be required under our contracts may not be sufficient to fully compensate us for the loss of the contract and could result in the rig becoming idle for an extended period of time.  Additionally, a customer may be able to obtain a comparable rig at a lower daily rate and seek to renegotiate the terms of its existing drilling contract with us.  In some cases, we may be unable to negotiate or complete definitive contracts following announcements of receipt of letters of intent.  If we or our customers are unable to perform under existing contracts for any reason, our backlog of estimated revenues from drilling contracts would decline and may have a material adverse effect on our operating results, financial position and cash flows.

We have and will likely continue to have certain customer concentrations which increase our risks and may reduce profitability in certain situations.

Our two largest customers, Saudi Aramco and Total, accounted for 29% and 11%, respectively, of our 2012 consolidated revenues.  The loss or material reduction of business from any such significant customer could have a material adverse impact on our results of operations and cash flows.  Moreover, to the extent that we may be dependent on any single customer, we could be subject to the risks faced by that customer to the extent that such risks impede the customer's ability to continue operating and make timely payments to us.

Many of our drilling rigs are subject to damage or destruction by severe weather, and our business may be affected by the threat of severe weather.

Our drilling rigs are located in areas that frequently experience hurricanes or other forms of severe weather conditions and are therefore subject to potential damage or destruction caused by such weather.  Damage caused by high winds and turbulent seas could cause us to suspend operations on drilling rigs for significant periods of time until the damage can be repaired.  Even if our drilling rigs are not damaged or lost due to severe weather, we may still experience disruptions in our operations due to damage to our customers’ platforms and other related facilities.  Additionally our customers may choose not to contract our rigs for use during hurricane season, particularly in the US GOM.  We lost six rigs due to hurricanes in 2002, 2005 and 2008, and another was significantly damaged.  Future storms could result in the loss or damage of additional rigs, which would 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 U.S. Gulf of Mexico.

Hurricanes (or named windstorms) have caused tremendous damage to drilling and production equipment and facilities throughout the Gulf Coast 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 removal of wreckage for these rigs is subject to a $200 million per occurrence deductible.  Losses due to future US GOM named windstorms not covered by insurance could adversely affect our financial position, results of operations and cash flows.

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

Our tax positions are subject to audit by U.K., U.S., and other tax authorities.  The tax authorities 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 transactions we have undertaken.  We could therefore incur material amounts of unrecorded income tax cost if our positions are challenged and we are unsuccessful in defending them.

In 2009, we recognized certain tax benefits as a result of applying the facts of a third-party tax case to our tax situation.  That case provided a more favorable tax treatment for certain foreign contracts entered into in prior years.  Determinations by such authorities that differ materially from our recorded estimates, favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows.  This position is currently under audit and is initially being challenged by the IRS field agents.  We have appealed their findings and expect to come to a conclusion within the next twelve months.  There can be no assurance that we will prevail in our position.

Changes in tax laws and our estimates of income taxes could adversely impact our financial results.
 
Through a merger, on May 4, 2012, we completed a change in our legal domicile from Delaware to the United Kingdom, where we already had substantial operations. As a result of the merger, Rowan UK became the parent company of the Rowan group of companies and our former Delaware parent company, Rowan Delaware, became an indirect, wholly owned subsidiary of Rowan UK.  There are frequently legislative proposals in the United States that attempt to treat companies that have undertaken similar transactions as U.S. corporations subject to U.S. taxes or to limit the tax deductions or tax credits available to United States 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 U.S. Internal Revenue Service 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 non-U.S. subsidiaries to the United States, or by changes in applicable regulations and accounting principles.

Changes in our recorded tax estimates (including estimated reserves for uncertain tax positions) may have a material impact on our results of operations, financial position and cash flows.  We do not provide for deferred income taxes on undistributed earnings of the Company’s non-U.K. subsidiaries, including Rowan Delaware and Rowan Delaware’s non-U.S. subsidiaries.  It is the Company’s policy and intention to permanently reinvest earnings of the non-U.S. subsidiaries of Rowan Delaware outside the U.S.  Should the non-U.S. subsidiaries of Rowan Delaware make a distribution from these earnings, we may be subject to additional U.S. income taxes.

Our foreign operations typically present additional risks, and operations in certain foreign areas present higher costs.

In recent years, we have significantly expanded our operations internationally.  Foreign operations are often subject to political, economic and other uncertainties not typically encountered in domestic operations, including arbitrary taxation policies, onerous customs restrictions, currency exchange fluctuations, security threats including terrorism, piracy and the risk of asset expropriation due to foreign sovereignty over operating areas.  Political unrest in areas in which we have operations, could potentially delay projects, either planned or currently in progress, or could impact us in other unforeseen ways.


In foreign areas where legal protections may be less available to the Company, we assume greater risk that our customer may terminate contracts without cause on short notice, contractually or by governmental action.  Additionally, operations in certain areas, such as the North Sea, are highly regulated and have higher compliance and operating costs in general.

The majority of our transactions are denominated in United States dollars.  In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and limit non-U.S. currency holdings to the extent they are needed to pay liabilities of operations denominated in local currencies.  In certain countries in which we operate however such as Egypt, local laws or contracts may require us to receive payment for a portion of the contract in the local currency.  In such instances, we may hold a greater amount of local currency than would otherwise be the case exposing us to a risk of exchange loss.  We currently do not hedge our foreign currency exposure.

Political disturbances, war, or terrorist attacks and changes in global trade policies and economic sanctions could adversely impact our operations.

As a result of our international operations, including our 12 rigs currently located in the Middle East and Egypt, we 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 of the Middle East or other geographic areas, which may result in extended business interruptions, suspended operations, 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, nationalization, expropriation, confiscation or deprivation of our assets or military action impacting our operations, assets or financial performance in our areas of operations, including the Middle East.

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

Most of our drilling contracts provide for the payment of a fixed day rate during periods of operation, and reduced day rates during periods of other activities.  Our long-term contracts may be at day rates that are lower than day rates then prevailing in the market, and we may be unable to increase day rates to reflect market conditions.  Long-term contracts may also be at day rates that are higher than market day rates, and our revenues may decline at the end of such favorable long-term contracts.   Many of our operating costs are unpredictable and can vary based on events beyond our control, including increased customer and regulatory requirements.  Operators and regulators are requiring higher standards, including increased back-up redundancy systems following the Macondo incident in the US GOM in 2010.  Our margins will therefore vary over the terms of our contracts as a result of applicable day rates and operating costs.  If our costs increase or we encounter unforeseen costs, we may not be able to recover them from our customers, which could adversely affect our financial position, results of operations and cash flows.

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

We do not expect our operating and maintenance costs with respect to our rigs to decline proportionately when rigs are not in service or when day rates decline.  Fixed costs continue to accrue during shipyard, transit and inspection time, which represented approximately 12% of our available rig days in 2012, down from 22% in 2011.   Operating revenue may fluctuate as a function of changes in day rates, but costs for operating a rig are generally fixed or only semi-variable regardless of the day rate being earned.  Additionally, if our rigs are idle between contracts, we typically continue to incur operating and personnel costs because the crew is used to prepare the rig for its next contract.  During times of reduced activity, reductions in costs may not be immediate as portions of the crew may be required to prepare our rigs for stacking.  Moreover, as our rigs are mobilized from one geographic location to another, the labor and other operating and maintenance costs may increase significantly.

There are a limited number of suppliers for certain equipment we use in our business.

As a result of the 2011 sale of LeTourneau, our former oil and gas equipment manufacturing subsidiary, we are more dependent on third-party suppliers for services, parts and equipment we use in our business.  This could result in higher prices for the parts we purchase, the availability of parts, delays in delivery, or poor customer service in general.



High costs associated with maintaining idle rigs may cause us to experience losses, and cold-stacking rigs could result in impairment charges.

During extended periods that rigs are idle, we may choose to cold-stack our rigs.  The Rowan Juneau and the Rowan Alaska, two of our oldest rigs have been cold-stacked since 2010 and the Rowan Paris was stacked in late 2011.  In 2012 we recognized an asset impairment charge on the Rowan Juneau of $5.2 million.  In the event markets deteriorate, we could be exposed to additional impairment charges on operating or stacked rigs and we could be exposed to severance costs in the event we stack additional rigs.

We are subject to operating risks such as blowouts and well fires that could result in environmental damage, property loss, personal injury and death.

Our drilling operations are subject to many hazards that could increase the likelihood of accidents. Accidents can result in:

 
costly delays or cancellations of drilling operations;
 
 
serious damage to or destruction of equipment;
 
 
personal injury or death;
 
 
significant impairment of producing wells, leased properties or underground geological formations; 
 
 
damage to, and loss of use of, the property of others;
 
 
damage to fisheries and 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 2012, as our EXL I rig was being towed prior to mobilizing to Indonesia, a passing tanker collided with the rig.  Repair costs totaled approximately $12 million, all of which we recognized in 2012.  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 patterns or climate 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 drilling formations and towing accidents resulting in lost drilling equipment.  In 2012 a gas leak occurred on an operator’s platform in Scotland where the Rowan Viking was working, and operations were suspended for a period of time.  Any future such events could result in operating losses and have a significant impact on our business.

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

We maintain insurance coverage for damage to our drilling rigs, third-party liability, workers’ compensation and employers’ liability, sudden and accidental pollution and other coverage.  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. The failure of one or more of our insurance providers to meet claim obligations, or losses or liabilities resulting from uninsured or underinsured events could have a material adverse effect on our financial position, results of operations and cash flows.

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

We maintain insurance policies providing coverage for liability associated with negative environmental impacts of a sudden and accidental pollution event, third-party liability, employers’ liability (including Jones Act liability), auto 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 removal-of-rig-wreck due to US GOM named windstorm, which has a self-insured retention of $200 million).

Our rig physical damage and liability insurance renews each June.  Due to recent industry losses, including the Macondo incident in the US GOM, it may be difficult or impossible to secure coverage of a similar nature and with similar limits, or such coverage may be available only at higher costs.


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.

Our customers may be unable or unwilling to indemnify us.

Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they generally agree to protect and indemnify us for liabilities resulting from various hazards associated with the drilling industry,  such as loss of well control, well-bore pollution and damage to subsurface reservoirs.  However, our rights to indemnification may be unenforceable under applicable law or limited by contract.  Our customers may dispute their contractual indemnification obligations to us.  We can provide no assurance that our customers will be financially able to meet these indemnification obligations.  The failure of a customer to meet its indemnification obligations, or losses or liabilities resulting from events excluded from the indemnification obligations could have a material adverse effect on our financial position, results of operations and cash flows.

Rig mobilization, upgrades, enhancements and new construction projects are subject to risks which could cause delays or cost overruns and adversely affect our financial position, results of operations and cash flows.

Rigs moving to a new location and new drilling rigs often experience delays and start-up complications following delivery or other unexpected operational problems that could result in significant uncompensated downtime, reduced day rates or the cancellation or termination of drilling contracts.  Rig mobilizations, upgrades and new rig construction projects are subject to risks of delay or cost overruns, including the following:

 
 
shortages of equipment, materials or skilled labor;
 
 
unscheduled delays in the delivery of ordered materials and equipment or shipyard construction;
 
 
failure of equipment to meet quality and/or performance standards;
 
 
financial or operating difficulties of equipment vendors or the shipyard;
 
 
unanticipated actual or purported change orders;
 
 
inability to obtain required permits or approvals;
 
 
unanticipated cost increases between order and delivery, which can be up to three years;
 
 
adverse weather conditions and other events of force majeure;
 
 
design or engineering changes; and
 
 
work stoppages and other labor disputes.

Unexpected expenses, significant cost overruns or delays could adversely affect our financial position, results of operations and cash flows.  Additionally, failure to complete a project on time may result in the delay or loss of revenue from that rig or make us subject to penalties from the customer, which also could adversely affect our financial position, results of operations and cash flows.

Regulation of greenhouse gases and climate change could have a negative impact on our business.
 
Some scientific studies have suggested that emissions of certain gases, commonly referred to as “greenhouse gases” (GHGs) and including carbon dioxide and methane, may be contributing to warming of the Earth’s atmosphere and other climatic changes.  In response to such studies, the issue of climate change and the effect of GHG emissions, in particular emissions from fossil fuels, is attracting increasing attention worldwide.  International treaties, legislative and regulatory measures to address concerns that emissions of GHGs are contributing to climate change are in various phases of discussions or implementation at the international, national, regional and state levels.

In 2005, the Kyoto Protocol to the 1992 United Nations Framework Convention on Climate Change, which established emission targets for GHGs, became binding on the countries that had ratified it.  International discussions are underway to develop a treaty to replace the Kyoto Protocol, which expired in 2012. The U.S. Congress has considered numerous legislative measures that would have imposed restrictions or costs on greenhouse gas emissions. The current Congress is also considering such legislation. In addition, the EPA has taken steps to regulate GHGs as pollutants under the Clean Air Act (CAA).  To date, the EPA has issued (i) rules requiring the mandatory reporting of greenhouse gases for certain sources including onshore oil and gas operation.; (ii) an "Endangerment Finding" final rule, effective January 14, 2010, which states that current and projected concentrations of six key GHGs in the atmosphere, as well as emissions from new motor vehicles


and new motor vehicle engines, threaten public health and welfare, allowing the EPA to finalize motor vehicle GHG standards (the effect of which could reduce demand for motor fuels refined from crude oil); (iii) a so-called “tailoring rule” such that only GHG from certain large GHG emissions sources will trigger GHG review under the construction and operating permit requirements for stationary sources; and (iv) rules requiring the reduction of methane emissions, a greenhouse gas, at certain oil and gas production operations.

Because our business depends on the level of activity in the oil and natural gas industry, existing or future laws, regulations, treaties or international agreements related to GHGs and climate change, including incentives to conserve energy or use alternative energy sources, could have an adverse impact on our business if such laws, regulations, treaties or international agreements reduce the worldwide demand for oil and natural gas or otherwise result in reduced economic activity generally.  In addition, such laws, regulations, treaties or international agreements could result in increased compliance costs or additional operating restrictions, which may have an adverse impact on our business.  In addition to potential impacts on our business directly or indirectly resulting from climate-change legislation or regulations, our business also could be negatively affected by climate-change related physical changes or changes in weather patterns.  An increase in severe weather patterns could result in damages to or loss of our rigs, impact our ability to conduct our operations and/or result in a disruption of our customers' operations. The effect on our operations could include increased costs to operate and maintain our equipment and facilities, install new emission controls on our equipment or facilities, measure and report our emissions, acquire allowances to authorize our greenhouse gas emissions, pay any taxes related to our greenhouse gas emissions and administer and manage a greenhouse gas emissions program.
 
 Three of our drillships under construction do not yet have drilling contracts.
 
Our ability to meet our cash flow obligations will depend on our ability to consistently secure drilling contracts, including for our new drillships under construction, at sufficiently high day rates. We cannot predict the future level of demand for our drilling units or future conditions in the oil and gas industry.  If oil and gas operators do not continue to increase exploration, development and production expenditures, we may have difficulty securing drilling contracts, or we may be forced to enter into contracts at unattractive day rates.  We have not yet obtained drilling contracts for three of our four drillships under construction. The first non-contracted drillship is due to be delivered in mid-2014.  Failure to secure economical contracts for our drillships under construction prior to delivery could impair our ability to generate sufficient cash flow to meet our capital expenditure and other obligations and negatively impact our operating results and financial position.

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

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

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


Our operations present hazards and risks that require significant oversight, and we depend upon the security and reliability of our technologies, systems and networks in numerous locations where we conduct business.

We depend on technologies, systems and networks to manage our international locations in numerous locations, and our digital technologies may be subject to cybersecurity breaches.  If our systems for protecting against cybersecurity risks prove to be insufficient, we could be adversely affected by having our business and financial systems compromised, our proprietary information altered, lost or stolen, or our business operations and safety procedures disrupted. Such events could impact our financial position, results of operations and cash flows.

Failure to comply with anti-bribery legislation could have an adverse impact on our business.

The U.S. Foreign Corrupt Practices Act (FCPA), the United Kingdom Bribery Act 2010 and similar anti-bribery 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. Although we have programs in place covering compliance with anti-bribery legislation, any failure to comply with the FCPA or other anti-bribery legislation 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 participating in or curtailment of business operations in those jurisdictions and the seizure of rigs or other assets.

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

Certain of our employees and contractors in international markets, such as Trinidad and Norway, are represented by labor unions and work under collective bargaining or similar agreements, which are subject to periodic renegotiation.  Further, efforts may be made from time to time to unionize portions of our workforce. In addition, we may in the future be subject to strikes or work stoppages and other labor disruptions such as the one that occurred for a brief period of time in Trinidad in August 2012. Additional unionization efforts, new collective bargaining agreements or work stoppages could materially increase our costs, reduce our revenues or limit our flexibility.

The expected benefits of the redomestication may not be realized.

We cannot be assured that the benefits of the redomestication will be achieved, particularly those subject to factors beyond our control. These factors include such things as the reactions of third parties with whom we do business and the reactions of investors, analysts and U.K. and U.S. taxing authorities.

We operate through subsidiaries in various countries throughout the world including the United States. We are or may become subject to changes in tax laws, treaties or regulations or the interpretation or enforcement thereof in the U.K., U.S. or any other jurisdictions in which we or any of our subsidiaries operate or are resident. Our income tax expense is based upon our interpretation of the tax laws in effect in various countries at the time that the expense was incurred. If the U.K., U.S., or other taxing authorities successfully challenge our application and/or interpretation of such laws, treaties and regulations or valuations and methodologies or other supporting documentation, we may not experience the level of tax benefits we anticipate or we may be subject to adverse tax consequences, which could have a material adverse effect on us. In addition, our realization of expected tax benefits is based upon the assumption that we take successful planning steps and that we maintain and execute adequate processes to support our planning activities. If we fail to do so, we may not achieve the expected benefits. Even if we are successful in maintaining our positions, we may incur significant expense in contesting positions asserted or claims made by tax authorities.
 
We also could be subject to future audits conducted by various tax authorities, and the resolution of such audits could significantly impact our effective tax rate in future periods, as would any reclassification or other matter (such as changes in applicable accounting rules) that increases the amounts we have provided for income taxes in our consolidated financial statements. There can be no assurance that we would be successful in attempting to mitigate the adverse impacts resulting from any changes in law, audits and other matters. Our inability to mitigate the negative consequences of any changes in the law, audits and other matters could cause our effective tax rate to increase and our results of operations to be negatively impacted.

Our effective tax rates and the benefits are also subject to a variety of other factors, many of which are beyond our ability to control, such as changes in the rate of economic growth in the U.K. and the U.S., the financial performance of our business in various jurisdictions, currency exchange rate fluctuations, and significant changes in trade, monetary or fiscal policies of the U.K. or the U.S., including changes in interest rates.


Further, realization of the logistical and operational benefits of the redomestication is also dependent on a variety of factors including the geographic regions in which our rigs are deployed, the location of the business unit offices that oversee our global offshore contract drilling operations, the locations of our customer's corporate offices and principal areas of operation and the location of our investors. If events or changes in circumstances occur affecting the aforementioned factors, we may not be able to continue to realize the expected logistical and operational benefits of the redomestication.

The enforcement of civil liabilities against Rowan UK may be more difficult.

Because Rowan UK is a public limited company incorporated under English law, investors could experience more difficulty enforcing judgments obtained against Rowan UK 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 (or impossible) to bring some types of claims against Rowan UK 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 UK 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 UK shareholder, together with persons acting in concert, would be at risk of certain Board sanctions if they acquired 30 percent or more of our issued shares without making an offer to all of our other shareholders that is in cash or accompanied by a cash alternative.  The ability of shareholders to retain their shares upon completion of a mandatory offer may depend on whether the offeror subsequently causes us to propose a court-approved scheme of arrangement that would compel minority shareholders to transfer or surrender their shares in favor of the offeror or, if the offeror has acquired at least 90 percent of the relevant shares, the offeror requires minority shareholders to accept the offer under the ‘squeeze-out’ provisions in our articles of association.  The mandatory offer provisions in our articles of association could have the effect of discouraging the acquisition and holding of interests of 30 percent or more of issued shares and encouraging those shareholders who may be acting in concert with respect to the acquisition of shares to seek to obtain the consent of our Board before effecting any additional purchases.  In addition, these provisions may adversely affect the market price of our shares or inhibit fluctuations in the market price of our shares that could otherwise result from actual or rumored takeover attempts.

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

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

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

English law also generally prohibits a company from repurchasing its own shares by way of “off market purchases” without the prior approval of shareholders by special resolution (i.e., 75% of votes cast), which approval lasts for a maximum period of five years. English law prohibits Rowan UK from conducting “on market purchases” as its shares will not be traded on a recognized investment exchange in the U.K.

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

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



We have incurred higher costs as a result of the redomestication and we expect to continue to do so.
 
The redomestication has resulted in an increase in some of our ongoing expenses and requires us to incur some new expenses. Some costs, including those related to holding worldwide operational management meetings and holding board and shareholder meetings in the U.K., are higher than would be the case if we had not redomesticated.  We are also incurring new or increased expenses, including professional fees, to comply with U.K. corporate and tax laws.


The Company has no unresolved Securities and Exchange Commission staff comments.




We lease approximately 112,000 square feet of space in an office tower located at 2800 Post Oak Boulevard in Houston, Texas, as our main office facility.  Additionally, we lease and, in some cases, own other office, maintenance and storage space in Houston and Sabine Pass, Texas; Aberdeen, Scotland; Dammam, Saudi Arabia; Doha, Qatar; Cairo, Egypt; Chaguaramas, Trinidad; Stavanger, Norway; Ulsan, South Korea; Jakarta, Indonesia; Kuala Lumpur, Malaysia, and Singapore.

Drilling Rigs

Following are summaries of the principal drilling equipment owned by the Company and location at February 21, 2013:
           
   
Depth (feet)(1)
     
Rig Name
Class Name/Type
Water
Drilling
Year in Service
Location
           
Ultra-Deepwater Drillships under construction: (2)
         
Rowan Relentless
Gusto MSC P10,000
12,000
40,000
2015 (est.)
Shipyard
Rowan Reliance
Gusto MSC P10,000
12,000
40,000
2015 (est.)
Shipyard
Rowan Resolute
Gusto MSC P10,000
12,000
40,000
2014 (est.)
Shipyard
Rowan Renaissance
Gusto MSC P10,000
12,000
40,000
2014 (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
Norway
Rowan Viking (3)
N-Class
430
35,000
2011
U.K. North Sea
Rowan EXL IV (3)
EXL
350
35,000
2011
Malaysia
Rowan EXL III (3)
EXL
350
35,000
2011
US GOM
Rowan EXL II (3)
EXL
350
35,000
2011
Trinidad
Rowan EXL I (3)
EXL
350
35,000
2010
Indonesia
Joe Douglas (3)
240C
375
35,000
2012
US GOM
Ralph Coffman (3)
240C
375
35,000
2009
Egypt
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
U.K. North Sea
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
Malaysia
Rowan California (3)
116C
300
30,000
1983
Middle East
Cecil Provine (3)
116C
300
30,000
1982
US GOM
Gilbert Rowe (3)
116C
300
30,000
1981/2013(6)
Middle East
Arch Rowan (3)
116C
350
30,000
1981
Middle East
Charles Rowan (3)
116C
350
30,000
1981
Middle East
Rowan Paris (3)
116C
300
30,000
1980
Middle East
Rowan Middletown (3)
116C
300
30,000
1980
Middle East
           
Conventional Jack-ups: (7)
         
Rowan Juneau
Slot
250
30,000
1977
US GOM
Rowan Alaska
Slot
350
30,000
1975
US GOM
Rowan Louisiana (3)
Slot
350
30,000
1975/2006(8)
US GOM
____________

(1)
Indicates rated water and drilling depths.
(2)
High-specification rigs are those that have hook-load capacity of at least two million pounds.
(3)
Unit is equipped with three mud pumps.
(4)
Unit is equipped with four mud pumps.
(5)
Premium jack-ups are cantilevered rigs capable of operating in water depths of 300 feet or more.
(6)
The Gilbert Rowe is undergoing substantial refurbishments and is expected to return to service in the second quarter of 2013.
(7)
Units are equipped with a skid-off capability.  For a discussion of skid-off technology, refer to “Offshore Operations” in Item 1, Business, of this Form 10-K.
(8)
The Rowan Louisiana was damaged during Hurricane Katrina in 2005 and was substantially refurbished in 2006.



On the morning of May 2, 2012, while attempting to enter the Port of Corpus Christi Ship Channel, the tanker M/V FR8 PRIDE lost engine power and propulsion and collided with the Company’s EXL I rig, causing extensive damage to the rig.  As a result of the collision, on May 18, 2012, the Company filed suit in federal court in the Southern District of Texas, Corpus Christi Division, against the M/V FR8 PRIDE, FR8 Pride Shipping Corp. PTE. Ltd. (FR8 Pride Shipping), Thome Ship Management PTE. Ltd. (Thome Ship Management), Scorpio USA LLC, and Scorpio Panamax Tanker Pool Ltd., believed to be the M/V FR8 PRIDE’s owners and operators.  The Company maintains that the M/V FR8 PRIDE failed to properly overtake the EXL I, the mechanical, electrical, and safety systems of M/V FR8 PRIDE were not properly maintained, and that navigational regulations were violated, and seeks damages primarily for repairs to and loss of use of the rig.  The Company has completed repairs to the rig at a cost of approximately $12 million, which has been recognized and included in material charges and other operating expenses in the statement of income.  The EXL I returned to work November 5, 2012, and at this time, the Company is currently assessing amount of its loss-of-use claim associated with this incident, as well as the other monetary damages that may be available under the law. 

In response to the Company’s suit, FR8 Pride Shipping and Thome Ship Management filed a complaint for exoneration from or limitation of liability pursuant to the Limitation of a Shipowner’s Liability Act (the Act) in federal court in the Southern District of Texas, Corpus Christi Division.  Under the Act, a vessel owner is liable only to the extent of the post-accident value of the vessel plus freight pending as long as the incident’s cause(s) were beyond the knowledge or privity of the vessel owner.  Pursuant to the Act, litigation arising from the incident is stayed, and claimants are directed to file their claims in the limitation proceeding.  Additionally, a limitation fund is established, from which legitimate claims are paid.  Limitable claims include those for personal injury, wrongful death, and damage to property.  Ultimately, the court determines whether the vessel and its owner are liable, whether liability should be limited, the amount of just claims, and how to distribute funds to claimants.

In their complaint, the tanker owners contend that the loss of main engine power and the resulting collision were unavoidable accidents. The Company has answered the complaint and filed a claim in the Limitation Action, which parallels its prior-filed suit.  On June 18, 2012, the Court entered an order requiring the tanker owner to post a $20 million bond, which was posted on November 2, 2012.  At this time, both suits are in the preliminary stages of litigation.  The Court has set a trial date of October 14, 2013.  Although we believe the Company’s claims are legally and factually strong, we are unable to predict the ultimate outcome of this litigation.  The repair costs to the EXL I will not be covered by the Company’s insurance because such costs are below our $25 million deductible.  In addition, loss of use is not an insured risk.  In the event the tanker owners are successful in limiting their liability, it is possible that such limitation will not cover our repair costs and loss-of-use damages.

We are from time to time a party to various lawsuits filed by current or former employees that are incidental to our operations in which the claimants seek unspecified amounts of monetary damages for personal injury, including injuries purportedly resulting from exposure to asbestos on our drilling rigs.  At December 31, 2012, there were approximately 18 asbestos related lawsuits in which we are one of many defendants.  These lawsuits have been filed in the state courts of Louisiana, Mississippi and Texas.  We intend to vigorously defend against the litigation.  We are unable to predict the ultimate outcome of these lawsuits; however, we do not believe the ultimate resolution of these matters will have a material adverse effect on our financial position, results of operations or cash flows.  
 
We are involved in various other legal proceedings incidental to our businesses and are vigorously defending our position in all such matters.  We believe that there are no other known contingencies, claims or lawsuits that could have a material adverse effect on our financial position, results of operations or cash flows.
 

Not applicable.


The names, positions and ages of the executive officers of the Company as of March 1, 2013, 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
President and Chief Executive Officer
63
Thomas P. Burke
Chief Operating Officer
45
J. Kevin Bartol
Executive Vice President, Chief Financial Officer and Treasurer
53
John L. Buvens
Executive Vice President, Legal
57
Mark A. Keller
Executive Vice President, Business Development
60
Melanie M. Trent
Senior Vice President, Chief Administrative Officer and Company Secretary
48
Gregory M. Hatfield
Vice President and Controller
43

Since January 2009, Mr. Ralls’ principal occupation has been President and Chief Executive Officer of the Company.  From June 2005 until his retirement in November 2007, Mr. Ralls served as Executive Vice President and Chief Operating Officer of GlobalSantaFe Corporation.  Mr. Ralls also serves on the Boards of Superior Energy Services and Cabot Oil & Gas Corporation.

Dr. Burke became Chief Operating Officer of the Company in July 2011.  He initially joined the Company in December 2009 to serve as President and Chief Executive Officer of LeTourneau Technologies, Inc. and served in such capacity until the sale of LeTourneau in June 2011.  Prior to that time, he was employed by Complete Production Services, Inc., an oilfield services company, as Division President from 2006 to 2009.

Mr. Bartol became Executive Vice President, Chief Financial Officer and Treasurer in September 2012. In July 2012, Mr. Bartol was appointed Executive Vice President, Finance and Corporate Development, and from March 2010 to July 2012, served as Senior Vice President, Corporate Development.  From June 2007 to March 2010, he served as Vice President, Strategic Planning.

Since January 2007, Mr. Buvens’ principal occupation has been Executive Vice President, Legal.

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

Ms. Trent became Senior Vice President, Chief Administrative Officer and Corporate Secretary in 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, and also served as Compliance Officer from 2005 to January 2007 and as Special Assistant to the CEO from January 2007 to December 2008.

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




Our shares are listed on the New York Stock Exchange (NYSE) under the symbol “RDC.”  The following table sets forth the high and low sales prices of our shares for each quarterly period within the two most recent years as reported by the NYSE Consolidated Transaction Reporting System.

 
 
2012
   
2011
 
Quarter
 
High
   
Low
   
High
   
Low
 
First
  $ 39.40     $ 30.78     $ 44.83     $ 32.24  
Second
    36.22       28.62       44.83       35.42  
Third
    39.40       32.08       40.76       30.18  
Fourth
    34.73       30.05       36.71       28.13  

On January 31, 2013, there were 62 shareholders of record.

Restrictive provisions in the Company’s debt agreements require the Company to maintain a minimum level of shareholders’ equity equal to no less than the 100% of the book value of outstanding debt.  The payment of future dividends, if any, would only be paid at the discretion of the Board of Directors.


The graph below presents the relative investment performance of our ordinary shares, the Dow Jones U.S. Oil Equipment and Services Index, and the S&P 500 Index for the five-year period ending December 31, 2012, assuming reinvestment of dividends.
 
 

stock graph

   
12/31/2007
   
12/31/2008
   
12/31/2009
   
12/31/2010
   
12/31/2011
   
12/31/2012
 
                                     
Rowan
    100.00       40.87       58.19       89.73       77.96       80.37  
S&P 500 Index
    100.00       63.00       79.67       91.67       93.61       108.59  
Dow Jones US Oil Equipment & Services Index
    100.00       40.70       67.22       85.60       74.96       75.20  




Issuer Purchases of Equity Securities

The following table summarizes acquisitions of our shares for the fourth quarter of 2012:



Month ended
 
Total number of shares purchased 1
   
Average price paid per share
   
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
                    $ 24,987,408  
October 31, 2012
    -       -       -       24,987,408  
November 30, 2012
    755     $ 32.27       -       24,987,408  
December 31, 2012
    -       -       -       24,987,408  
  Total
    755     $ 32.27       -          
                                 
                                 
1 The total number of shares purchased includes (i) shares purchased, if any, pursuant to a publicly announced share repurchase program described in note 2 below and (ii) shares acquired from employees and non-employee directors by an affiliated Employee Benefit Trust upon forfeiture of nonvested awards or in satisfaction of tax withholding requirements. There were no shares repurchased under the Company's share repurchase program during the fourth quarter of 2012.
 
2 On July 25, 2012, the Board of Directors of Rowan UK, as successor issuer to Rowan Delaware, approved the continuation of the previously announced $150 million share repurchase program, of which approximately $25 million remained available. Share repurchases may be commenced or suspended from time to time without prior notice. Any shares acquired under the share repurchase program will be canceled.
 

For information concerning our shares to be issued in connection with equity compensation plans, see Item 12, “Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters,” of this Form 10-K.




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


   
2012
   
2011
   
2010
   
2009
   
2008
 
         
(Dollars in thousands, except per share amounts)
 
Operations
                             
Revenues
  $ 1,392,607     $ 939,229     $ 1,017,705     $ 1,043,003     $ 1,210,853  
Costs and expenses:
                                       
Direct operating costs (excluding items shown below)
    752,173       508,066       416,832       404,313       480,057  
Depreciation and amortization
    247,900       183,903       138,301       123,940       97,686  
Selling, general and administrative
    99,712       88,278       78,658       65,953       62,006  
(Gain) loss on disposals of property and equipment
    (2,502 )     (1,577 )     402       (5,543 )     (22,996 )
Material charges and other operating expenses (1)
    40,272       10,976       5,250       -       24,635  
Gain on hurricane-related events
    -       -       -       -       (37,088 )
Total costs and expenses
    1,137,555       789,646       639,443       588,663       604,300  
Income from operations
    255,052       149,583       378,262       454,340       606,553  
Other income (expense) — net
    (71,582 )     (19,503 )     (18,727 )     (6,822 )     6,404  
Income from continuing operations, before income taxes
    183,470       130,080       359,535       447,518       612,957  
Provision (benefit) for income taxes
    (19,829 )     (5,659 )     91,934       119,186       207,431  
Income from continuing operations
    203,299       135,739       267,601       328,332       405,526  
Discontinued operations, net of taxes (2)
    (22,697 )     601,102       12,394       39,172       22,102  
Net income
  $ 180,602     $ 736,841     $ 279,995     $ 367,504     $ 427,628  
Basic income per common share:
                                       
Income from continuing operations
  $ 1.65     $ 1.09     $ 2.29     $ 2.89     $ 3.60  
Income from discontinued operations
    (0.18 )     4.80       0.10       0.35       0.20  
Net income
  $ 1.47     $ 5.89     $ 2.39     $ 3.24     $ 3.80  
Diluted income per common share:
                                       
Income from continuing operations
  $ 1.64     $ 1.07     $ 2.25     $ 2.89     $ 3.58  
Income from discontinued operations
    (0.18 )     4.76       0.11       0.35       0.19  
Net income
  $ 1.46     $ 5.83     $ 2.36     $ 3.24     $ 3.77  
                                         
Financial Position
                                       
Cash and cash equivalents
  $ 1,024,008     $ 438,853     $ 437,479     $ 639,681     $ 222,428  
Property, plant and equipment — net
  $ 6,071,729     $ 5,678,713     $ 4,344,522     $ 3,093,591     $ 2,627,906  
Total assets
  $ 7,699,487     $ 6,597,845     $ 6,217,457     $ 5,210,694     $ 4,548,892  
Long-term debt, less current portion
  $ 2,009,598     $ 1,089,335     $ 1,133,745     $ 787,490     $ 355,560  
Stockholders’ equity
  $ 4,531,724     $ 4,325,987     $ 3,752,310     $ 3,110,370     $ 2,659,816  
                                         
Statistical Information
                                       
Current ratio (3)
    5.61       2.46       2.88       2.97       1.82  
Long-term debt/total capitalization
    0.31       0.20       0.23       0.20       0.12  
Book value per share of common stock outstanding
  $ 36.48     $ 35.01     $ 29.71     $ 27.31     $ 23.51  
Price range of common stock:
                                       
High
  $ 39.40     $ 44.83     $ 35.39     $ 27.54     $ 47.94  
Low
  $ 28.62     $ 28.13     $ 20.44     $ 10.28     $ 12.00  
Cash dividends per share
  $ -     $ -     $ -     $ -     $ 0.40  

___________________

(1)
 
Material charges and other operating expenses consisted of the following: 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 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, $2.3 million of incremental noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with the settlement of a 2005 dispute with a customer; 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 and $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee; 2010 – the cost of terminating the Company’s agency agreement in Mexico; and 2008 – $11.8 million of impairment charges for the cancelation of construction of a fourth 240C jack-up rig, $8.5 million of severance costs, $2.8 million of investment banking and legal fees, and $1.5 million for goodwill impairment.
(2)
 
In 2011, the Company sold its manufacturing and land drilling operations.  Operating results for manufacturing and land drilling have been reclassified to discontinued operations for each year presented.
(3)
Current ratio excludes assets and liabilities of discontinued operations.
   



OVERVIEW

Operating results from continuing operations for 2012 reflected the full-year effect of the addition to our fleet of seven newly constructed high-specification jack-up rigs, including three EXL-class rigs and three N-class rigs in 2011, and the Joe Douglas 240-C class rig in early 2012.  Demand for drilling equipment continues to be bifurcated based on rig capabilities.  Utilization of our high-specification jack-ups for 2012 was 91%, compared to 63% and 33% for our premium and conventional jack-ups, respectively.  In 2011 utilization of our high-specification jack-ups was 83%, compared to 49% and 28% for our premium and conventional jack-ups, respectively.  We define high-specification jack-ups as those that have hook load capacity of at least two million pounds and premium jack-ups as those cantilevered rigs capable of operating in water depths of 300 feet or more.

Revenues for 2012 increased by 48% over 2011 to $1.4 billion as a result of the rig additions and higher utilization and day rates for existing rigs.  Net income from continuing operations increased by 50% to $203.3 million.  Included in pretax earnings for 2012 was a loss on debt extinguishment of $22.2 million ($14.4 million after tax).

For 2012, we recognized an income tax benefit of $19.8 million on $183.5 million of pretax income from continuing operations as compared to a benefit of $5.7 million on $130.1 million of pretax income from continuing operations in 2011.  The recognition of income tax benefits in 2012 and 2011 were due in part to the amortization of benefits related to outbounding certain rigs to our non-U.S. subsidiaries in prior years, and with respect to 2012, the implementation of tax planning strategies with regard to capitalized interest.  Also impacting taxes in 2012 and 2011 were the removal of the Company’s manufacturing and land drilling operations, whose earnings were subject to a 35% U.S. statutory rate, and a significant proportion of income earned in lower-tax jurisdictions.  We are currently projecting a 2013 effective income tax expense rate in the single digits.

In 2011 we entered into contracts with Hyundai Heavy Industries Co., Ltd (Hyundai) for the construction of three ultra-deepwater drillships, the Rowan Renaissance, Rowan Resolute and Rowan Reliance, which are scheduled for delivery from the shipyard in December 2013, June 2014 and October 2014, respectively.  In 2012 we exercised our option with Hyundai for the construction of a fourth ultra-deepwater drillship, the Rowan Relentless, which is scheduled for delivery in March 2015.  The agreement with Hyundai also includes an option for a similar fifth drillship exercisable in the first quarter of 2013, for delivery in the third quarter of 2015.  We may seek to extend the option prior to its termination.

As of February 21, 2013, the date of our most recent Fleet Status Report, we had six jack-ups in the North Sea, eleven in the Middle East, seven in the US GOM, three in Malaysia, two in Trinidad and one each in Egypt and Indonesia.  As of that date, ten of our rigs had drilling contracts estimated to be completed in 2013, twelve had contracts estimated to be completed in 2014, six had contracts estimated to be completed in 2015 through 2017, and three were available.  Additionally, the Rowan Renaissance has a three-year contract for initial work in West Africa that is expected to commence in the first quarter of 2014 following its delivery from the shipyard.

RESULTS OF OPERATIONS

Our profitability is primarily a function of our ability to keep our rigs under contract and the operating day rates received, but is also impacted by the level of 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 utilization approaches 90% or more.  When drilling markets are weakening, contractors often reduce day rates in an effort to maintain utilization.  Both rig utilization and day rates have historically declined much faster than they have risen. Our average utilization and day rates by rig classification are presented below:



 
 
   
2012
   
2011
   
2010
 
                   
Utilization: (1)
                 
High specification jack-up (2)
    91 %     83 %     94 %
Premium jack-up(3)
    63 %     49 %     58 %
Conventional jack-up
    33 %     28 %     24 %
                         
Average Day rate: (4)
                       
High specification jack-up (2)
  $ 181,480     $ 169,869     $ 184,332  
Premium jack-up(3)
  $ 94,678     $ 78,972     $ 118,880  
Conventional jack-up
  $ 72,688     $ 58,313     $ 144,985  
                         
(1) Utilization is the number of revenue-producing days divided by the aggregate number of days rigs were available to work.
 
(2) We define high-specification jack-ups as those that have hook load capacity of at least two million pounds.
 
(3) We define premium jack-ups as those cantilevered rigs capable of operating in water depths of 300 feet or more.
 
(4) Average day rate is computed by dividing day rate revenues by the number of revenue-producing days.
 


Current Operations and Markets

Worldwide rig demand 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.

Our primary drilling markets are currently the U.K. and Norwegian sectors of the North Sea, Southeast Asia, Middle East and US GOM. We also have rigs operating in Trinidad and Egypt.  As demand shifts among geographic areas, the Company may from time to time relocate rigs from one major geographic area to another.  During 2011 and 2012, we completed the following major strategic repositionings:

 
From
 
To
2011:
     
Rowan Mississippi
 US GOM
 
 Middle East
Rowan Gorilla II
 US GOM
 
 Malaysia
Rowan Gorilla III
 US GOM
 
 Trinidad
J.P. Bussell
 Egypt
 
 Vietnam
       
2012:
     
Ralph Coffman
 US GOM
 
 Egypt
Rowan EXL I
 US GOM
 
 Indonesia
Rowan EXL IV
 US GOM
 
 Malaysia


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 relatively tight regulatory environment.  Project lead times are often lengthy, and drilling assignments, which typically require ultra-premium equipment capable of handling extreme weather conditions and high down-hole pressures and temperatures, can range from several months to several years.  Drilling activity and day rates in the North Sea move slowly in response to market conditions, and generally follow trends in oil prices.  As of February 21, 2013, industry utilization for jack-up rigs in the North Sea was 95%, and we had six rigs in the U.K. and Norwegian sectors with expected contract completion dates ranging from 2013 through 2017.

The Middle East is a market in which we have had a stable presence in recent years.  As of February 21, 2013, industry utilization in the Middle East for jack-up rigs was 85%, and we had eight rigs under contract in Saudi Arabia, two rigs under


contract in Qatar and one stacked rig in Sharjah, United Arab Emirates.  Eight of our ten rigs working there have contracts estimated to complete in 2014, one has a contract estimated complete in 2015 and the other has a contract estimated to complete in 2016.

The US GOM jack-up drilling market is highly fragmented among many participants, many of which are independent operators whose drilling activities may be highly dependent on near-term operating cash flows.  A typical drilling assignment may call for 60 days of exploration or development work performed under a single-well contract with negotiable renewal options.  Long-term contracts for jack-up rigs have been relatively rare, and generally are available only from the major integrated oil companies and a few of the larger independent operators.  Jack-up drilling demand and day rates in the US GOM have tended to move quickly and generally follow trends in natural gas prices.  Demand in the shallow waters of the US GOM has been relatively weak over the last few years as a result of large supplies of natural gas and relatively low prices.   As of February 21, 2013, industry utilization for jack-up rigs in the US GOM was 58%, and we had seven rigs there – four under contracts estimated to complete in 2013, one estimated to complete in 2014 and two that were stacked.

In late 2011, we reentered the Southeast Asia market after a long absence and currently have four rigs working there – three in Malaysia (including the J.P. Bussell, which worked in Vietnam for most of 2012 prior to relocating to Malaysia in late 2012) and one in Indonesia.  We see increasing opportunities in Southeast Asia due to a strong regional economy, a growing emphasis on higher specification rigs and strong interest in contractors with high-pressure/high-temperature well experience.  Industry utilization for jack-up rigs in Southeast Asia was 86% at February 21, 2013.  Three of our rigs there have contracts estimated to complete in 2013 and one has a contract estimated to complete in 2014.



Key Performance Measures

The following table presents certain key performance measures for our fleet:

                   
   
2012
   
2011
   
2010
 
                   
Revenues (in thousands):
                 
Northern Europe
  $ 491,459     $ 298,027     $ 176,265  
Middle East (1)
    400,359       263,589       283,512  
U.S. Gulf of Mexico
    206,348       260,405       283,308  
Southeast Asia
    135,943       16,560       -  
Other international
    122,159       89,364       256,832  
Subtotal - Day rate revenues
    1,356,268       927,945       999,917  
Other revenues(2)
    36,339       11,284       17,788  
Total
  $ 1,392,607     $ 939,229     $ 1,017,705  
                         
Revenue producing days:
                       
Northern Europe
    2,074       1,424       776  
Middle East (1)
    3,010       2,048       2,012  
U.S. Gulf of Mexico
    1,706       2,227       2,121  
Southeast Asia
    994       136       -  
Other international
    893       696       1,253  
Total
    8,677       6,531       6,162  
                         
Average day rate:(3)
                       
Northern Europe
  $ 236,962     $ 209,289     $ 227,146  
Middle East (1)
  $ 133,010     $ 128,706     $ 140,911  
U.S. Gulf of Mexico
  $ 120,954     $ 116,931     $ 133,573  
Southeast Asia
  $ 136,764     $ 121,765       -  
Other international
  $ 136,796     $ 128,397     $ 204,974  
Total
  $ 156,306     $ 142,083     $ 162,272  
                         
Utilization:(4)
                       
Northern Europe
    94 %     94 %     94 %
Middle East (1)
    75 %     53 %     61 %
U.S. Gulf of Mexico
    59 %     71 %     68 %
Southeast Asia
    79 %     0 %     0 %
Other international
    94 %     59 %     92 %
Total
    77 %     66 %     72 %
                         
(1) Our rigs operating in the Middle East are located in Saudi Arabia and Qatar. We also have a rig operating in Egypt, which is included in "other international."
 
(2) Other revenues, which are primarily revenues received for contract reimbursable costs, are excluded from the computation of average day rate.
 
(3) Average day rate is computed by dividing day rate revenues by the number of revenue-producing days.
 
(4) Utilization is the number of revenue-producing days divided by the aggregate number of days rigs were available to work.
 



2012 Compared to 2011

Our operating results for the years ended December 31, 2012 and 2011 are highlighted below (dollars in millions):


   
2012
   
2011
 
   
Amount
   
% of Revenues
   
Amount
   
% of Revenues
 
                         
Revenues
  $ 1,392.6       100 %   $ 939.2       100 %
Operating costs (excluding items below)
    (752.2 )     -54 %     (508.1 )     -54 %
Depreciation expense
    (247.9 )     -18 %     (183.9 )     -20 %
Selling, general and administrative expenses
    (99.7 )     -7 %     (88.2 )     -9 %
Net gain (loss) on property disposals
    2.5       0 %     1.6       0 %
Material charges and other operating expenses
    (40.2 )     -3 %     (11.0 )     -1 %
Operating income
  $ 255.1       18 %   $ 149.6       16 %


Revenues for 2012 increased by $453.4 million or 48% compared to 2011 as a result of the following (in millions):


   
Increase
 
   
(Decrease)
 
       
Rig additions
  $ 257.4  
Higher utilization of existing rigs
    127.2  
Higher average day rates for existing rigs
    43.8  
Revenues for reimbursable costs and other, net
    25.0  
Net increase
  $ 453.4  

The addition of seven newbuild rigs to the fleet in 2011 and 2012 contributed 1,198 incremental revenue-producing days in 2012 (14% of total revenue-producing days) over 2011.

Operating costs other than depreciation, selling, general and administrative expenses and material charges and other operating expenses for 2012 increased by $244.1 million or 48% over the prior year, as a result of the following (in millions):


   
Increase
 
   
(Decrease)
 
       
Operating costs attributable to fleet additions
  $ 112.6  
Higher operating costs of rigs previously in shipyard or in transit
    63.0  
Expansion of foreign shorebases
    32.9  
Reimbursable expenses
    24.9  
Other, net
    10.7  
Net increase
  $ 244.1  


Our operating margin (revenues in excess of operating costs, other than depreciation, selling, general and administrative expenses and material charges and other operating expenses) was approximately 46% of revenues in both 2012 and 2011.  Depreciation increased by $64.0 million or 35% over 2011 due to the rig additions.  Selling, general and administrative expenses increased by $11.5 million or 13% primarily due to increases in personnel and related costs in connection with the expansion of operations in 2011 and 2012 and to increases in professional fees.

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 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, $2.3 million of incremental


noncash share-based compensation cost in connection with the retirement of an employee, partially offset by a $4.7 million gain for cash received in connection with a legal settlement.

Material charges and other operating expenses for 2011 consisted of a $6.1 million charge for the settlement of litigation in connection with the 2005 loss of the Rowan Halifax and a cash and noncash charge of $4.9 million for incremental compensation cost in connection with the separation of an employee.

For 2012, we recognized an income tax benefit of $19.8 million on $183.5 million of pretax income from continuing operations as compared to a benefit of $5.7 million on $130.1 million of pretax income from continuing operations in 2011. The recognition of income tax benefits in 2012 and 2011 were due in part to the amortization of benefits related to outbounding certain rigs to our non-U.S. subsidiaries in prior years, and with respect to 2012, the implementation of tax planning strategies with regard to capitalized interest. Also impacting taxes in 2012 and 2011 were the removal of the Company’s manufacturing and land drilling operations, whose earnings were subject to a 35% U.S. statutory rate, and a significant proportion of income earned in lower-tax jurisdictions. We are currently projecting a 2013 effective income tax expense rate in the single digits.

2011 Compared to 2010

Our operating results for the years ended December 31, 2011 and 2010 are highlighted below (dollars in millions):


   
2011
   
2010
 
   
Amount
   
% of Revenues
   
Amount
   
% of Revenues
 
                         
Revenues
  $ 939.2       100 %   $ 1,017.7       100 %
Operating costs (excluding items below)
    (508.1 )     -54 %     (416.8 )     -41 %
Depreciation expense
    (183.9 )     -20 %     (138.3 )     -14 %
Selling, general and administrative expenses
    (88.2 )     -9 %     (78.6 )     -8 %
Net gain (loss) on property disposals
    1.6       0 %     (0.4 )     0 %
Material charges and other operating expenses
    (11.0 )     -1 %     (5.3 )     -1 %
Operating income
  $ 149.6       16 %   $ 378.3       37 %


Revenues for 2011 decreased by $78.5 million or 8% compared to 2010 as a result of the following (in millions):


   
Increase
 
   
(Decrease)
 
       
Rig additions
  $ 234.9  
Lower average day rates for existing rigs
    (159.7 )
Lower utilization of existing rigs
    (147.2 )
Revenues for reimbursable costs and other, net
    (6.5 )
Net decrease
  $ (78.5 )

Newbuild additions to the fleet in 2010 and 2011 contributed 1,267 (or 21%) incremental revenue-producing days in 2011 over 2010.  During the year, we had nine rigs moving to, or preparing for, new contracts, and several of those projects took longer than anticipated.  We estimate that approximately 22% of our available rig days in 2011 were spent by rigs in shipyards or in transit, which contributed to the lower utilization of existing rigs in 2011.  The conclusion on long-term, higher day rate contracts in 2010 and 2011 contributed to the lower average day rates for existing rigs in 2011.

Operating costs other than depreciation, selling, general and administrative expenses and material charges and other operating expenses for 2011 increased by $91.3 million or 22% over the prior year, as a result of the following (in millions):

   
Increase
 
   
(Decrease)
 
       
Operating costs attributable to fleet additions
  $ 86.7  
Worker's compensation
    8.8  
Lower operating costs for Gorilla VI in the U.K. versus Norway
    (14.7 )
Lower operating costs due to rigs in shipyard, net
    (7.4 )
Other, net
    17.9  
Net increase
  $ 91.3  

Operating margin (revenues in excess of operating costs other than depreciation, selling, general and administrative expenses and material charges and other operating expenses) declined to 46% of revenues in from 59% in 2010 primarily as a result of lower average day rates for and utilization of existing rigs, which more than offset the impact of fleet additions over the


periods.  Depreciation expense increased by $45.6 million or 33% between periods due to the rig additions.  Selling, general and administrative expenses increased by $9.6 million or 12% due primarily to higher labor costs and tax consulting fees.

In 2011, we settled litigation with Textron relating to the loss of the Rowan Halifax in 2005 and charged operations for a payment of $6.1 million.  Also in 2011, we recognized $4.9 million of incremental noncash and cash compensation cost in connection with the separation of an employee.  Such amounts comprise the “Material charges and other operating expenses.”

Material charges and other operating expenses in 2010 consisted of a $5.3 million charge to operations for the cost of terminating the Company’s agency agreement in Mexico.

Outlook

Our backlog by geographic area as of the date of our most recent “Monthly Fleet Status Report,” compared to our backlog as reported in our 2011 Form 10-K, is set forth below.  Backlog at February 21, 2013, for the US GOM and West Africa includes $452 million and $226 million, respectively, for the Rowan Renaissance, which is currently under construction and expected to enter service in the first quarter of 2014 (in millions):


   
February 21, 2013
   
February 27, 2012
 
             
Northern Europe
  $ 1,599     $ 1,646  
Middle East
    790       949  
U.S. Gulf of Mexico
    594       109  
West Africa
    226       -  
Southeast Asia
    183       57  
Other international
    203       304  
    $ 3,595     $ 3,065  


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

       
2013
  $ 1,116  
2014
    1,060  
2015
    726  
2016
    574  
2017
    119  
Total backlog
  $ 3,595  

About 66% of our remaining available rig days in 2013 and 42% of available days in 2014 were under contract or commitment as of February 21, 2013.

Our collective shipyard, transit and inspection time declined to 12% of our available rig days in 2012 from 22% in 2011.  Shipyard and transit time in 2011 was negatively impacted due to a number of strategic mobilizations of rigs between geographic areas and the start-up of six newly constructed rigs.  We currently expect shipyard, transit and inspection time to consume approximately 10% of our available rig days in 2013, a slight improvement compared to 2012.



LIQUIDITY AND CAPITAL RESOURCES

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


   
2012
   
2011
 
             
Cash and cash equivalents
  $ 1,024.0     $ 438.9  
Current assets (excluding assets of discontinued operations)
  $ 1,529.6     $ 794.1  
Current liabilities (excluding liabilities of discontinued operations)
  $ 272.8     $ 323.4  
Current ratio (excluding assets and liabilities of discontinued operations)
    5.61       2.46  
Current maturities of long-term debt
  $ -     $ 45.0  
Long-term debt, less current maturities
  $ 2,009.6     $ 1,089.3  
Shareholders' equity
  $ 4,531.7     $ 4,326.0  
Long-term debt/total capitalization
    0.31       0.20  

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

   
2012
   
2011
   
2010
 
                   
Net operating cash flows
  $ 393.7     $ 94.7     $ 508.2  
Borrowings, net of issue costs
    1,102.9       -       395.5  
Capital expenditures
    (685.2 )     (1,517.7 )     (490.6 )
Debt repayments
    (238.5 )     (52.2 )     (594.0 )
Proceeds from asset disposals
    10.5       5.7       3.3  
Proceeds from equity compensation plans
    0.6       19.9       8.0  
Proceeds from sales of manufacturing and land drilling operations, net
    -       1,555.5       -  
Payments to acquire treasury stock
    -       (125.0 )     -  
Net change in restricted cash balance
    -       15.3       (15.3 )
Net cash used in acquisition of SKDP
    -       -       (17.7 )
All other, net
    1.2       5.2       0.4  
   Total sources (uses)
  $ 585.2     $ 1.4     $ (202.2 )

Operating Cash Flows

Cash flows from operations increased to approximately $394 million in 2012 from $95 million in 2011, and were in excess of $508 million for 2010.  Operating cash flows for all of 2010 and for part of 2011 included those attributable to our former manufacturing and land drilling businesses, which we sold in June and September of 2011, respectively.  As discussed in Note 1 of Notes to Consolidated Financial Statements, the Company has chosen not to separately disclose cash flows pertaining to discontinued operations in its statement of cash flows, as permitted under US GAAP.  Operating cash flows for 2012 were positively impacted by the addition of seven newbuild rigs to the fleet in 2011 and 2012. Cash flows from operations for 2010 benefited from long-term contracts entered into in earlier years when rates were significantly higher.

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

As of December 31, 2012, unremitted earnings of Rowan Delaware were approximately $2,453 million, and unremitted earnings of Rowan Delaware’s non-U.S. subsidiaries were approximately $400 million.  Should non-U.S. subsidiaries of Rowan Delaware 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 a deferred tax liability related to the undistributed earnings, and Rowan Delaware has no plan to distribute earnings in a manner that would cause those earnings to be subject to U.S., U.K. or other local country taxation.

At December 31, 2012, Rowan Delaware and Rowan Delaware’s non-U.S. subsidiaries held approximately $228 million and $176 million, respectively, of the $1.0 billion of consolidated cash and cash equivalents.   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 our policy of reinvesting such undistributed earnings outside the U.K. and U.S. indefinitely.

Investing Activities

In 2011 we entered into contracts with Hyundai Heavy Industries Co., Ltd for the construction of three ultra-deepwater drillships, the Rowan Renaissance, Rowan Resolute and Rowan Reliance, which are scheduled for delivery in December 2013, June 2014 and October 2014, respectively.  In 2012 we exercised our option with Hyundai for the construction of a fourth ultra-deepwater drillship, the Rowan Relentless, which is scheduled for delivery in March 2015.  The agreement with Hyundai also includes an option for a similar fifth drillship exercisable in the first quarter of 2013, for delivery in the third quarter of 2015.  We may seek to extend the option prior to its termination.  Reference should be made to Note 7 of Notes to Consolidated Financial Statements in this Form 10-K for the status of our newbuild rig projects.

Capital expenditures in 2012 totaled $685 million and included the following:

·  
$287 million towards construction of the ultra-deepwater drillships 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.

We currently estimate our 2013 capital expenditures to be approximately $1.3 billion, including $826 million towards construction of the four ultra-deepwater drillships, $275 million for life enhancement projects and existing fleet maintenance capital, $190 million for partially reimbursed contractual modifications to the jack-up fleet, and $54 million for equipment spares, drill pipe and improvements to our shore bases.

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

We expect to fund our newbuild drillship program and other capital expenditures from available cash, cash flows from operations, amounts available under our revolving credit facility, if required, and potential future financings.

Financing Activities

In April 2012, the U.S. Department of Transportation Maritime Administration (MarAd), which had previously guaranteed certain of the Company’s debt securities under the Title XI Federal Ship Financing Program (the Title XI Notes), denied the Company’s request for consent with respect to a parent company guarantee in connection with the Company’s redomestication.  As a result, the Company redeemed $226.1 million aggregate principal amount of the Title XI Notes in 2012 for $251.5 million in cash, including principal, make-whole premiums and accrued interest, and recognized a pretax loss on debt extinguishment of $22.2 million, including $0.7 million of noncash deferred financing costs.

In connection with the redomestication, on May 4, 2012, Rowan UK became a party to and a borrower and guarantor under the credit facility, dated September 16, 2010, among Rowan Delaware, Wells Fargo Bank, National Association, as administrative agent and lender, and certain other lenders.  Rowan UK entered into a guaranty in favor of the administrative agent for the benefit of the lenders whereby Rowan UK fully and unconditionally guarantees the obligations of Rowan Delaware under the credit facility.

On May 21, 2012, Rowan UK, as guarantor, and its 100% owned subsidiary, Rowan Delaware, as issuer, completed the issuance and sale in a public offering of $500 million aggregate principal amount of 4.875% Senior Notes due 2022 (the 4.875% Notes), at a price to the public of 99.333% of the principal amount.  Net proceeds were approximately $493 million, which were used, in part, to replenish cash used to redeem the Title XI Notes.

On December 11, 2012, Rowan UK, as guarantor, and its 100% owned subsidiary, Rowan Delaware, as issuer, completed the issuance and sale in a public offering of $200 million aggregate principal amount of 4.875% Senior Notes due 2022 at a price to the public of 109.007% of the principal amount and $400 million aggregate principal amount of 5.4% Senior Notes due 2042 at a price to the public of 99.575% of the principal amount (the “December offering”).  The 4.875% Senior Notes issued in December 2012 were offered as additional notes under the indenture governing the $500 million principal amount of notes


of the same series issued in May 2012.  Net proceeds of the December offering were approximately $611 million, which will be used in the Company’s rig construction program and for general corporate purposes.

The 4.875% Notes and the 5.4% Notes will mature on June 1, 2022, and December 1, 2042, respectively.  Interest on the 4.875% Notes and the 5.4% Notes is payable semi-annually on June 1 and December 1 of each year.
 
The 4.875% Notes and the 5.4% Notes are Rowan Delaware’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 Rowan Delaware’s existing and future senior indebtedness, including its 5% Senior Notes due 2017, 7.875% Senior Notes due 2019, and any indebtedness under Rowan Delaware’s senior revolving credit facility.  The 4.875% Notes and the 5.4% Notes rank effectively junior to Rowan Delaware’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 Rowan Delaware).

All or part of the 4.875% Notes and 5.4% 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.  There will be no make-whole premium applicable to the redemption of the 4.875% Notes on or after March 1, 2022, or applicable to redemption of the 5.4% Notes on or after June 1, 2042.

On December 4, 2012, the Company entered into the third amendment to the credit agreement dated September 16, 2010, that, among other things, increased the borrowing capacity under the revolving credit facility from $500 million to $750 million and provides for an accordion feature that would permit the borrowing capacity to be increased to a maximum of $1.0 billion, subject to the consent of the lenders.  There were no amounts drawn under the revolving credit facility at December 31, 2012.

As of December 31, 2012, we had $2.0 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; and $400 million principal amount of 5.4% Senior Notes due 2042 (together, the “Senior Notes”).  The Senior Notes are fully and unconditionally guaranteed on a senior and unsecured basis by Rowan UK (see Note 15 of Notes to Financial Statements).  Annual interest payments on the Senior Notes total $117 million.  No principal payments are required until each series’ final maturity date.  Management believes that cash flows from operating activities and existing cash balances will be sufficient to satisfy all of the Company’s cash requirements for the following 12 months.

Our debt agreements contain provisions that limit the amount of long-term debt, 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, 2012, and expects to remain in compliance throughout 2013.

Cash Dividends

Restrictive provisions in the Company’s debt agreements require the Company to maintain a minimum level of shareholders’ equity equal to no less than the 100% of the book value of outstanding debt.  The payment of future dividends, if any, would only be paid at the discretion of the Board of Directors.

Off-balance Sheet Arrangements and Contractual Obligations

The Company had no off-balance sheet arrangements as of December 31, 2012 or 2011, 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, 2012, including obligations recognized on our balance sheet and those not required to be recognized (in millions):



   
Payments due by period
 
   
Total
   
Within 1 year
   
2 to 3 years
   
4 to 5 years
   
After 5 years
 
                               
Long-term debt, including interest
  $ 3,367     $ 117     $ 233     $ 634     $ 2,383  
Newbuild construction contracts
    2,213       751       1,462       -       -  
Purchase obligations
    703       703       -       -       -  
Operating leases
    33       5       9       8       11  
Total
  $ 6,316     $ 1,576     $ 1,704     $ 642     $ 2,394  


We periodically employ letters of credit or other bank-issued guarantees in the normal course of our businesses, and had outstanding letters of credit of approximately $33 million at December 31, 2012.

Pension Obligations

Minimum contributions under defined benefit pension plans are determined based upon actuarial calculations of pension assets and liabilities that involve, among other things, assumptions about long-term asset returns and interest rates.  Similar calculations were used to estimate pension costs and obligations as reflected in our consolidated financial statements (see “Critical Accounting Policies and Management Estimates – Pension and other postretirement benefits).  As of December 31, 2012, our financial statements reflected an aggregate unfunded pension liability of $238 million.  We expect to make minimum contributions to our defined benefit pension plans of approximately $19 million in 2013, and we will continue to make significant pension contributions over the next several years.  Additional funding may be required if pension asset values decline.

Contingent Liabilities

We are involved in various legal proceedings incidental to our businesses and are vigorously defending our position in all such matters. The Company believes that there are no known contingencies, claims or lawsuits that could have a material effect on its financial position, results of operations or cash flows.

CRITICAL ACCOUNTING POLICIES AND MANAGEMENT ESTIMATES

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

Impairment of long-lived assets

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.



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, 2012, included weighted average discount rates of 4.17% and 4.58% used to determine pension benefit obligations and net cost, respectively, an expected long-term rate of return on pension plan assets of 8% and annual healthcare cost increases ranging from 8.1% in 2013 to 4.5% in 2029 and beyond.  The assumed discount rate is based upon the average yield for Moody’s Aa-rated corporate bonds and the rate of return assumption reflects a probability distribution of expected long-term returns that is weighted based upon plan asset allocations.  A one-percentage-point decrease in the assumed discount rate would increase our recorded pension and other postretirement benefit liabilities by approximately $118 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 $4.6 million.  A one-percentage-point increase in the assumed healthcare cost trend rate would increase 2013 other postretirement benefit cost by $0.4 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 maintained at 8% at December 31, 2012, unchanged from December 31, 2011.

Income taxes

In accordance with accounting guidelines for income tax uncertainties, we evaluate each tax position to determine if it is more likely than not that the tax position will be sustained upon examination, based on its merits.  A tax position that meets the more-likely-than-not recognition threshold is subject to a measurement assessment to determine the amount of benefit to recognize in income for the period, and a reserve, if any.  Our income tax returns are subject to audit by U.S. federal, state, and foreign tax authorities.  Determinations by such taxing authorities that differ materially from our recorded estimates, either favorably or unfavorably, may have a material impact on our results of operations, financial position and cash flows.  We believe our reserve for uncertain tax positions totaling $58.9 million at December 31, 2012, is properly recorded in accordance with the accounting guidelines.



Our outstanding debt at December 31, 2012, consisted entirely of fixed-rate debt with a carrying value of $2.010 billion and a weighted-average annual interest rate of 5.7%.  Due to the fixed-rate nature of our debt, management believes the risk of loss due to changes in market interest rates is not material.

The majority of our transactions are denominated in United States dollars. Our primary exposure to currency exchange is the British pound.  In order to reduce the impact of exchange rate fluctuations, we generally require customer payments to be in U.S. dollars and generally limit local currency holdings to the extent they are needed to pay liabilities denominated in local currencies.  In certain countries in which we operate however such as Egypt, local laws or contracts may require us to receive payment for a portion of the contract in the local currency.  In such instances, we may hold a greater amount of local currency than would otherwise be the case.  We currently do not hedge our foreign currency exposure.

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.
 
 




INDEX
Page 
   
Report of Independent Registered Public Accounting Firm
40
Management’s Report On Internal Control Over Financial Reporting
41
Report of Independent Registered Public Accounting Firm
42
Consolidated Balance Sheets, December 31, 2012 and 2011
43
Consolidated Statements of Income for the Years Ended December 31, 2012, 2011 and 2010
44
Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2012, 2011 and 2010
45
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2012, 2011 and 2010
46
Consolidated Statements of Cash Flows for the Years Ended December 31, 2012, 2011 and 2010
47
Notes to Consolidated Financial Statements
48
Selected Quarterly Financial Data (Unaudited)
81



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas
 
We have audited the accompanying consolidated balance sheets of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2012 and 2011, and the related consolidated statements of income, comprehensive income, changes in shareholders' equity, and cash flows for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Rowan Companies plc and subsidiaries at December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 1 to the consolidated financial statements, on May 4, 2012, Rowan Companies plc, a public limited company incorporated under the laws of England and Wales, became the successor issuer to Rowan Companies, Inc. pursuant to an agreement and plan of merger and reorganization approved by the shareholders of Rowan Companies, Inc. on April 16, 2012.  Also, as discussed in Note 3 to the consolidated financial statements, on June 22, 2011, and September 1, 2011, the Company completed the sale of its wholly owned manufacturing subsidiary, LeTourneau Technologies, Inc., and land drilling services business, respectively.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2013, expressed an unqualified opinion on the Company's internal control over financial reporting.
 
/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 1, 2013


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) 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, 2012.

The registered public accounting firm Deloitte & Touche LLP has audited Rowan’s consolidated financial statements included in our 2012 Annual Report on Form 10-K and has issued an attestation report on the Company’s internal control over financial reporting.

/s/  W. MATT RALLS                                                          
/s/ J. KEVIN BARTOL                                                               
W. Matt Ralls
J. Kevin Bartol
President and Chief Executive Officer
Executive Vice President, Chief Financial Officer and Treasurer
   
   
March 1, 2013
March 1, 2013



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of
Rowan Companies plc
Houston, Texas

We have audited the internal control over financial reporting of Rowan Companies plc and subsidiaries (the "Company") as of December 31, 2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting Pursuant to Section 404 of the Sarbanes-Oxley Act of 2002. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

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

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

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

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework 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, 2012 of the Company and our report dated March 1, 2013,  expressed an unqualified opinion on those financial statements and included an explanatory paragraph regarding Rowan Companies plc, a public limited company incorporated under the laws of England and Wales, becoming the successor issuer to Rowan Companies, Inc. pursuant to an agreement and plan of merger and reorganization approved by the shareholders of Rowan Companies, Inc. on April 16, 2012.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas
March 1, 2013



ROWAN COMPANIES PLC

CONSOLIDATED BALANCE SHEETS


   
December 31,
 
   
2012
   
2011
 
   
(In thousands, except share amounts)
 
ASSETS
 
CURRENT ASSETS:
           
Cash and cash equivalents
  $ 1,024,008     $ 438,853  
Receivables - trade and other
    423,839       283,592  
Prepaid expenses and other current assets
    55,121       44,586  
Deferred income taxes - net
    26,628       27,023  
Assets of discontinued operations
    22,954       27,661  
Total current assets
    1,552,550       821,715  
                 
PROPERTY, PLANT AND EQUIPMENT:
               
Drilling equipment
    6,764,046       6,179,587  
Construction in progress
    756,308       711,558  
Other property and equipment
    140,739       138,177  
Property, plant and equipment - gross
    7,661,093       7,029,322  
Less accumulated depreciation and amortization
    1,589,364       1,350,609  
Property, plant  and equipment - net
    6,071,729       5,678,713  
                 
Other assets
    75,208       97,417  
                 
TOTAL ASSETS
  $ 7,699,487     $ 6,597,845  
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
 
CURRENT LIABILITIES:
               
Current maturities of long-term debt
  $ -     $ 45,023  
Accounts payable - trade
    83,004       111,082  
Deferred revenues
    52,340       36,220  
Accrued liabilities
    137,495       131,041  
Liabilities of discontinued operations
    21,255       25,005  
Total current liabilities
    294,094       348,371  
                 
Long-term debt - less current maturities
    2,009,598       1,089,335  
Other liabilities
    390,199       357,709  
Deferred income taxes - net
    473,872       476,443  
Commitments and contingent liabilities (Note 7)
    -       -  
                 
SHAREHOLDERS' EQUITY:
               
Class A Ordinary Shares, $0.125 par value, 124,740,407 shares issued at December 31, 2012
    15,593       -  
Common stock, $0.125 par value, 150,000,000 shares authorized and 127,577,530 shares issued at December 31, 2011
    -       15,947  
Additional paid-in capital
    1,372,135       1,478,233  
Retained earnings
    3,366,964       3,186,362  
Cost of 529,387 and 3,996,465 treasury shares at December 31, 2012 and 2011, respectively
    (1,886 )     (128,884 )
Accumulated other comprehensive loss
    (221,082 )     (225,671 )
Total shareholders' equity
    4,531,724       4,325,987  
                 
TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY
  $ 7,699,487     $ 6,597,845  


See Notes to Consolidated Financial Statements.


ROWAN COMPANIES PLC

CONSOLIDATED STATEMENTS OF INCOME


   
Years ended December 31,
 
   
2012
   
2011
   
2010
 
   
(In thousands, except per share amounts)
 
                   
REVENUES
  $ 1,392,607     $ 939,229     $ 1,017,705  
                         
COSTS AND EXPENSES:
                       
Direct operating costs (excluding items below)
    752,173       508,066       416,832  
Depreciation and amortization
    247,900       183,903       138,301  
Selling, general and administrative
    99,712       88,278       78,658  
(Gain) loss on disposals of  property and equipment
    (2,502 )     (1,577 )     402  
Material charges and other operating expenses
    40,272       10,976       5,250  
Total costs and expenses
    1,137,555