UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C.
20549
FORM 10-K
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R
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ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the year ended December 31, 2009
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OR
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£
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TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
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For
the transition period from __________ to
__________
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Commission
File Number: 1-5491
ROWAN
COMPANIES, INC.
(Exact
name of registrant as specified in its charter)
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Delaware
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75-0759420
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(State
or other jurisdiction of incorporation or organization)
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(I.R.S.
Employer Identification No.)
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2800 Post
Oak Boulevard, Suite 5450
Houston,
Texas 77056-6189
Registrant’s
telephone number, including area code: (713) 621-7800
Securities
registered pursuant to Section 12(b) of the Act:
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Title of each class
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Name of each exchange on which
registered
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Common
Stock, $0.125 par value
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New
York Stock Exchange
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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. £
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 the voting stock held by non-affiliates of the
registrant was approximately $2.2 billion as of June 30, 2009, based
upon the closing price of the registrant’s Common Stock on the New York Stock
Exchange Composite Tape of $19.32 per share.
The
number of shares of Common Stock, $0.125 par value, outstanding at February
26, 2010 was 113,834,940.
DOCUMENTS
INCORPORATED BY REFERENCE
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Document
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Part of Form 10-K
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Portions
of the Proxy Statement for the 2010 Annual Meeting of
Stockholders
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Part III,
Items 10-14
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FORWARD-LOOKING
STATEMENTS
This Form
10-K contains “forward-looking statements” as defined by the Securities and
Exchange Commission (“SEC”). Such statements are those concerning
contemplated transactions and strategic plans, expectations and objectives for
future operations. These include, without limitation:
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statements,
other than statements of historical fact, that address activities, events
or developments that we expect, believe or anticipate will or may occur in
the future;
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statements
relating to future financial performance, future capital sources and other
matters; and
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any
other statements preceded by, followed by or that include the words
“anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,”
“projects,” “could,” “should,” “may,” or similar
expressions.
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Although
we believe that our plans, intentions and expectations reflected in or suggested
by the forward-looking statements we make in this Form 10-K are reasonable, we
can give no assurance that such plans, intentions and expectations will be
achieved. These statements are based on assumptions made by us based
on our experience and perception of historical trends, current conditions,
expected future developments and other factors that we believe are appropriate
in the circumstances. Such statements are subject to a number of
risks and uncertainties, many of which are beyond our control. You
are cautioned that any such statements are not guarantees of future performance
and that actual results or developments may differ materially from those
projected in the forward-looking statements. Among the factors that could cause
actual results to differ materially are the following:
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demand
for drilling services, in the United States and
abroad
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demand
and prices for oil, natural gas and other
commodities
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the
level of exploration and development expenditures by energy
companies
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the
willingness and ability of the Organization of Petroleum Exporting
Countries, or OPEC, to limit production levels and influence
prices
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the
level of production in non-OPEC
countries
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the
general economy, including
inflation
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the
condition of global capital markets
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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
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environmental
and other laws and regulations
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policies
of various governments regarding exploration and development of their oil
and natural gas reserves
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domestic
and international tax policies
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political
and military conflicts in oil-producing areas and the effects of
terrorism
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advances
in exploration and development
technology
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further
consolidation of our customer base
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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.
Other
relevant factors are included in Item 1A, “Risk Factors,” of this Form
10-K.
Rowan
Companies, Inc. (“Rowan” or the “Company”) is a major provider of international
and domestic contract drilling services. Rowan also owns and operates a
manufacturing division that produces equipment for the drilling, mining and
timber industries. Organized in 1947 as a Delaware corporation under the name
Rowan Drilling Company, Inc., Rowan is a successor to a contract drilling
business conducted since 1923.
Information
with respect to Rowan’s revenues, operating income, assets, and other financial
information relating to the Company’s business segments and geographic areas of
operation is presented in Note 10 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.
Rowan
provides contract drilling services utilizing a fleet of 23 self-elevating
mobile offshore drilling platforms (“jack-up rigs”) and 29
marketed deep-well land drilling rigs. Our primary focus is on
high-specification and premium jack-up rigs, which our customers use for
offshore exploratory and development drilling and, in certain areas, well
workover operations.
We
conduct offshore drilling operations in various markets throughout the world,
and onshore drilling operations in the United States. At February 16,
2010, we had nine offshore rigs in the Middle East, eight in the U.S. Gulf of
Mexico, two in the North Sea, and one each offshore West Africa, Eastern Canada,
Mexico and Egypt. At that date, we had twenty-one marketed land rigs
in Texas, six in Louisiana, and one each in Oklahoma and Alaska.
During
2009, our drilling operations generated revenues of $1,214.9 million and income
from operations of $472.1 million, compared with $1,451.6 million and $670.1
million, respectively, in 2008. 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.
Rowan
operates 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 floating hull that is
fully equipped to serve as a drilling platform supported by three independently
elevating legs. The rig is towed to the drilling site where the legs are lowered
until they penetrate the ocean floor, and the hull is jacked up to the elevation
required to drill the well. Each of our jack-ups was designed and
built by our manufacturing division.
We have
aggressively grown our jack-up fleet over the past decade to better serve the
needs of the industry for drilling in harsher environments, 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 greatly accelerate the drilling process. Most have been
designed or upgraded to handle the toughest environmental
criteria. At February 16, 2010, our offshore drilling fleet was
comprised of the following:
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Eleven
high-specification cantilever jack-up rigs, including one
harsh-environment Gorilla class rig, four
enhanced Super
Gorilla class rigs, four Tarzan Class rigs and
two 240C 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 to handle the casing strings
required to drill beyond 30,000
feet.
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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.
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Three
conventional or slot jack-up rigs with skid-off capability, as described
below.
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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 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 four
Super Gorilla class
rigs were delivered during the period from 1998 to 2003 and are enhanced
versions of our Gorilla
class rigs featuring simultaneous drilling and production
capabilities. 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 (formerly the
Gorilla VIII), is an enhanced version
of the Super Gorilla
class jack-up designated a Super Gorilla
XL. With 713 feet of leg,
139 feet more than the Super Gorillas, and 30%
larger spud cans, this rig can operate in water depths to 550 feet in
relatively benign environments like the Gulf of Mexico or in water depths to
400 feet in the hostile environments of the North Sea and offshore eastern
Canada and West Africa.
Our four
Tarzan Class rigs were
specifically designed for deep-well, HPHT drilling in up to 300 feet of water in
benign environments.
Our 240C class rigs are designed
for HPHT drilling in water depths to 400 feet. Construction of
the first 240C, the
Rowan-Mississippi, was
completed in the fourth quarter of 2008, and the second rig, the Ralph Coffman, was delivered
in the fourth quarter of 2009. The third 240C jack-up, the Joe Douglas, is currently
under construction with delivery expected in the third quarter of
2011.
Additionally,
we have four EXL class
rigs under construction at the Keppel AmFELS, Inc. (“Keppel”) shipyard in
Brownsville, Texas, with expected deliveries of three rigs in 2010 and one in
early 2012. Our EXL
class rigs will 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 will be equipped with the hook-load and horsepower required to
efficiently drill beyond 30,000 feet.
In
addition to our offshore drilling operations, we provide drilling equipment and
personnel on a contract basis for exploration and development of onshore
areas. At February 16, 2010, our onshore fleet consisted of 29
marketed deep-well land rigs, 28 of which are 2,000 HP or greater and capable of
drilling wells to 35,000 feet, and 19 of which are AC drive. These premium
specifications are ideal for targeting shale and gas plays such as the
Haynesville and Deep Bossier in Louisiana and Texas.
See Item
2, “Properties,” of this Form 10-K for additional information with respect
to the rigs in our fleets.
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 four 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
minimal amounts required to meet local expenses.
A number
of factors affect our ability to obtain contracts, both onshore and offshore, at
profitable rates within a given area. Such factors, which are
detailed below 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
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. As of
February 16, 2010, ten of our offshore rigs were operating under drilling
contracts estimated to complete in 2010, eight had contracts estimated to
complete in 2011, one had a contract estimated to complete in 2012, and four
were without contracts. The five rigs currently under construction
are expected to be delivered over the period from early 2010 through early
2012. We have a contract for the use of one rig, and the remaining
four are not yet contracted.
Our
drilling revenue backlog was estimated to be approximately $1.3 billion at
February 16, 2010, down from approximately $1.7 billion one year earlier.
The
contract drilling industry is highly competitive, and success in obtaining
contracts involves many factors, including price, equipment capability,
operating and safety performance and reputation. We believe that
Rowan competes favorably with respect to all of these factors.
Currently,
we compete with several offshore drilling contractors that together have close
to 700 mobile rigs available worldwide, including approximately 460
jack-ups. We estimate that 26 or less than 6% of the world’s existing
jack-up fleet are high-specification, including the eleven rigs that we
own. Sixty-one additional jack-up rigs are under construction for
delivery through 2012, eleven of which are considered high-specification,
including all five of our rigs.
Our
onshore operations compete with several domestic drilling contractors that have
approximately 250 deep-well land rigs available. Based on the number
of rigs as tabulated by ODS-Petrodata, Rowan is the seventh largest offshore
drilling contractor in the world and the fifth largest jack-up rig
operator. 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, many smaller 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.
Rowan’s
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. 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.
Much of
the Gulf of Mexico, the North Sea and offshore eastern Canada frequently
experience hurricanes or other extreme weather conditions. Many of
our offshore drilling rigs are located in these areas and are thus subject to
potential damage or destruction by such conditions. 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. Additionally, even if our drilling rigs are not damaged or
lost in such conditions, we may still experience disruptions in our operations
due to damage to our customer’s platforms and other related facilities in these
areas.
Hurricanes
(or “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 windstorm coverage available and have dramatically increased the
cost 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 hurricane losses has also been limited. Any ongoing
change in weather patterns or climate could further increase costs and reduce
availability of insurance coverage for windstorms.
Rowan
suffered a significant loss of prospective revenues and has incurred significant
claims for removal of wreckage from the total destruction of six rigs in four
separate storms from 2002 through 2008. Due to the increased cost and
reduced availability of coverage as discussed above, in 2009 we decided to
discontinue windstorm physical damage coverage on four of our older,
lower-specification jack-up rigs, and our coverage for removal of wreckage is
subject to a $100 million per occurrence deductible. Currently, our
windstorm physical damage coverage is subject to a $50 million per occurrence
deductible with an annual aggregate limit of $150 million and covers only the
Gorilla II, the Bob Palmer and the Rowan-Mississippi.
We seek
to maintain adequate insurance coverage for worker’s compensation, maritime
employer’s liability, automobile liability and various other types of exposures
customarily encountered in our operations. Certain of our liability
insurance policies specifically exclude coverage for fines, penalties and
punitive or exemplary damages. We can give no assurance that
insurance coverage will continue to be available at rates considered reasonable,
that self-insured amounts or deductibles will not increase or that certain types
of coverage will be available at any cost. We renew our insurance
policies annually, and the level of coverage that we maintain is reevaluated
each year based on a variety of factors. We can provide no assurance
that we will maintain future coverage at current levels.
Foreign
operations are often subject to political, economic and other uncertainties not
encountered in domestic operations, such as arbitrary taxation policies, onerous
customs restrictions, unstable currencies, exchange rate fluctuations and the
risk of asset expropriation due to foreign sovereignty over operating
areas. We attempt to minimize the risk of currency fluctuations by
generally contracting for payment in U.S. dollars and limit our holdings of
foreign currencies to amounts needed to cover local expenditures. As
our international operations have grown in recent years, exchange rate and other
risks of operating internationally have become more significant.
Many
aspects of our operations are subject to governmental regulation in the areas of
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. Rowan could become liable for damages resulting from
pollution of offshore waters and, under United States regulations, we must
document financial responsibility. Generally, we are indemnified
under our drilling contracts for pollution damages, except in certain cases of
pollution emanating above the surface of land or 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.
During
2004, we learned that the Environmental and Natural Resources Division,
Environmental Crimes Section of the U.S. Department of Justice (“DOJ”) had
begun conducting a criminal investigation of environmental matters involving
several of our offshore drilling rigs that at various times operated in the Gulf
of Mexico. In late 2007, we entered into a plea agreement with the
DOJ, as amended, under which we paid fines and made community service payments
totaling $9 million and agreed to be subject to unsupervised probation for
a period of three years. During this period we must ensure that we
commit no further criminal violations of federal, state, or local laws or
regulations and must also continue to implement our comprehensive Environmental
Management System Plan. Concurrent with the plea agreement, the
Environmental Protection Agency approved a compliance agreement with us which,
among other things, contains a certification that the conditions giving rise to
the violations to which we entered guilty pleas have been
corrected. We believe that if we fully comply with the terms of the
compliance agreement, we will not be suspended or debarred from entering into or
participating in contracts with the U.S. Government or any of its
agencies.
We
believe we are in compliance in all material respects with the health, safety
and environmental regulations affecting the operation of our rigs and the
drilling of oil and gas wells in the countries and jurisdictions in which we
operate. Except as discussed above, regulatory compliance has not
materially affected our capital expenditures, earnings or competitive position
to date, although such measures do 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.
In the
United States, Rowan is 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.
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.
Our
manufacturing operations are conducted by LeTourneau Technologies, Inc.
(“LeTourneau”), a wholly-owned subsidiary of the Company headquartered in
Longview, Texas. LeTourneau has two operating segments: Drilling
Products and Systems and Mining, Forestry and Steel Products, each of which
serves markets that require large-scale, steel-intensive, high load-bearing
products and related parts and services.
In 2009,
our manufacturing operations reported external revenues of $555.3 million and
income from operations of $28.9 million, compared with revenues of $761.1
million and a loss from operations of $12.0 million in 2008. Results
for 2008 included material charges and other operating expenses of $86.5
million, which are set forth in Note 11 of “Notes to Consolidated Financial
Statements” in Item 8 of this Form 10-K. Our backlog of external
manufacturing orders totaled approximately $413 million at
December 31, 2009, nearly all of which is scheduled for delivery in 2010,
compared with $562 million at December 31, 2008. Our
manufacturing results of operations and backlog are further discussed in
“Management’s Discussion and Analysis of Financial Condition and Results of
Operations” in Item 7 of this Form 10-K.
Our
Drilling Products and Systems segment built the first jack-up drilling rig in
1955, and has since designed, built or licensed the construction of more than
200 units including all 23 of our current jack-up rigs. This segment
also designs and manufactures primary drilling equipment in a wide range of
sizes, including mud pumps, top drives, drawworks and rotary tables, as well as
variable-speed motors, variable-frequency drive systems and other electrical
components for the oil and gas, marine, mining and dredging
industries. We also manufacture complete land rigs and related
drilling equipment packages.
Drilling
Products and Systems completed construction of our second 240C class jack-up in
December 2009 and is currently constructing our third 240C class jack-up, the Joe Douglas, at our
Vicksburg, Mississippi, shipyard for delivery in the third quarter of
2011. Our Longview, Texas, facility is providing the rig kit (design,
legs, jacking system, cranes and other equipment) and certain drilling equipment
for each of the EXL
class jack-ups being built for Rowan by Keppel.
The
Vicksburg facility is dedicated primarily to vessel construction for the
offshore drilling industry, and is heavily dependent upon demand for offshore
jack-up rigs. We currently have no further plans for rig construction
in Vicksburg following the delivery of the Joe Douglas in
2011. Absent additional orders or sufficient prospects for future
work, the activities at the facility would be significantly reduced at that
time, in which case we would incur additional costs such as employee
severance, among other charges. Closing or significantly reducing
activity levels at the facility could result in the incurrence of cash charges
ranging from $5 million to $6 million and noncash charges ranging from $7
million to $10 million. Rig component manufacturing, rig repair
services and design engineering continue to be performed at our Longview
facility.
Our
Mining, Forestry and Steel Products segment manufactures heavy equipment such as
large-wheeled front-end loaders, diesel-electric powered log stackers and steel
plate products.
Our
mining loaders feature bucket capacities up to 53 cubic yards, which are the
largest in the industry. LeTourneau loaders are generally used in
coal, copper, and iron ore mines, and utilize a proprietary diesel-electric
drive system with digital controls. This system allows large, mobile
equipment to stop, start and reverse direction without gear shifting and
high-maintenance braking. LeTourneau’s wheeled loaders can load
rear-dump trucks in the 85-ton to 400-ton range. Our log stackers
offer two- or four-wheel drive configurations and load capacities ranging from
35 to 55 tons.
Mining
products and parts are distributed through our own distribution network serving
the western United States, Australia, Canada, China and Brazil as well as
through a worldwide network of independent dealers. These dealers
have agreements to sell our products to end-users and provide follow-up service
and parts directly to those end-users. We focus on after-market parts
and components for the repair and maintenance of our machines and market these
items through the same dealer network. Global sites for parts
stocking, rebuilding and service include approximately 60 locations on six
continents.
From our
mini-mill in Longview, Texas, we recycle scrap metal and produce carbon, alloy
and tool steel plate products for internal needs as well as external
customers. We concentrate on niche markets that require higher-end
alloy steel grades, including mold steels, aircraft-quality steels and
resulfurized and boron grades. Sales consist primarily of steel
plate, but also include value-added fabrication of steel
products. Our products are generally sold to steel service centers,
fabricators and manufacturers through a direct sales force. Plate
products are sold throughout North America while sales of fabricated products
are more regional, encompassing Texas, Oklahoma, Louisiana, Mississippi and
Arkansas. Carbon and alloy plate products are also used internally in
the production of equipment and parts.
We
conduct ongoing research and product development, primarily to increase the
capacity and performance of our product lines on a continuous improvement basis,
and routinely evaluate our products and after-market applications for potential
enhancements.
We offer
warranties and parts guarantees extending for stipulated periods of ownership or
hours of usage, whichever occurs first. In most cases, dealers of our
products perform the warranty work. For drilling equipment, we
generally perform warranty work directly and accrue for estimated future
warranty costs based on historical experience.
The
principal raw material used in our manufacturing operations is steel plate, much
of which is supplied by our Longview mini-mill. Other required
materials are generally available in sufficient quantities to meet our
manufacturing needs through purchases in the open market, and we do not believe
that we are dependent on any single supplier.
Since
1955, when the first LeTourneau jack-up was delivered, LeTourneau has been
recognized as a leading designer and builder of jack-up drilling rigs, having
designed or built approximately one-third of all jack-ups currently in operation
worldwide. We believe there are currently 61 jack-ups under
construction worldwide, 11 of which are LeTourneau designs. At
present, we have a limited number of competitors in jack-up rig design, though
several shipyard facilities have emerged in recent years to provide jack-up rig
construction and repair services, and some of these competitors are
significantly larger than LeTourneau.
We
encounter significant competition in the drilling equipment
market. The leading competitor in the mud pump market is estimated to
have more than a 50% share of the market. Our shares of the top
drive, drawworks, rotary table and land rig markets are not
significant.
We have
four major steel plate competitors. Our share of the overall steel
market is small, but we are very competitive in certain niche applications for
high-strength alloy, thick plate. Internal requirements for steel
plate provide a base load for the steel mill.
We
encounter competition worldwide from several sources in mining
products. Our wheeled loader product lines have a number of
competitors. In forestry, our log stackers have four major
competitors.
Our
competition in the sale of after-market parts for mining and forestry products
is fragmented, with only three other companies considered to be direct
competitors. Vendors supplying parts directly to end-users and others
who obtain and copy the parts for cheaper and lower-quality substitutes provide
more intense competition to us than do direct competitors.
Our
jack-up rig designs are subject to regulatory approval by various agencies,
depending on the geographic areas where the rig will be qualified for
drilling. Other than the approvals that classify the jack-up as a
vessel, the rules relate primarily to safety and environmental issues, vary by
location and are subject to frequent change.
In the
United States, our manufacturing operations and facilities are subject to
regulation by a variety of local, state, and federal agencies with authority
over safety and environmental compliance. These include the
Environmental Protection Agency (“EPA”), OSHA, and other state and local
jurisdictions with comparable statutes. Internationally, our
operations and facilities are subject to comparable regulations in the countries
in which we operate.
We have
the required permits at our manufacturing facilities for wastewater discharges,
solid waste disposal and air emissions. Our manufacturing operations may
generate waste products which are considered hazardous by the EPA or
other governmental agencies. We properly contain and dispose of these
waste products at approved waste disposal facilities.
In
the event
we experience an unplanned release of waste products, we may be liable for
damages from any air, water or land pollution that may result. We believe
that our compliance with environmental protection laws and regulations will
have no material effect on our capital expenditures, earnings or competitive
position during 2010. Further regulations may reasonably be
anticipated, but any effects on our manufacturing operations cannot be
accurately predicted at this time.
As a
manufacturing company, we may be responsible for certain risks associated with
the use of our products. These risks include product liability claims
for personal injury and/or death, property damage, loss of product use, business
interruption and necessary legal expenses to defend us against such
claims. We carry insurance, and we believe we are adequately covered
for such risks.
At
December 31, 2009, we had 4,846 employees, as compared to 6,023 and 5,704 at
December 31, 2008 and 2007, respectively. Included in these
numbers are citizens of the United States and other countries. None of our
employees are covered by collective bargaining agreements with labor
unions. We consider relations with our employees to be
satisfactory.
One
drilling customer, Saudi Aramco, accounted for 15% of consolidated revenues in
each of 2009 and 2008, and 13% in 2007.
Historically,
our manufacturing customer base has been diverse, and none of our product lines
are highly dependent on any one customer or small group of
customers.
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 common stock.
We operate in volatile businesses
that are 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:
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fluctuations
in worldwide demand for oil and natural
gas
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the
willingness and ability of the Organization of Petroleum Exporting
Countries, or “OPEC,” to limit production levels and influence
prices;
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political
and military conflicts in oil-producing areas and the effects of
terrorism;
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the
level of production in non-OPEC
countries;
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laws,
regulations and policies of various governments regarding exploration and
development of their oil and natural gas
reserves;
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domestic
and international tax policies;
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disruption
of exploration and development activities due to hurricanes and other
severe weather conditions;
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advances
in exploration and development technology;
and
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further
consolidation of our customer base
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Our
drilling operations have been and will continue to be adversely affected by
dramatic declines in oil and natural gas prices, as occurred in late 2008 and
early 2009, but we cannot predict the extent of that effect. Nor can
we assure you that a reduction in offshore drilling activity will not occur for
other reasons. Our Manufacturing operations are also dependent on commodity
prices and financial market conditions which affect demand for rigs and related
components, mining and timber equipment and after-market
parts.
The
delivery of new offshore drilling rigs currently under construction may further
reduce our rig utilization and day rates and could lead to impairment
charges.
We
believe there are currently 61 competitive jack-up rigs under construction
worldwide, or approximately 13% of the existing fleet. Most of these
rigs do not have drilling contracts in place, and their delivery will increase
the supply of available rigs competing for work, which could further reduce rig
utilization and day rates. In addition, many of these rigs will
likely enter the market at a time of excess capacity and low day
rates. Prolonged periods of low rig utilization require us to accept
lower day rates, or may cause us to temporarily take rigs out of service, or
“stack” rigs, which would adversely affect our operating results and cash
flows. We may be required to recognize impairment charges on our
drilling rigs if future cash flow estimates, based upon information available to
management at the time, indicate that their carrying values may not be
recoverable.
Our
markets are highly competitive, and satisfactory price levels are difficult to
maintain.
Our
drilling and manufacturing markets are highly competitive, and no single
participant is dominant. Drilling contracts are often awarded on a
competitive bid basis, with intense price competition frequently being the
primary factor determining which qualified contractor is awarded the
job. Relocation of offshore rigs from areas of lower activity, such
as the U.S. Gulf of Mexico, to more active international markets has further
increased the competition among rigs looking for work in those
areas. The anticipated delivery of 61 new jack-ups over the next
three years 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 further reduce our prices in
order to remain competitive, which would have an adverse effect on our operating
results.
Our
rigs under construction do not yet have drilling contracts.
We have
not yet obtained drilling contracts for four of our rigs under
construction. Failure to secure economical contracts for them prior
to delivery could negatively impact our operating results.
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.
Much of
the Gulf of Mexico, the North Sea and offshore eastern Canada frequently
experience hurricanes or other extreme weather conditions. Many of
our offshore drilling rigs are located in these areas and are thus subject to
potential damage or destruction by such conditions. 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 by such
conditions, we may still experience disruptions in our operations due to damage
to our customers’ platforms and other related facilities in these
areas. Additionally our customers may choose not to contract our rigs
for use during hurricane season, particularly our conventional rigs in the Gulf
of Mexico. During Hurricanes Katrina and Rita in 2005, we lost four
jack-up rigs and another was significantly damaged. During Hurricane
Ike in 2008, we lost one jack-up rig. 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.
Our
insurance coverage for windstorms may be inadequate, has become more expensive,
and may become unavailable or cost-prohibitive.
Hurricanes
(or “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 windstorm coverage available and have dramatically increased the
cost 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 hurricane losses has also been limited.
As a
result of the increased cost and reduced availability of coverage, in 2009 we
decided to discontinue windstorm physical damage coverage on four of our older,
less capable jack-up rigs, and our current coverage for removal of wreckage is
subject to a $100 million per occurrence deductible. Currently, our
windstorm physical damage coverage is subject to a $50 million per occurrence
deductible with an annual aggregate limit of $150 million and covers only the
Gorilla II, the Bob Palmer and the Rowan-Mississippi. Losses
due to future windstorms not covered by insurance could adversely affect our
financial position, results of operations and cash flows. We renew
our rig insurance policies annually each April. The level of coverage
that we maintain is reevaluated each year based on a variety of factors, and we
can provide no assurance that we will maintain future coverage at current
levels.
Taxing
authorities may challenge our tax positions, and we may not be able to realize
expected benefits.
In 2009,
we recognized tax benefits of $25 million as a result of applying our facts to a
recent third-party tax case that provides a more favorable tax treatment for
certain foreign contracts entered into in prior years. 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.
Our
foreign operations typically present additional risk, 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,
foreign currency exchange fluctuations, security threats including terrorism,
and the risk of asset expropriation due to foreign sovereignty over operating
areas. With regard to the risk that our customer may terminate
contracts without cause on short notice, contractually or by governmental
action, we assume greater risks of such events in foreign areas, where legal
protections may be less available to the Company. Any such unforeseen
events could have a material adverse effect on our financial position, results
of operations and cash flows. Additionally, operations in certain
foreign areas, such as the North Sea, are highly regulated and have higher
compliance and operating costs in general.
Most of our contracts are fixed-price
contracts, and increases in our operating costs or the impact of any
general inflation 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,
and our manufacturing contracts typically provide for a fixed
price. Many of our operating costs are unpredictable and can vary
based on events beyond our control. Our gross margins will therefore
vary over the terms of our contracts. 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.
High
costs associated with maintaining idle rigs may cause us to experience losses,
and cold-stacking rigs may result in impairment charges.
In the
past, Rowan generally has not cold-stacked its offshore drilling rigs during
extended idle periods, as the long-term costs of rehiring and retraining
personnel and restarting equipment typically negate any short-term
savings. As noted previously, however, we have recently cold-stacked
the Rowan-Juneau, one
of our oldest rigs. Should we cold-stack additional idle rigs, we
could be exposed to additional severance costs and potential impairment charges
from reductions in the fair value of our equipment.
Deterioration
in global capital markets reduces customer spending and results in lower demand
for our products and services and reduced or delayed collections of expected
revenues.
Weakness
in global capital markets, coupled with declining oil and natural gas prices,
have caused a number of oil and gas producers to reduce operating and capital
budgets, cancel projects or large purchases and/or slow the payment of
receivables in an effort to preserve liquidity. Many of our customers
have approached us in an effort to cancel contracts, reduce rates and prices or
extend payment terms. We can provide no assurance that all of our
receivables will be collected.
We
will experience reduced profitability if our customers terminate or seek to
renegotiate our drilling contracts.
Some of
our drilling contracts are cancelable by the customer upon specific notice, or
upon the occurrence of events beyond our control, such as the loss or
destruction of the rig due to weather, or the suspension of drilling operations
for a specified period of time as a result of a breakdown of major
equipment. 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, in weak market conditions, 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.
Weakness
in global capital markets may limit our ability to meet our future capital
needs.
At
December 31, 2009, we had $640 million of cash and equivalents plus a $155
million revolving credit facility to be used, if necessary, for general
corporate purposes, including capital expenditures and debt service
requirements. Given the volatility in global capital markets, it is
possible our credit facility will not be available when and if
required. Lack of access to capital may limit our ability to expand
our businesses, engage in acquisitions or otherwise take advantage of business
opportunities.
We are subject to operating risks
such as blowouts and well fires that could result in environmental damage, property
loss, personal injury and death, some of which may not be covered by insurance or
recoverable indemnification.
Our
drilling operations are subject to many hazards that could increase the
likelihood of accidents. Accidents can result in:
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costly
delays or cancellations of drilling
operations;
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serious
damage to or destruction of
equipment;
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personal
injury or death;
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significant
impairment of producing wells, leased properties or underground geological
formations; and
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major
environmental damage.
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Our
offshore drilling operations are also subject to marine hazards, whether at
drilling sites or while equipment is under tow, such as vessel capsizings,
collisions or groundings. In addition, raising and lowering jack-up
rigs and drilling into high-pressure formations are complex, hazardous
activities, and we frequently encounter problems. Any ongoing change
in weather patterns or climate could increase the adverse impact of marine
hazards.
Our
manufacturing processes could pollute the air, land, and inland waters, and the
products we manufacture could be implicated in lawsuits alleging environmental
harm, property loss, personal injury and death.
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. Any future such events could result in operating losses
and have a significant adverse impact on our business.
We
have a significant insurance receivable related to the salvage of several
offshore drilling rigs lost or damaged during recent hurricanes.
During
2005, we lost four offshore rigs, including the Rowan-Halifax, and incurred
significant damage on a fifth as a result of Hurricanes Katrina and
Rita. We also lost another offshore rig during Hurricane Ike in
2008. Since 2005, we have been working to locate the lost rigs,
salvage related equipment, remove debris, wreckage and pollutants from the
water, mark or clear navigational hazards and clear rights of way. As
of December 31, 2009, we had incurred $229 million of costs related to such
efforts, of which $199 million had been reimbursed through insurance, leaving
$30 million included in receivables. Some of these expenditures may
not be reimbursed by our insurance coverage, which could have a material adverse
effect on our financial position, results of operations and cash
flows.
Our four Super Gorilla class rigs and
two of our Tarzan Class rigs are pledged as security under our
government-guaranteed debt arrangements.
If
operating conditions deteriorate and if market conditions were to remain
depressed for a long period of time, our results of operations would suffer, and
working capital and other financial resources may not be available or adequate
to service our outstanding debt. Our four Super Gorilla class jack-ups
and two of our Tarzan Class
jack-ups are pledged as security under our government-guaranteed debt
arrangements. If we were unable to service our debt, it is possible
that these assets could be removed from our fleet, in which case our ability to
generate sufficient revenues and cash flows would be significantly
reduced.
Changes
to our inventory valuation allowances may reduce our future operating
results.
We
recognize valuation allowances against our inventories based on historical usage
of inventory on hand, assumptions about future demand based on market
conditions, and estimates about potential alternative uses, which are usually
limited. Our inventories generally consist of spare parts, work in
process, and raw materials to support ongoing manufacturing operations and our
installed base of drilling, mining and timber equipment. Customers
rely on us to stock these specialized items to ensure that their equipment can
be repaired and serviced in a timely manner. The estimated carrying
values of our inventories are therefore indirectly affected by demand for oil,
natural gas and other commodities, general economic conditions worldwide, and
the potential obsolescence of various types of equipment we sell, among other
factors. As a result of the 2008 declines in oil and natural gas
prices, the onset of global recession and weakness in capital markets, we
reduced our estimates of future usage of our inventories and significantly
increased our inventory reserves at December 31, 2008.
Further
deterioration in worldwide demand for oil, natural gas and certain other
commodities, or the development of new technologies which make older drilling,
mining and timber technologies obsolete, could require us to record additional
reserves to reduce the value of our inventory and reduce our future operating
results.
Rig 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.
New
drilling rigs may experience 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 construction projects are subject to risks of delay or
cost overruns inherent in any large construction project from numerous factors,
including the following:
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shortages
of equipment, materials or skilled
labor;
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unscheduled
delays in the delivery of ordered materials and equipment or shipyard
construction;
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failure
of equipment to meet quality and/or performance
standards;
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financial
or operating difficulties of equipment vendors or the
shipyard;
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unanticipated
actual or purported change orders;
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inability
to obtain required permits or
approvals;
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unanticipated
cost increases between order and delivery, which can be up to two
years;
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adverse
weather conditions and other events of force
majeure;
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design
or engineering changes; and
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work
stoppages and other labor disputes.
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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 of revenue from that rig, which also
could adversely affect our financial position, results of operations and cash
flows.
Our
customers may be unable 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. We can provide no assurance, however, that our customers
will be financially able to meet these indemnification
obligations. The failure of a customer to meet such obligations, the
failure of one or more of our insurance providers to meet claim obligations, or
losses or liabilities resulting from unindemnified, uninsured or underinsured
events could have a material adverse effect on our financial position, results
of operations and cash flows.
We
are subject to governmental laws and regulations that could cause significant
costs and liability on us for environmental and natural resource
damages.
Many
aspects of our operations are subject to governmental regulation in the areas of
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. Rowan 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 land or 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.
In late
2007, we entered into a plea agreement with the Environmental and Natural
Resources Division, Environmental Crimes Section of the U.S. Department of
Justice, as amended, under which we paid fines and made community service
payments totaling $9 million. Additionally, we agreed
to be subject to unsupervised probation for a period of three years in
connection with a criminal investigation of environmental matters involving
several of our offshore drilling rigs that at various times operated in the Gulf
of Mexico. During the probation period we must ensure that we commit
no further criminal violations of federal, state, or local laws or regulations
and must also continue to implement our comprehensive Environmental Management
System Plan.
In the
United States, Rowan is 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.
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.
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. 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. We currently operate one of our rigs
in eastern Canada, which is one of the countries that ratified the Kyoto
Protocol. International discussions are underway to develop a treaty
to replace the Kyoto Protocol after its expiration in
2012.
In the
United States, federal legislation imposing restrictions on GHGs is under
consideration. Proposed legislation has been introduced that would
establish an economy-wide cap on emissions of GHGs and would require most
sources of GHG emissions to obtain GHG emission “allowances” corresponding to
their annual emissions. In addition, the EPA is taking steps that
would result in the regulation of GHGs as pollutants under the Clean Air Act
(“CAA”). To date, the EPA has issued (i) a “Mandatory Reporting of
Greenhouse Gases” final rule, effective December 29, 2009, which establishes a
new comprehensive scheme requiring operators of stationary sources in the United
States emitting more than established annual thresholds of carbon
dioxide-equivalent GHGs to inventory and report their GHG emissions annually;
and (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). Finally, according to the EPA, the final
motor vehicle GHG standards will trigger construction and operating permit
requirements for stationary sources. As a result, the EPA has
proposed to tailor these programs such that only large stationary sources will
be required to have air permits that authorize GHG emissions.
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 customer's
operations.
Also, on
June 26, 2009, the U.S. House of Representatives passed “American Clean
Energy and Security Act of 2009” or ACESA, which would establish an economy-wide
cap-and-trade program to reduce U.S. emissions of “greenhouse
gases.” The net effect of ACESA would be to impose increasing
costs on the combustion of carbon-based fuels such as oil, refined petroleum
products, and natural gas. The U.S. Senate has begun work on its own
legislation for restricting domestic greenhouse gas emissions, and the Obama
Administration has indicated its support of legislation to reduce greenhouse
gas
emissions
through an emission allowance system. Although it is not possible at this
time to predict when the Senate may act on climate change legislation or how any
bill passed by the Senate would be reconciled with ACESA, the adoption and
implementation of any CAA regulations, and any future federal, state or local
laws or implementing regulations that may be adopted to address greenhouse gas
emissions, could require us to incur increased operating costs and could
adversely affect demand for oil and natural gas and our services. 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.
Anti-takeover provisions in our
Certificate of Incorporation and bylaws could make it difficult for holders of
our common stock to receive a premium for their shares upon a
change of control.
Holders
of the common stock of acquisition targets may receive a premium for their
shares upon a change of control. Delaware law and the following provisions,
among others, of our Certificate of Incorporation and bylaws could have the
effect of delaying or preventing a change of control and could prevent holders
of our common stock from receiving such a premium:
|
|
•
|
Currently
the affirmative vote of 80% of the outstanding shares of our capital stock
is required to approve business combinations with any related person that
has not been approved by our board of directors. We are also
subject to a provision of Delaware corporate law that prohibits us from
engaging in a business combination with any interested stockholder for
three years from the date that person became an interested stockholder
unless specified conditions are
met.
|
|
|
•
|
Special
meetings of stockholders may not be called by anyone other than our board
of directors, our chairman, our executive committee or our president or
chief executive officer.
|
|
|
•
|
Our
board of directors is divided into three classes whose terms end in
successive years, so that less than a majority of our board comes up for
election at any annual meeting.
|
|
|
•
|
Our
board of directors has the authority to issue up to 5,000,000 shares
of preferred stock and to determine the voting rights and other privileges
of these shares without any vote or action by our
stockholders.
|
The
Company has no unresolved Securities and Exchange Commission staff
comments.
Rowan
leases as its corporate headquarters approximately 79,300 square feet of
space in an office tower located at 2800 Post Oak Boulevard in Houston,
Texas.
Following
are summaries of the principal drilling equipment owned by the Company and
location at February 16, 2010.
Offshore
Rigs
|
Depth (feet)(2)
|
||||||
|
Rig Name
|
Class Number(1)
|
Class Name/Type(1)
|
Water
|
Drilling
|
Year in Service
|
Location
|
|
Rigs
under construction (High-Specification Jack-ups):
(3)
|
||||||
|
Rowan
EXL #4
|
S116E
|
EXL
|
350
|
35,000
|
2012
|
Shipyard
|
|
Joe
Douglas
|
240C
|
240C
|
400
|
35,000
|
2011
|
Shipyard
|
|
Rowan
EXL #1
|
S116E
|
EXL
|
350
|
35,000
|
2010
|
Shipyard
|
|
Rowan
EXL #2
|
S116E
|
EXL
|
350
|
35,000
|
2010
|
Shipyard
|
|
Rowan
EXL #3
|
S116E
|
EXL
|
350
|
35,000
|
2010
|
Shipyard
|
|
High-Specification
Jack-ups: (3)
|
||||||
|
Ralph
Coffman (4)
|
240C
|
240C
|
400
|
35,000
|
2009
|
Gulf
of Mexico
|
|
Rowan-Mississippi
(4)
|
240C
|
240C
|
375
|
35,000
|
2008
|
Gulf
of Mexico
|
|
J.P.
Bussell (4)
|
225C
|
Tarzan
|
300
|
35,000
|
2008
|
Egypt
|
|
Hank
Boswell (4)
|
225C
|
Tarzan
|
300
|
35,000
|
2006
|
Middle
East
|
|
Bob
Keller (4)
|
225C
|
Tarzan
|
300
|
35,000
|
2005
|
Middle
East
|
|
Scooter
Yeargain (4)
|
225C
|
Tarzan
|
300
|
35,000
|
2004
|
Middle
East
|
|
Bob
Palmer (4)
|
224C
|
Super
Gorilla XL
|
550
|
35,000
|
2003
|
Gulf
of Mexico
|
|
Rowan
Gorilla VII (5)
|
219C
|
Super
Gorilla
|
400
|
35,000
|
2002
|
West
Africa
|
|
Rowan
Gorilla VI (5)
|
219C
|
Super
Gorilla
|
400
|
35,000
|
2000
|
North
Sea
|
|
Rowan
Gorilla V (5)
|
219C
|
Super
Gorilla
|
400
|
35,000
|
1998
|
North
Sea
|
|
Rowan
Gorilla IV (4)
|
200C
|
Gorilla
|
450
|
35,000
|
1986
|
Mexico
|
|
Premium
Jack-ups: (6)
|
||||||
|
Rowan
Gorilla III (4)
|
200C
|
Gorilla
|
450
|
30,000
|
1984
|
Eastern
Canada
|
|
Rowan
Gorilla II (4)
|
200C
|
Gorilla
|
450
|
30,000
|
1984
|
Gulf
of Mexico
|
|
Rowan-California
(4)
|
116C
|
116C
|
300
|
30,000
|
1983
|
Middle
East
|
|
Cecil
Provine (4)
|
116C
|
116C
|
300
|
30,000
|
1982
|
Gulf
of Mexico
|
|
Gilbert
Rowe (4)
|
116C
|
116C
|
350
|
30,000
|
1981
|
Middle
East
|
|
Arch
Rowan (4)
|
116C
|
116C
|
350
|
30,000
|
1981
|
Middle
East
|
|
Charles
Rowan (4)
|
116C
|
116C
|
350
|
30,000
|
1981
|
Middle
East
|
|
Rowan-Paris
(4)
|
116C
|
116C
|
350
|
30,000
|
1980
|
Middle
East
|
|
Rowan-Middletown
(4)
|
116C
|
116C
|
350
|
30,000
|
1980
|
Middle
East
|
|
Conventional
Jack-ups: (7)
|
||||||
|
Rowan-Juneau
|
116
|
Slot
|
250
|
30,000
|
1977
|
Gulf
of Mexico
|
|
Rowan-Alaska
|
84
|
Slot
|
350
|
30,000
|
1975
|
Gulf
of Mexico
|
|
Rowan-Louisiana
|
84
|
Slot
|
350
|
30,000
|
1975/2006
(8)
|
Gulf
of Mexico
|
____________
|
(1)
|
Class
number is assigned by LeTourneau and denotes the design and
construction. Class name is assigned by
Rowan. The Gorilla class unit is
designed for extreme hostile environments. The Super Gorilla class
unit is an enhanced version of the Gorilla class, and the
Super Gorilla XL
class unit is an enhanced version of our Super Gorilla
class. The 240C is LeTourneau’s
latest design. The EXL class unit is an
enhanced version of the 116C. All rigs are equipped with
top-drive drilling systems.
|
|
(2)
|
Indicates
rated water depth in current location and rated drilling
depth.
|
|
(3)
|
High-specification
rigs are those that have hook-load capacity of at least two million
pounds.
|
|
(4)
|
Unit
is equipped with three mud pumps.
|
|
(5)
|
Unit
is equipped with four mud pumps.
|
|
(6)
|
Premium
jack-ups are cantilevered rigs capable of operating in water depths of 300
feet or more.
|
|
(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.
|
Onshore
Rigs
|
Maximum
|
||||
|
Drilling
|
Maximum
|
|||
|
Rig Name
|
Type
|
Depth (feet)
|
Horsepower
|
Location
|
|
Actively
marketed rigs:
(1)
|
||||
|
Rig
9
|
Diesel
electric
|
20,000
|
2,000
|
Texas
|
|
Rig
12
|
SCR
diesel electric
|
18,000
|
1,500
|
Texas
|
|
Rig
15
|
AC
electric
|
35,000
|
3,000
|
Texas
|
|
Rig
26
|
SCR
diesel electric
|
25,000
|
2,000
|
Texas
|
|
Rig
29
|
Mechanical
|
18,000
|
1,500
|
Texas
|
|
Rig
30
|
AC
electric
|
20,000
|
2,000
|
Louisiana
|
|
Rig
31
|
SCR
diesel electric
|
35,000
|
3,000
|
Texas
|
|
Rig
33
|
SCR
diesel electric
|
18,000
|
1,500
|
Texas
|
|
Rig
35
|
SCR
diesel electric
|
18,000
|
1,500
|
Texas
|
|
Rig
51
|
SCR
diesel electric
|
25,000
|
2,000
|
Texas
|
|
Rig
52
|
SCR
diesel electric
|
25,000
|
2,000
|
Oklahoma
|
|
Rig
53
|
SCR
diesel electric
|
25,000
|
2,000
|
Louisiana
|
|
Rig
54
|
SCR
diesel electric
|
25,000
|
2,000
|
Louisiana
|
|
Rig
59
|
AC
electric
|
25,000
|
2,000
|
Louisiana
|
|
Rig
60
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
61
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
62
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
63
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
64
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
65
|
AC
electric
|
25,000
|
2,000
|
Louisiana
|
|
Rig
66
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
67
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
68
|
AC
electric
|
25,000
|
2,000
|
Alaska
|
|
Rig
76
|
AC
electric
|
25,000
|
2,000
|
Louisiana
|
|
Rig
77
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
84
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
85
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
86
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rig
87
|
AC
electric
|
25,000
|
2,000
|
Texas
|
|
Rigs
out of service:
|
||||
|
Rig
14
|
AC
electric
|
35,000
|
3,000
|
Texas
|
|
Rig
18
|
SCR
diesel electric
|
25,000
|
2,000
|
Texas
|
|
Rig
34
|
SCR
diesel electric
|
25,000
|
2,000
|
Texas
|
____________
|
(1)
|
All
but Rig 29 are equipped with top-drive drilling
systems.
|
Rowan’s
drilling division leases and, in some cases, owns various operating and
administrative facilities generally consisting of office, maintenance and
storage space in the United States in Texas and Alaska and in Canada, Scotland,
Saudi Arabia, Qatar, Egypt and Mexico.
LeTourneau’s
principal manufacturing facility and headquarters are located in Longview,
Texas, on approximately 2,400 acres with approximately 1.2 million
square feet of covered working area. The facility is owned and
contains:
|
|
•
|
a
steel mini-mill with 330,000 square feet of covered working
area;
|
|
|
•
|
a
fabrication shop with 300,000 square feet of covered working
area;
|
|
|
•
|
a
machine shop with 140,000 square feet of covered working area;
and
|
|
|
•
|
an
assembly shop with 124,000 square feet of covered working
area.
|
The
mini-mill has two 25-ton electric arc furnaces capable of producing 120,000
melted tons per year.
We
machine, fabricate, assemble, and test drilling products and systems at a
facility we own in Houston, Texas, that has approximately 450,000 square
feet of covered work area and 45,000 square feet of office
space. This capacity is supported by the Longview, Texas,
facility. Additionally, we lease warehouse and administrative
facilities in Texas, Louisiana and Canada.
We also
own a jack-up rig construction facility located in Vicksburg, Mississippi, on
1,850 acres of land that has approximately 560,000 square feet of
covered work area. Our rig service and repair operation is carried
out primarily at our Sabine Pass, Texas, facility.
Our
distributor of forestry products in the northwestern United States is located on
a six-acre site in Troutdale, Oregon, with approximately 22,000 square feet
of building space.
Our
distributor of mining products in the western United States is located in a
leased facility in Tucson, Arizona, having approximately 20,000 square
feet. Our distributor of mining products in Australia is located in a
leased facility in Murarrie, Queensland, having approximately 29,500 square
feet. There are additional branch locations in each Australian
territory. Our distributor of mining products in Brazil leases an
office building and warehouse.
Reference
should be made to Note 6 of “Notes to Consolidated Financial Statements” in Item
8 of this Form 10-K for the status of significant legal
proceedings.
The
names, positions, years of credited service and ages of the officers of the
Company as of March 1, 2010 are listed below. 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
|
Years
of
Credited
Service
|
Age
|
|
W.
Matt Ralls
|
President
and Chief Executive Officer
|
1
|
60
|
|
John
L. Buvens
|
Executive
Vice President, Legal
|
29
|
54
|
|
Mark
A. Keller
|
Executive
Vice President, Business Development
|
17
|
57
|
|
David
P. Russell
|
Executive
Vice President, Drilling Operations
|
26
|
48
|
|
J.
Kevin Bartol
|
Vice
President, Strategic Planning
|
2
|
50
|
|
Barbara
A. Carroll
|
Vice
President, Health, Safety and Environmental Affairs
|
2
|
55
|
|
Michael
J. Dowdy
|
Vice
President, Engineering
|
19
|
50
|
|
Thomas
P. Burke
|
President
and Chief Executive Officer, LeTourneau Technologies, Inc.
|
-
|
43
|
|
William
H. Wells
|
Vice
President, Finance and Chief Financial Officer
|
15
|
47
|
|
Terry
D. Woodall
|
Vice
President, Human Resources
|
4
|
61
|
|
George
C. Jones
|
Compliance
Officer
|
3
|
44
|
|
Gregory
M. Hatfield
|
Controller
|
15
|
40
|
|
Melanie
M. Trent
|
Corporate
Secretary
|
4
|
45
|
Since
January 2009, Mr. Ralls’ principal occupation has been President and Chief
Executive Officer. From June 2005 until his retirement in November
2007, Mr. Ralls served as Executive Vice President and Chief Operating Officer
of GlobalSantaFe Corporation. Prior to that time, Mr. Ralls
served as Senior Vice President and Chief Financial Officer of GlobalSantaFe
Corporation. Mr. Ralls also serves on the Board of Complete
Production Services, Inc.
Since
January 2007, Mr. Buvens’ principal occupation has been Executive Vice
President, Legal. Prior to that time, Mr. Buvens served as Senior
Vice President, Legal.
Since
January 2007, Mr. Keller’s principal occupation has been Executive Vice
President, Business Development. Prior to that time, Mr. Keller
served as Senior Vice President, Marketing.
Since
January 2007, Mr. Russell’s principal occupation has been Executive Vice
President, Drilling Operations. From January 2005 to January 2007,
Mr. Russell served as Vice President, Drilling. Prior to that
time, Mr. Russell served as Vice President, Rowan Drilling Company, Inc., a
Rowan subsidiary.
Since
June 2007, Mr. Bartol’s principal occupation has been Vice President, Strategic
Planning. From January 2007 to June 2007, Mr. Bartol served as a
consultant to the Company on strategic initiatives. From June 2004 to
August 2006, Mr. Bartol was Chief Financial Officer of Jindal United Steel
Corporation.
Since May
2008, Ms. Carroll’s principal occupation has been Vice President, Health, Safety
and Environmental Affairs. From October 2007 to May 2008, Ms. Carroll
served as Vice President, Environmental Affairs. From July 2006 to
October 2007, Ms. Carroll served as a consultant to the
Company. Prior to that time, Ms. Carroll was Vice President of
Environmental, Health and Safety for TEPPCO Partners, LLP.
Since
April 2006, Mr. Dowdy’s principal occupation has been Vice President,
Engineering. Prior to that time, Mr. Dowdy was Chief Engineer, Marine
Group for LeTourneau.
Since
January 2010, Dr. Burke’s principal occupation has been President and Chief
Executive Officer of LeTourneau. Prior to that time, Dr. Burke was
employed by Complete Production Services, Inc., an oilfield services company, as
Division President from 2006 to 2009, and as Vice President Corporate
Development from 2004 to 2006.
Since
January 2007, Mr. Wells’ principal occupation has been Vice President,
Finance and Chief Financial Officer. From May 2005 to January 2007,
Mr. Wells served as Vice President, Finance and Treasurer. Prior to
that time, Mr. Wells served as Controller.
Since
July 2005, Mr. Woodall’s principal occupation has been Vice President,
Human Resources. Prior to that time, Mr. Woodall was Manager,
U.S. Employee Services for Schlumberger.
Since
July 2007, Mr. Jones’ principal occupation has been Compliance
Officer. From July 2006 to July 2007, Mr. Jones served as Senior
Corporate Counsel. Prior to that time, Mr. Jones practiced corporate
law at Andrews Kurth LLP.
Since May
2005, Mr. Hatfield’s principal occupation has been
Controller. Prior to that time, Mr. Hatfield served as Corporate
Accountant of the Company.
Since
January 2009, Ms. Trent’s principal occupation has been Corporate
Secretary. From January 2007 to January 2009, Ms. Trent served as
Corporate Secretary and Special Assistant to the CEO. From October
2005 to January 2007, Ms. Trent served as Corporate Secretary and Compliance
Officer. From 2004 to September 2005, Ms. Trent performed
contract legal services, primarily for Jindal United Steel
Corporation.
Rowan’s
common stock is 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 common stock for each quarterly period within the two most recent years
as reported by the NYSE Consolidated Transaction Reporting System.
|
|
2009
|
2008
|
||||||||||||||
|
Quarter:
|
High
|
Low
|
High
|
Low
|
||||||||||||
|
First
|
$ | 18.52 | $ | 10.28 | $ | 42.49 | $ | 30.49 | ||||||||
|
Second
|
23.90 | 11.40 | 47.94 | 36.90 | ||||||||||||
|
Third
|
24.31 | 16.96 | 47.00 | 27.53 | ||||||||||||
|
Fourth
|
27.54 | 21.42 | 30.15 | 12.00 | ||||||||||||
On
February 26, 2010, there were 1,396 stockholders of record.
In May
2006, Rowan’s Board of Directors approved a regular quarterly cash dividend of
$0.10 per share, which the Company paid approximately every three months
thereafter through November 2008. The Company did not pay any
dividends in 2009. Future dividends, if any, will only be paid at the
discretion of the Board of Directors. At December 31, 2009,
Rowan had approximately $615 million of retained earnings available for
distribution to stockholders under the provisions of its debt
agreements. We do not expect to pay dividends in the foreseeable
future.
The graph
below presents the relative investment performance of Rowan’s common stock, the
Dow Jones U.S. Oil Equipment and Services Index, and the S&P 500 Index for
the five-year period ending December 31, 2009, assuming reinvestment of
dividends.
* $100
invested on 12/31/04 in stock or index, including reinvestment of dividends.
Fiscal year ending December 31.
|
12/31/2004
|
12/31/2005
|
12/31/2006
|
12/31/2007
|
12/31/2008
|
12/31/2009
|
|
|
Rowan
Companies, Inc.
|
100.00
|
139.78
|
131.96
|
158.54
|
64.79
|
92.26
|
|
S&P
500 Index
|
100.00
|
104.91
|
121.48
|
128.16
|
80.74
|
102.11
|
|
Dow
Jones US Oil Equipment & Services Index
|
100.00
|
151.75
|
172.19
|
249.58
|
101.59
|
167.77
|
During
the fourth quarter of 2009, we acquired 66 shares of our common stock in
connection with the vesting of an employee restricted stock award.
In
1998, our Board of Directors authorized us to purchase up to eight million
shares of our common stock. We last purchased shares under this
program in 2002, and at December 31, 2009, we could purchase up to 1,524,600
additional shares. We have no plans to purchase additional shares at
the present time.
For
information concerning our common stock to be issued in connection with our
equity compensation plans, see Item 12, “Security Ownership of Certain
Beneficial Owners and Management and Related Stockholder Matters,” of this Form
10-K.
The
following information summarizes Rowan’s results of operations and financial
position for each of the last five years ended December 31.
|
2009
|
2008
|
2007
|
2006
|
2005
|
||||||||||||||||
|
(In
thousands except per share amounts and ratios)
|
||||||||||||||||||||
|
Operations
|
||||||||||||||||||||
|
Revenues:
|
||||||||||||||||||||
|
Drilling
services
|
$ | 1,214,896 | $ | 1,451,623 | $ | 1,382,571 | $ | 1,067,448 | $ | 775,356 | ||||||||||
|
Manufacturing
sales and services
|
555,284 | 761,113 | 712,450 | 443,286 | 293,426 | |||||||||||||||
|
Total
|
1,770,180 | 2,212,736 | 2,095,021 | 1,510,734 | 1,068,782 | |||||||||||||||
|
Costs
and expenses:
|
||||||||||||||||||||
|
Drilling
services (excluding items shown below)
|
525,157 | 629,795 | 591,412 | 504,873 | 388,259 | |||||||||||||||
|
Manufacturing
sales and services (excluding items shown below)
|
475,553 | 624,815 | 596,541 | 372,219 | 253,688 | |||||||||||||||
|
Depreciation
and amortization
|
171,445 | 141,395 | 118,796 | 89,971 | 81,204 | |||||||||||||||
|
Selling,
general and administrative
|
102,760 | 115,226 | 94,905 | 78,243 | 71,428 | |||||||||||||||
|
Gain
on disposals of property and equipment
|
(5,748 | ) | (30,701 | ) | (40,506 | ) | (29,266 | ) | (52,449 | ) | ||||||||||
|
Material
charges and other operating expenses (1)
|
- | 111,171 | - | 9,000 | - | |||||||||||||||
|
Gain
on hurricane-related events
|
- | (37,088 | ) | - | - | (13,948 | ) | |||||||||||||
|
Total
|
1,269,167 | 1,554,613 | 1,361,148 | 1,025,040 | 728,182 | |||||||||||||||
|
Income
from operations
|
501,013 | 658,123 | 733,873 | 485,694 | 340,600 | |||||||||||||||
|
Other
income (expense) — net
|
78 | (4,032 | ) | 5,213 | 7,660 | 4,870 | ||||||||||||||
|
Income
from continuing operations, before income taxes
|
501,091 | 654,091 | 739,086 | 493,354 | 345,470 | |||||||||||||||
|
Provision
for income taxes
|
133,587 | 226,463 | 255,286 | 176,377 | 127,633 | |||||||||||||||
|
Income
from continuing operations
|
367,504 | 427,628 | 483,800 | 316,977 | 217,837 | |||||||||||||||
|
Income
from discontinued operations including gain on sale, net of taxes
(2)
|
- | - | - | 1,269 | 11,963 | |||||||||||||||
|
Net
income
|
$ | 367,504 | $ | 427,628 | $ | 483,800 | $ | 318,246 | $ | 229,800 | ||||||||||
|
Basic
income per common share:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 3.24 | $ | 3.80 | $ | 4.36 | $ | 2.87 | $ | 2.00 | ||||||||||
|
Income
from discontinued operations
|
- | - | - | 0.01 | 0.11 | |||||||||||||||
|
Net
income
|
$ | 3.24 | $ | 3.80 | $ | 4.36 | $ | 2.88 | $ | 2.11 | ||||||||||
|
Diluted
income per common share:
|
||||||||||||||||||||
|
Income
from continuing operations
|
$ | 3.24 | $ | 3.77 | $ | 4.31 | $ | 2.84 | $ | 1.97 | ||||||||||
|
Income
from discontinued operations
|
- | - | - | 0.01 | 0.11 | |||||||||||||||
|
Net
income
|
$ | 3.24 | $ | 3.77 | $ | 4.31 | $ | 2.85 | $ | 2.08 | ||||||||||
|
Financial
Position
|
||||||||||||||||||||
|
Cash
and cash equivalents
|
$ | 639,681 | $ | 222,428 | $ | 284,458 | $ | 258,041 | $ | 675,903 | ||||||||||
|
Property,
plant and equipment — net
|
$ | 3,579,485 | $ | 3,147,528 | $ | 2,487,811 | $ | 2,133,226 | $ | 1,720,734 | ||||||||||
|
Total
assets
|
$ | 5,210,694 | $ | 4,548,892 | $ | 3,875,305 | $ | 3,435,398 | $ | 2,975,183 | ||||||||||
|
Long-term
debt, less current portion
|
$ | 787,490 | $ | 355,560 | $ | 420,482 | $ | 485,404 | $ | 550,326 | ||||||||||
|
Stockholders’
equity
|
$ | 3,110,370 | $ | 2,659,816 | $ | 2,348,438 | $ | 1,874,046 | $ | 1,619,739 | ||||||||||
|
Statistical
Information
|
||||||||||||||||||||
|
Current
ratio
|
2.73 | 1.84 | 2.63 | 2.13 | 3.55 | |||||||||||||||
|
Long-term
debt/total capitalization
|
0.20 | 0.12 | 0.15 | 0.21 | 0.25 | |||||||||||||||
|
Book
value per share of common stock
|
$ | 27.31 | $ | 23.51 | $ | 21.10 | $ | 16.97 | $ | 14.75 | ||||||||||
|
Price
range of common stock:
|
||||||||||||||||||||
|
High
|
$ | 27.54 | $ | 47.94 | $ | 46.16 | $ | 48.15 | $ | 39.50 | ||||||||||
|
Low
|
$ | 10.28 | $ | 12.00 | $ | 29.48 | $ | 29.03 | $ | 24.53 | ||||||||||
|
Cash
dividends per share
|
$ | - | $ | 0.40 | $ | 0.40 | $ | 0.55 | $ | 0.50 | ||||||||||
___________________
|
(1)
|
Material
charges and other operating expenses in 2008 included $62.4 million of
inventory valuation charges, a $13.6 million charge for goodwill
impairment, $12.7 million for professional fees related to the suspended
LeTourneau monetization, an $11.8 million impairment charge due to the
cancellation of the fourth 240C jack-up rig and
$10.7 million for severance payments. The 2006 amount reflected
an accrual for payments made in 2007 related to a Department of Justice
investigation.
|
|
(2)
|
Income
from discontinued operations in 2005 consisted primarily of the aggregate
after-tax results of Rowan’s boat operations, which were sold in 2005, and
include an after-tax gain on sale of $13.1 million. The 2006
amount reflected a refund of excise taxes related to the Company’s
aviation operations, which were sold in
2004.
|
SUMMARY
During
2009, our results of operations continued to benefit from contracts executed
prior to the downturn that began in mid 2008 in markets for our products and
services. Reduced activity levels, however, caused by the continuing
global economic weakness resulted in a decline in our 2009 revenues and
profitability. We are currently receiving above-market day rates on
several long-term drilling contracts, most of which are scheduled to conclude in
2010 or 2011. Absent a rebound in drilling demand sufficient to
enable a recovery in market day rates, our future results of operations would be
further negatively impacted as lower market rates are realized in our reported
results. Although our operations are currently profitable overall, we
can provide no assurance that they will continue to be profitable.
As of
February 16, 2010, we had nine offshore rigs in the Middle East, eight in the
U.S. Gulf of Mexico, two in the North Sea, and one each offshore West Africa,
Eastern Canada, Mexico and Egypt.
RESULTS
OF OPERATIONS
The
following table highlights Rowan’s operating results for the years indicated (in
millions):
|
2009
|
2008
|
2007
|
||||||||||
|
Revenues:
|
||||||||||||
|
Drilling
services
|
$ | 1,214.9 | $ | 1,451.6 | $ | 1,382.6 | ||||||
|
Manufacturing
sales andservices:
|
||||||||||||
|
Drilling
products and systems
|
369.4 | 493.5 | 498.6 | |||||||||
|
Mining,
forestry and steel products
|
185.9 | 267.6 | 213.8 | |||||||||
|
Total
manufacturing sales and services
|
555.3 | 761.1 | 712.4 | |||||||||
|
Total
revenues
|
$ | 1,770.2 | $ | 2,212.7 | $ | 2,095.0 | ||||||
|
Costs
and expenses:
|
||||||||||||
|
Drilling
services
|
$ | 742.8 | $ | 781.5 | $ | 720.8 | ||||||
|
Manufacturing
sales andservices:
|
||||||||||||
|
Drilling
products and systems
|
366.0 | 538.1 | 455.6 | |||||||||
|
Mining,
forestry and steel products
|
160.4 | 235.0 | 184.7 | |||||||||
|
Total
manufacturing sales and services
|
526.4 | 773.1 | 640.3 | |||||||||
|
Total
costs and expenses
|
$ | 1,269.2 | $ | 1,554.6 | $ | 1,361.1 | ||||||
|
Operating
income:
|
||||||||||||
|
Drilling
services
|
$ | 472.1 | $ | 670.1 | $ | 661.8 | ||||||
|
Manufacturing
sales andservices:
|
||||||||||||
|
Drilling
products and systems
|
3.4 | (44.6 | ) | 43.0 | ||||||||
|
Mining,
forestry and steel products
|
25.5 | 32.6 | 29.1 | |||||||||
|
Total
manufacturing sales and services
|
28.9 | (12.0 | ) | 72.1 | ||||||||
|
Total
operating income
|
$ | 501.0 | $ | 658.1 | $ | 733.9 | ||||||
|
Net
income
|
$ | 367.5 | $ | 427.6 | $ | 483.8 | ||||||
As
indicated in the preceding table, Rowan’s results of operations are primarily
driven by the performance of our Drilling Services segment, which comprises
about 95% of our fixed assets and, over the past three years, has generated
two-thirds of our aggregate revenues and 95% of our aggregate operating
income. Our manufacturing division, featuring our Drilling Products
and Systems segment, has led the strategic expansion and upgrade of our drilling
fleet over the past decade and, in recent years, has expanded product lines and
sought to grow its external business.
Costs and
expenses in 2008 included $111.2 million of special items, including (i)
impairment charges relating to a cancelled rig construction project, the
realizable value of manufacturing inventories and goodwill, (ii) professional
service fees and other expenses incurred in connection with the suspended
LeTourneau monetization process and (iii) severance costs in
connection
with the retirement of the Company’s former Chief Executive Officer in 2008 and
headcount reductions. These items are described more fully in the
operating segment discussions below and in Note 11 of “Notes to Consolidated
Financial Statements.”
Net
income includes income from operations plus the following items (in
millions):
|
2009
|
2008
|
2007
|
||||||||||
|
Interest
income
|
$ | 1.2 | $ | 6.3 | $ | 20.9 | ||||||
|
Interest
expense
|
(29.5 | ) | (18.6 | ) | (25.9 | ) | ||||||
|
Capitalized
interest
|
21.5 | 17.4 | 10.0 | |||||||||
|
Other
income (expense) - net
|
6.9 | (9.1 | ) | 0.2 | ||||||||
|
Provision
for income taxes
|
(133.6 | ) | (226.5 | ) | (255.3 | ) | ||||||
In 2009,
the Company recognized a $25.4 million tax benefit as a result of applying our
facts to a recent third-party tax case that provides a more favorable tax
treatment for certain foreign contracts entered into in prior
years. The Company has deferred recognition of a remaining $49.2
million estimated benefit in accordance with the accounting guidelines for
income tax uncertainties.
The
performance of each of our operating segments over the period from 2007 through
2009 is discussed more fully below.
Drilling
Operations
Drilling
Services’ operating results are primarily a function of the activity (or
utilization) and day rates achieved by our land and offshore rig
fleets. Rig activity and day rates are primarily determined by 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 activity, and day rate increases can be
more significant as utilization approaches 100%. When drilling
markets are weakening, day rates are often significantly reduced in an effort to
maintain utilization. Due to intense competition in the contract
drilling industry, both market utilization and day rates have historically
declined much faster than they have risen.
Market
Conditions
Over the
period from 2007 through mid 2008, global demand for oil and natural gas
continued to increase, especially in developing nations such as China and
India. At the same time, many key producers increasingly struggled
with depleting reserves, requiring more drilling simply to maintain production
levels. These market forces caused a dramatic increase in energy
prices, and the per-barrel price of oil rose from the low $50s in early 2007 to
an all-time high of more than $145 in July 2008. Natural gas prices
followed a similar pattern during the period, though with much more volatility,
generally ranging from $5.50 to $8.50 per mcf during 2007 and peaking in mid
2008 at nearly $14.
As a
result, drilling demand surged over the period, with all available rigs
benefiting. Many of the projects were in increasingly difficult
drilling environments and demanded the most capable drilling
equipment. Meanwhile, the global jack-up fleet, with relatively few
net rig additions between 1986 and 2005, continued to age. The more
capable rigs were marketable throughout the world, and were generally able to
obtain longer-term contracts and higher day rates than older and less capable
“commodity” rigs.
In mid
2008, when the global economy began slipping into recession and access to
capital diminished significantly due to weakening financial markets, both oil
and natural gas prices began to decline precipitously, and were down from their
highs by approximately 79% and 61%, respectively, by the end of
2008. Most companies reduced spending in 2009, and energy companies
in particular, with the prospect of significantly reduced cash flows and
constrained capital resources, dramatically cut exploration and development
expenditures, with most of the reductions targeted at shallow water and land
drilling.
As access
to capital began to be restored and global economies began to stabilize in 2009,
oil prices more than doubled from their lows and global drilling activity
appeared to bottom during the second quarter. Most drilling budgets
in 2010 show increases over the reduced 2009 levels. Natural gas
prices remained weak for most of 2009, causing a collapse in domestic land and
offshore drilling markets early in the year, particularly in the Gulf of Mexico,
though prices began strengthening and activity had begun to recover by year’s
end. See further discussion under “Drilling Operations –
Outlook.”
Our
Rig Fleets
Our
offshore fleet currently consists of 23 jack-up rigs, featuring:
|
·
|
Two
240C class
jack-ups, one of which was delivered in late 2008 and one in late
2009,
|
|
·
|
Four
Tarzan Class
jack-ups delivered during the 2004-2008
period,
|
|
·
|
Four
Super Gorilla
class jack-ups delivered during the 1998-2003
period,
|
|
·
|
Three
Gorilla class
jack-ups built during the early
1980s,
|
|
·
|
Seven
116C class
jack-ups built during the early 1980s,
and
|
|
·
|
Two
84 class jack-ups
and one 116 class
jack-up built during the mid-to-late
1970s.
|
The 240Cs, Tarzan Class, Super Gorillas and one of the
Gorilla class rigs have
at least two million pounds of hook-load capability, enabling efficient drilling
beyond 30,000 feet. We consider such rigs “high-specification”
jack-ups.
Five
additional high-specification jack-ups are under construction with deliveries
currently expected over the period from the second quarter of 2010 through the
first quarter of 2012, including one 240C class rig and four EXL class
rigs. See further discussion of our offshore newbuild program under
“Liquidity and Capital Resources – Capital Expenditures.”
During
2009, we discontinued active marketing of three of our thirty-two land
rigs. Our land fleet currently consists of 29 marketed rigs,
including 16 rigs constructed since 2005, four rigs built during 2001-2002 and
nine older rigs that have been refurbished over the years.
Current
Operations
The U.S.
Gulf of Mexico offshore drilling market is highly fragmented among several oil
and gas companies, many of which are independent operators whose drilling
activities are 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 have been relatively rare, and generally
are available only from the major integrated oil companies and a few of the
larger independent operators. Drilling activity and day rates in the
Gulf of Mexico have tended to fluctuate rather quickly, and generally follow
trends in natural gas prices. Offshore drilling demand in the Gulf
reached a peak in 2007, began weakening in late 2008, and generally has remained
weak since that time. We currently have eight rigs in the U.S. Gulf
of Mexico – seven under contracts expiring in 2010 and one that is
idle.
International
markets present more opportunities for longer-term drilling contracts and
high-specification rigs than do domestic markets. The relocation of
rigs from domestic to foreign markets is a significant undertaking, and often
interrupts revenues and cash flows for up to three to four months, particularly
when equipment upgrades are involved. Thus, major relocations are
typically carried out only when the likelihood of higher long-term returns
heavily 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. Thus,
drilling activity and day rates in the North Sea move slowly in response to
market conditions, and generally follow trends in oil prices. We
currently have two Super
Gorilla class rigs operating in the North Sea – one under contract that
is expected to be completed in the second quarter of 2011 and another under
contract that is estimated to be completed in the third quarter of
2011.
We have
operated offshore eastern Canada at varying levels since the early 1980s, though
we had vacated that market in late 2006. In July 2009, one of our
Gorilla class rigs
returned to eastern Canada, where it is operating under a contract that is
expected to continue through the third quarter of 2010.
The
Middle East has been a primary focus among our international operations in
recent years. In 2007, we added four rigs to our four existing rigs
in the region – two 116Cs with initial two-year
contracts with Maersk offshore Qatar, and two Tarzan Class rigs under
four-year contracts with Saudi Aramco. We added a third Tarzan Class rig in the
Middle East under a three-year contract in 2008 and currently have nine rigs in
the region – two under contracts expiring in 2010, four under contracts expiring
in 2011 and three that are idle.
In
October 2009, we completed mobilizing the J.P. Bussell to Egypt where
it began operating for Shell under an approximate 20-month
contract. Our two remaining rigs operating internationally are the
Rowan Gorilla IV, which
is operating for PEMEX in the Gulf of Mexico under a contract that is expected
to conclude in the third quarter of 2011, and the Rowan Gorilla VII, which,
after completion of the current contract in the second quarter of 2010, will
mobilize from West Africa to the North Sea, where it has a contract that is
expected to be completed in the first quarter of 2012.
2009
Compared to 2008
The
following table highlights the performance of our Drilling Services segment
during 2009 compared to 2008 (dollars in millions, except day
rates):
|
2009
|
2008
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 1,214.9 | 100 | % | $ | 1,451.6 | 100 | % | ||||||||
|
Operating
costs
|
(525.2 | ) | -43 | % | (629.8 | ) | -43 | % | ||||||||
|
Depreciation
expense
|
(155.9 | ) | -13 | % | (125.9 | ) | -9 | % | ||||||||
|
Selling,
general and administrative expenses
|
(68.0 | ) | -6 | % | (69.2 | ) | -5 | % | ||||||||
|
Gains
on property disposals
|
6.3 | 1 | % | 68.0 | 5 | % | ||||||||||
|
Material
charges and other operating expenses
|
- | 0 | % | (24.6 | ) | -2 | % | |||||||||
|
Operating
income
|
$ | 472.1 | 39 | % | $ | 670.1 | 46 | % | ||||||||
|
Offshore
fleet:
|
||||||||||||||||
|
Average
day rate
|
$ | 175,100 | $ | 163,200 | ||||||||||||
|
Rig
utilization
|
73 | % | 95 | % | ||||||||||||
|
Revenue-producing
days
|
5,876 | 7,313 | ||||||||||||||
|
Land
fleet:
|
||||||||||||||||
|
Average
day rate
|
$ | 23,200 | $ | 22,600 | ||||||||||||
|
Rig
utilization
|
62 | % | 93 | % | ||||||||||||
|
Revenue-producing
days
|
7,175 | 10,067 | ||||||||||||||
The
following table summarizes average prices for oil and natural gas and our
utilization and average day rates by quarter in 2009, and for the full years
2009 and 2008 for our offshore fleet:
|
Oil
(per bbl) *
|
Natural
gas (per MCF) *
|
Average
utilization
|
Average
day rate
|
|||||||||||||
|
2009:
|
||||||||||||||||
|
First
quarter
|
$ | 43.14 | $ | 4.47 | 93 | % | $ | 173,600 | ||||||||
|
Second
quarter
|
$ | 59.61 | $ | 3.81 | 78 | % | $ | 177,200 | ||||||||
|
Third
quarter
|
$ | 68.14 | $ | 3.44 | 59 | % | $ | 182,500 | ||||||||
|
Fourth
quarter
|
$ | 76.00 | $ | 4.93 | 63 | % | $ | 167,700 | ||||||||
|
Full
year:
|
||||||||||||||||
|
2009
|
$ | 61.95 | $ | 4.16 | 73 | % | $ | 175,100 | ||||||||
|
2008
|
$ | 99.67 | $ | 8.90 | 95 | % | $ | 163,200 | ||||||||
__________
|
*
|
Source:
New York Mercantile Exchange
(NYMEX)
|
The
dramatic declines in oil and natural gas prices that began in mid 2008 coupled
with the weakness in the global capital markets increased our customers’ efforts
to preserve liquidity and adversely affected the economics of certain drilling
projects. Most oil and gas producers significantly reduced their 2009
drilling expenditures, and that reduction was most prominent for shallow water
and onshore projects. The reduction in demand reduced global jack-up
and land rig utilization, increased competition among available rigs for fewer
drilling assignments, and pressured day rates.
Drilling
revenues for 2009 decreased by $236.7 million, or 16%, compared to 2008 as a
result of the following (in millions):
|
Increase
|
||||
|
(Decrease)
|
||||
|
Lower
offshore rig utilization
|
$ | (274.7 | ) | |
|
Lower
land rig utilization
|
(86.3 | ) | ||
|
Loss
of the Rowan-Anchorage1
|
(15.2 | ) | ||
|
Reimbursables
and other, net
|
(10.8 | ) | ||
|
Higher
average land day rates
|
1.9 | |||
|
Addition
of four land rigs2
|
23.3 | |||
|
Higher
average offshore day rates
|
45.6 | |||
|
Addition
of the J.P.
Bussell and Rowan-Mississippi3
|
79.5 | |||
|
Net
decrease
|
$ | (236.7 | ) | |
_______________________________
1The
Rowan-Anchorage was
lost in September 2008 during Hurricane Ike.
2The
four land rigs added to the fleet over the period from May 2008 through June
2009 contributed an additional 939 revenue-producing days in 2009 as compared to
2008.
3The
J.P. Bussell and Rowan-Mississippi commenced
operations in November 2008 and contributed 548 revenue-producing days in 2009,
as compared to 86 days in 2008.
The
following table presents certain key performance measures by geographic area for
our offshore fleet for 2009 and 2008. The number of rigs in each
location is based on location for the majority of the period and includes active
and idle rigs. Revenues include those attributable to reimbursable
costs. Average day rates are computed by dividing revenues recognized
during the year, excluding reimbursables, by the number of revenue-producing
days. Rig utilization is computed as the number of revenue-producing
days divided by total available rig-days.
|
2009
|
2008
|
|||||||
|
Gulf
of Mexico:
|
||||||||
|
Number
of rigs
|
8 | 8 | ||||||
|
Revenues
|
$ | 297,206,000 | $ | 402,696,000 | ||||
|
Average
day rate
|
$ | 145,600 | $ | 129,900 | ||||
|
Utilization
|
64 | % | 97 | % | ||||
|
Middle
East:
|
||||||||
|
Number
of rigs
|
9 | 9 | ||||||
|
Revenues
|
$ | 373,059,000 | $ | 480,981,000 | ||||
|
Average
day rate
|
$ | 153,300 | $ | 155,400 | ||||
|
Utilization
|
74 | % | 94 | % | ||||
|
North
Sea:
|
||||||||
|
Number
of rigs
|
2 | 2 | ||||||
|
Revenues
|
$ | 172,610,000 | $ | 166,486,000 | ||||
|
Average
day rate
|
$ | 243,400 | $ | 244,900 | ||||
|
Utilization
|
97 | % | 91 | % | ||||
|
Other
international:
|
||||||||
|
Number
of rigs
|
3 | 2 | ||||||
|
Revenues
|
$ | 199,449,000 | $ | 158,988,000 | ||||
|
Average
day rate
|
$ | 257,600 | $ | 301,200 | ||||
|
Utilization
|
83 | % | 98 | % | ||||
Drilling
operating costs in 2009 decreased by $104.6 million, or 17% from 2008, as set
forth in the table below (in millions):
|
Increase
|
||||||||
|
(Decrease)
|
%
Change
|
|||||||
|
Personnel
and related costs for existing rigs
|
$ | (55.3 | ) | -16 | % | |||
|
Repairs
and maintenance for existing rigs
|
(27.5 | ) | -21 | % | ||||
|
Reimbursable
expenses
|
(9.8 | ) | -34 | % | ||||
|
Rig
insurance costs for existing rigs
|
(3.1 | ) | -7 | % | ||||
|
All
other
|
(8.9 | ) | -11 | % | ||||
|
Net
decrease
|
$ | (104.6 | ) | -17 | % | |||
The
declines in personnel and related costs and repairs and maintenance
expenses were primarily the result of reduced activity
levels. Additionally, several shipyard upgrade projects on many of
our idle rigs absorbed certain personnel-related costs and resulted in lower
routine repair and maintenance expenses that we would have otherwise
incurred. Operating margins before depreciation and selling, general
and administrative expenses were 57% in both 2009 and 2008. Drilling
depreciation expense increased by $30.0 million or 24% between periods due
primarily to the addition of the J.P. Bussell and Rowan-Mississippi in November
2008.
2008
Compared to 2007
The
following table highlights the performance of our Drilling Services segment
during 2008 compared to 2007 (dollars in millions):
|
2008
|
2007
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 1,451.6 | 100 | % | $ | 1,382.6 | 100 | % | ||||||||
|
Operating
costs
|
(629.8 | ) | -43 | % | (591.4 | ) | -43 | % | ||||||||
|
Depreciation
expense
|
(125.9 | ) | -9 | % | (101.8 | ) | -7 | % | ||||||||
|
Selling,
general and administrative expenses
|
(69.2 | ) | -5 | % | (68.3 | ) | -5 | % | ||||||||
|
Gains
on property disposals
|
68.0 | 5 | % | 40.7 | 3 | % | ||||||||||
|
Material
charges and other operating expenses
|
(24.6 | ) | -2 | % | - | 0 | % | |||||||||
|
Operating
income
|
$ | 670.1 | 46 | % | $ | 661.8 | 48 | % | ||||||||
Drilling
revenues increased by $69.0 million or 5% in 2008, due primarily to the
effects of increased drilling activity and average day rates, as follows (in
millions):
|
Increase
|
||||
|
(Decrease)
|
||||
|
New
rigs
|
$ | 33.2 | ||
|
Increases
in average day rates
|
23.7 | |||
|
Net
increase in utilization for existing rigs
|
16.6 | |||
|
Net
increase in utilization for relocated rigs
|
12.5 | |||
|
Lost
or sold rigs
|
(9.4 | ) | ||
|
Other,
primarily reduction in reimbursables
|
(7.6 | ) | ||
|
Net
increase
|
$ | 69.0 | ||
Our
overall offshore fleet utilization was 95% in 2008, up from 94% in 2007, with
most of the downtime in each period associated with rigs being prepared for
long-term assignments overseas. Our average offshore day rate was
$163,200 in 2008, an increase of approximately 4% over 2007. Total
revenue-producing days offshore increased by 103 or 1% between years, with most
of that increase associated with our new rigs.
Middle East. Our
nine jack-ups working offshore Saudi Arabia and Qatar collectively generated
approximately $480 million of drilling revenues in 2008, averaging more than
$155,000 per day, compared to almost $400 million from eight rigs averaging
$149,000 per day in 2007. Our utilization averaged 94% in 2008, up
from 92% in 2007.
North Sea. Our two
rigs working in the North Sea generated approximately $164 million of drilling
revenues in 2008, averaging about $245,000 per day, compared to $246 million
from three rigs averaging $241,000 per day in 2007. Our utilization
averaged 91% in 2008, down from 96% in 2007, with most of the downtime in 2008
due to rigs undergoing shipyard upgrades.
Other
International. After relocating from the North Sea in early
January 2008, Gorilla
VII was 96% utilized offshore West Africa and provided almost
$325,000 per day in drilling revenues during the remainder of the
year. Gorilla III was 100%
utilized offshore Trinidad during the first five months of 2008, generating
approximately $40 million of drilling revenues during the period, or more than
$249,000 per day. Gorilla III relocated to the
Gulf of Mexico during the second quarter of 2008 where the rig was 98% utilized
during the remainder of the year.
Gulf of
Mexico. The following table summarizes average oil and natural
gas prices and our Gulf of Mexico fleet utilization and average day rates by
quarter in 2008, and for the full years 2008 and 2007:
|
Oil
(per bbl) *
|
Natural
gas (MCF) *
|
Average
utilization
|
Average
day rate
|
|||||||||||||
|
2008:
|
||||||||||||||||
|
First
quarter
|
$ | 97.86 | $ | 8.74 | 91 | % | $ | 114,100 | ||||||||
|
Second
quarter
|
$ | 123.78 | $ | 11.47 | 98 | % | $ | 126,600 | ||||||||
|
Third
quarter
|
$ | 118.29 | $ | 8.98 | 100 | % | $ | 131,400 | ||||||||
|
Fourth
quarter
|
$ | 58.68 | $ | 6.40 | 100 | % | $ | 144,600 | ||||||||
|
Full
year:
|
||||||||||||||||
|
2008
|
$ | 99.67 | $ | 8.90 | 97 | % | $ | 129,900 | ||||||||
|
2007
|
$ | 72.34 | $ | 7.12 | 96 | % | $ | 129,300 | ||||||||
__________
|
*
|
Source:
New York Mercantile Exchange
(NYMEX)
|
Natural
gas prices remained at historically high levels over the first half of 2008, and
our fleet achieved stable utilization and increasing average day rates during
that period, though shipyard time for upgrades to the Bob Palmer reduced average
utilization during the first quarter. As prices weakened dramatically
over the last half of the year, our contracted backlog helped to insulate Rowan
from the effects of reduced drilling demand that ensued in the Gulf of Mexico
and throughout the United States. The addition of the Rowan-Mississippi and J.P. Bussell in November
2008, coupled with the loss of our oldest jack-up, the Rowan-Anchorage, during
Hurricane Ike in September, increased our average rate during the fourth
quarter. As shown in the preceding table, our average Gulf of Mexico
day rate increased by $1,100 or 1% during 2008, though, by year end, we had
begun to feel the impact of weakening demand for our three skid-off
rigs. Our total revenue-producing days in the Gulf of Mexico
decreased by 97 or 3% in 2008, due primarily to the effects of rig
relocations.
Land. Contracted
backlog also enabled our 30 deep-well land rigs in Texas, Louisiana, Oklahoma
and Alaska to withstand the volatile domestic market conditions during 2008, and
attain 93% utilization and an average day rate of $22,600 during the year,
compared to 95% and $22,800 in 2007. The fleet included four new 2000
horsepower rigs that were delivered during 2008, which contributed to a 701 or
7% increase in revenue-producing days during the year.
Operating
Costs. Drilling operating costs increased by
$38.4 million or 6% in 2008 compared to 2007, due primarily to effects of
the following (in millions):
|
Increase
|
||||||||
|
(Decrease)
|
%
Change
|
|||||||
|
Personnel
and related costs for existing rigs
|
$ | 19.8 | 7 | % | ||||
|
Repairs
and maintenance for existing rigs
|
19.3 | 18 | % | |||||
|
Rig
insurance costs for existing rigs
|
(11.7 | ) | -21 | % | ||||
|
Addition
of Rowan-Mississippi and
J.P. Bussell and
four land rigs
|
11.2 | - | ||||||
|
All
other
|
(0.2 | ) | - | |||||
|
Net
increase
|
$ | 38.4 | 6 | % | ||||
Depreciation
expense incurred by our drilling operations increased by $24.1 million or
24% in 2008, due primarily to the addition of the rigs noted
above. Selling, general and administrative costs increased by
$0.9 million or 1% in 2008, due primarily to higher professional service
fees resulting from our international expansion and incremental incentive
compensation costs associated with our improved financial results.
Our
drilling operations realized $68.0 million of gains on asset disposals during
2008, including $37.1 million from insurance proceeds received in connection
with the loss of the Rowan-Anchorage during
Hurricane Ike, $14.5 million from the sale of our London office, $5.4 million
from the sale of our Fourchon, Louisiana, yard and $4.7 million from the sale of
a land rig. Our 2007 net gain was $40.7 million, and included $14.1
million from the sale of our Alaska-based drilling camps and $23.4 million
related to the installment sale of the Rowan-Midland and related
equipment.
Our 2008
Drilling Services operating income included $24.6 million of special charges,
including $11.8 million for the estimated unrecoverable cost of amounts expended
on construction of our fourth 240C rig which we cancelled, $8.5 million related
to severance costs, including the impact of accelerated equity awards primarily
resulting from our CEO’s 2008 retirement, $2.8 million of primarily professional
service fees incurred in connection with the suspended LeTourneau monetization
process, and $1.5 million related to the impairment of goodwill.
Outlook
Worldwide
rig demand is inherently volatile and has historically varied from one
geographic market to the next, 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
backlog of drilling contracts as of February 16, 2010, was approximately $1.3
billion, which we estimate will be realized as follows: 2010 – $905 million,
2011 – $335 million, 2012 and later years – $70 million. About 58% of
our remaining available offshore rig days in 2010, and 17% of available days in
2011 are currently under contract, and most of our drilling contracts have
termination penalties. Though we have had several notable additions
to our drilling backlog over the past year, the total is down by approximately
one-quarter over this period.
Certain
of our customers have sought to modify existing contracts, and we have accepted
modifications in the few cases where we felt it in our best long-term interest
to do so. We intend to enforce our drilling contracts and will
vigorously defend our rights thereunder. Any such disputes may
adversely impact our results of operations and cash flows to the extent that
collections are delayed and administrative costs are increased.
As of
February 16, 2010, ten of our offshore rigs had drilling contracts estimated to
complete in 2010, eight had contracts estimated to complete in 2011, one had a
contract estimated to complete in 2012 and four were available. We
received delivery of the newly constructed Ralph Coffman in December
2009, and the rig commenced operations in the U.S. Gulf of Mexico in January
2010. Among the five rigs currently under construction and expected
to be delivered over the period from early 2010 through early 2012, we have a
contract from a customer for the use of one rig, and the remaining four are not
yet contracted.
Hurricanes
(or “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 windstorm coverage available and have dramatically increased the
cost 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 hurricane losses has also been limited.
Rowan
suffered a significant loss of prospective revenues and has incurred significant
claims for removal of wreckage from the total destruction of six rigs in four
separate storms from 2002 through 2008. Due to the increased cost and
reduced availability of coverage as discussed above, in 2009 we decided to
discontinue windstorm physical damage coverage on four of our older,
lower-specification jack-up rigs, and our coverage for removal of wreckage is
subject to a $100 million per occurrence deductible. Our windstorm
physical damage coverage is subject to a $50 million per occurrence deductible
with an annual aggregate limit of $150 million and covers only the Gorilla II, the Bob Palmer and the Rowan-Mississippi.
In each
of the past several years, the onset of hurricane season has coincided with
declines in drilling activity in the Gulf of Mexico. We expect this
pattern to continue in future years.
Our
drilling operations are currently benefiting from contracted backlog obtained
during the predominantly favorable market conditions of the past few
years. As our rigs rolled off existing contracts throughout 2009,
opportunities for new contracts were limited, and some of our rigs became and
remain idle. Such opportunities have become more prevalent in recent
months, though most encounter interest from many competing contractors and
rigs. We believe there are currently 61 jack-ups under construction
for completion by 2012, most of which do not have drilling contracts in
place. Delivery of those rigs is expected to further increase
competition among jack-up contractors. Thus, we can provide no
assurance that we will be able to replace our contract backlog as it is
realized, that we can maintain current utilization levels, that spot day rates
will remain above breakeven levels, or that our drilling operations will remain
profitable.
Manufacturing
Operations
We have
manufacturing facilities in Longview and Houston, Texas, and Vicksburg,
Mississippi, which collectively produce drilling rigs and various rig components
and mining and forestry equipment, alloy steel and steel plate under two
operating segments – Drilling Products and Systems and Mining, Forestry and
Steel Products.
The
Drilling Products and Systems segment provides equipment, parts and services for
the offshore and onshore oil and gas drilling industry. Featured
products include complete jack-up rigs, rig kits and component packages, primary
drilling equipment such as mud pumps, drawworks, top drives and rotary tables,
and electrical components such as variable-speed motors and
drives. The segment built the first offshore jack-up drilling rig in
1955 and has since designed, built or licensed the construction of more than 200
rigs, including all 23 in our fleet. During 2008, Drilling Products
and Systems completed construction of our fourth Tarzan Class rig, the J.P. Bussell, and our first
240C class rig, the
Rowan-Mississippi, and
in December 2009, completed construction of the second 240C class rig, the Ralph Coffman.
The
Mining, Forestry and Steel Products segment produces large-wheeled mining and
timber equipment and related parts and carbon and alloy steel and steel
plate.
|
|
Our
manufacturing revenues are greatly influenced by the timing of product
shipments, and our profitability is impacted by the mix of product
sales. Original equipment sales, for example, have
traditionally yielded lower margins than the related after-market parts
sales. Land rigs and component packages typically require more
costs for commissioning than do individual pumps and other drilling
equipment, and often carry a package discount. Thus, our gross
margins are typically higher on equipment sales than on rigs and component
packages.
|
2009
Compared to 2008
The
following table highlights the performance of our Drilling Products and Systems
segment for 2009 and 2008 (dollars in millions):
|
2009
|
2008
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 369.4 | 100 | % | $ | 493.5 | 100 | % | ||||||||
|
Operating
costs
|
(341.0 | ) | -92 | % | (421.5 | ) | -85 | % | ||||||||
|
Depreciation
expense
|
(9.0 | ) | -2 | % | (9.5 | ) | -2 | % | ||||||||
|
Selling,
general and administrative expenses
|
(16.0 | ) | -4 | % | (25.1 | ) | -5 | % | ||||||||
|
Material
charges and other operating expenses
|
- | 0 | % | (81.9 | ) | -17 | % | |||||||||
|
Net
gain (loss) on property disposals
|
- | 0 | % | (0.1 | ) | 0 | % | |||||||||
|
Operating
income (loss)
|
$ | 3.4 | 1 | % | $ | (44.6 | ) | -9 | % | |||||||
Revenues
from Drilling Products and Systems decreased by $124.1 million, or 25%, between
periods due primarily to the following:
|
·
|
A
decrease of $78.0 million attributable to $111.6 million of revenues
recognized on five offshore rig kit projects in 2009, as compared to
$189.6 million recognized on eight projects in
2008;
|
|
·
|
A
decrease of $36.3 million attributable to $103.0 million recognized on
shipments of land rigs and component packages in 2009, down from $139.3
million in 2008;
|
|
·
|
A
decrease of $23.8 million attributable to $1.9 million of revenues
recognized on shipments of top drives in 2009, down from $25.7 million in
2008;
|
|
·
|
An
increase of $8.6 million attributable to $50.1 million recognized on 57
mud pumps shipped in 2009, up from $41.5 million on 63 pumps in
2008.
|
Our
average margin before depreciation and selling, general and administrative
expenses decreased to 8% of revenues in 2009 from 15% in
2008. Margins in 2009 were negatively affected by sales mix, with a
greater share of revenues from some of our lower-margin products as compared to
the prior year and poor results on several land rig projects.
Selling,
general and administrative costs declined by $9.1 million or 36% between periods
due primarily to lower compensation and related fringe benefit costs associated
with reduced employment levels.
Our
Drilling Products and Systems operating results for 2009 exclude
$278.9 million of revenues and $182.3 million of expenses in connection
with sales of products and services to our Drilling Services segment, much of
which was attributable to construction of the newbuild jack-up, Ralph Coffman, and kits and
equipment provided for our EXL
rigs. Drilling Products and Systems operating results for 2008
excludes $382.9 million of revenues and $307.7 million of expenses, primarily
for construction of the J.P.
Bussell, Rowan-Mississippi and Ralph Coffman.
The
following table highlights the performance of our Mining, Forestry and Steel
Products segment for 2009 and 2008 (dollars in millions):
|
2009
|
2008
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 185.9 | 100 | % | $ | 267.6 | 100 | % | ||||||||
|
Operating
costs
|
(134.6 | ) | -72 | % | (203.3 | ) | -76 | % | ||||||||
|
Depreciation
expense
|
(6.5 | ) | -3 | % | (6.1 | ) | -2 | % | ||||||||
|
Selling,
general and administrative expenses
|
(18.8 | ) | -10 | % | (20.8 | ) | -8 | % | ||||||||
|
Material
charges and other operating expenses
|
- | 0 | % | (4.7 | ) | -2 | % | |||||||||
|
Net
loss on property disposals
|
(0.5 | ) | 0 | % | (0.1 | ) | 0 | % | ||||||||
|
Operating
income
|
$ | 25.5 | 14 | % | $ | 32.6 | 12 | % | ||||||||
Revenues
from Mining, Forestry and Steel Products decreased by $81.7 million or 31%
between periods due primarily to the following:
|
·
|
Lower
sales of new mining loaders and forestry stackers, which declined by $38.9
million or 38%, from $102.6 million in 2008 to $63.7 million in
2009. We shipped 14 new mining loaders and forestry stackers
2009, as compared to 29 units in
2008;
|
|
·
|
Lower
sales of steel plate, which declined by $35.0 million or 52%, from $66.9
million in 2008 to $31.9 million in
2009;
|
|
·
|
A
two-percent increase in part sales, to $73.3 million in 2009 from $71.9
million in 2008.
|
Our
average margin before depreciation and selling, general and administrative
expenses increased to 28% of revenues in 2009 from 24% in 2008. The
higher margins were attributable to primarily product sales mix, particularly a
greater proportion of higher-margin after-market parts and service revenues in
2009.
2008
Compared to 2007
The
following table highlights the performance of our Drilling Products and Systems
segment during 2008 compared to 2007 (dollars in millions):
|
2008
|
2007
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 493.5 | 100 | % | $ | 498.6 | 100 | % | ||||||||
|
Operating
costs
|
(421.5 | ) | -85 | % | (426.6 | ) | -86 | % | ||||||||
|
Depreciation
expense
|
(9.5 | ) | -2 | % | (11.7 | ) | -2 | % | ||||||||
|
Selling,
general and administrative expenses
|
(25.1 | ) | -5 | % | (17.2 | ) | -3 | % | ||||||||
|
Material
charges and other operating expenses
|
(81.9 | ) | -17 | % | - | 0 | % | |||||||||
|
Losses
on property disposals
|
(0.1 | ) | 0 | % | (0.1 | ) | 0 | % | ||||||||
|
Operating
income
|
$ | (44.6 | ) | -9 | % | $ | 43.0 | 9 | % | |||||||
Our
Drilling Products and Systems segment sustained a $5.1 million or 1%
decrease in revenues in 2008, which featured the following:
|
·
|
$175.4
million associated with 16 land rigs and component packages shipped in
2008, up from $148.3 million in
2007;
|
|
·
|
$153.5
million recognized on eight rig kit projects in 2008, up from $116.9
million in 2007;
|
|
·
|
$41.5
million from 63 mud pumps shipped in 2008, down from $49.8 million and 70
pumps in 2007;
|
|
·
|
$14.9
million related
to drive and control system packages, down from $33.4 million in
2007;
|
|
·
|
$12.9
million from 216 motors shipped in 2008, down from $15.2 million in 2007;
and
|
|
·
|
$7.7
million from custom fabrication work, down from $27.9 million in
2007.
|
Our 2007
operating results included $41.6 million of revenues and a $15.8 million loss on
the external rig construction project which required many more labor hours than
we originally anticipated. There were no such revenues in
2008. Thus, as is shown in the preceding table, our average margin
over operating costs increased slightly to 15% of revenues in 2008 from 14% in
2007.
Depreciation
expense incurred by Drilling Products and Systems in 2008 decreased by
$2.2 million or 19% over 2007, due primarily to incremental depreciation
related to a land rig lease transaction during 2007. Selling, general
and administrative costs increased by $7.9 million or 46% in 2008, due
primarily to higher expenses related to our sales and marketing
efforts.
Drilling
Products and Systems operating results for 2008 included material charges and
other operating expenses of $81.9 million, which included a $62.4 million charge
for estimated surplus inventory, $10.9 million for goodwill impairment, $6.4
million of allocated monetization costs and $2.2 million for severance costs
incurred in connection with headcount reductions.
Operating
results for 2008 shown in the preceding table exclude the effects of the
approximately $383 million of revenues and $308 million of expenses in
connection with products and services provided to our Drilling Services segment
during the year, most of which was attributable to construction progress on the
Rowan-Mississippi, the
J.P. Bussell and
the Ralph
Coffman.
The
following table highlights the performance of our Mining, Forestry and Steel
Products segment during 2008 compared to 2007 (dollars in
millions):
|
2008
|
2007
|
|||||||||||||||
|
Amount
|
%
of Revenues
|
Amount
|
%
of Revenues
|
|||||||||||||
|
Revenues
|
$ | 267.6 | 100 | % | $ | 213.8 | 100 | % | ||||||||
|
Operating
costs
|
(203.3 | ) | -76 | % | (169.9 | ) | -79 | % | ||||||||
|
Depreciation
expense
|
(6.1 | ) | -2 | % | (5.3 | ) | -2 | % | ||||||||
|
Selling,
general and administrative expenses
|
(20.8 | ) | -8 | % | (9.4 | ) | -4 | % | ||||||||
|
Material
charges and other operating expenses
|
(4.7 | ) | -2 | % | - | 0 | % | |||||||||
|
Losses
on property disposals and other
|
(0.1 | ) | 0 | % | (0.1 | ) | 0 | % | ||||||||
|
Operating
income
|
$ | 32.6 | 12 | % | $ | 29.1 | 14 | % | ||||||||
Our
Mining, Forestry and Steel Products segment achieved an aggregate
$53.8 million or 25% increase in revenues in 2008, which featured the
following:
|
·
|
$107.9
million of equipment revenues in 2008, up from $94.9 million in 2007;
shipments of mining loaders and forestry stackers totaled 29 units in
2008, down from 30 units in 2007, though 16 of the 2008 units were the
larger L-1850 model which carry a higher selling price, up from 13 larger
units in 2007;
|
|
·
|
$71.9
million from parts sales in 2008, up from $62.6 million in
2007;
|
|
·
|
$66.9
million from steel plate revenues in 2008, up from $41.2 million in 2007;
shipments totaled 61,900 tons in 2008, up by 9,000 tons or 17% over 2007,
and the mix changed from 51% external in 2007 to 59% external in 2008,
yielding a 33% increase in external volume between
years.
|
Thus, as
is shown in the preceding table, our average margin on operating costs increased
to 24% of revenues in 2008 from 21% in 2007.
Depreciation
expense incurred by Mining, Forestry and Steel Products in 2008 increased by
$.8 million or 15% from 2007, due to machinery and equipment additions made
in the previous year to increase our manufacturing capacity. Selling,
general and administrative costs increased by $11.4 million or 121% in
2008, due primarily to higher expenses related to our sales and marketing
efforts and increased amounts of professional fees and other shared
administrative costs that are allocated between our manufacturing segments based
upon revenues.
Mining,
Forestry and Steel Products operating results for 2008 included charges and
other operating expenses of $4.7 million, which included $3.5 million of
allocated monetization costs and $1.2 million for goodwill
impairment.
Outlook
Our
manufacturing operations are highly impacted by world commodities
prices. Our Drilling Products and Systems segment is closely tied to
the condition of the overall drilling industry and demand for drilling
equipment, parts and services. The prospects for our Mining, Forestry
and Steel Products segment are strongly affected by prices for copper, iron ore,
coal and timber. The volatility of commodity prices and weakness in
global capital markets over the latter half of 2008 and much of 2009 resulted in
reduced demand for most of the manufactured products and services that we offer,
though prices and demand, particularly for mined commodities, began improving in
late 2009. We cannot predict the duration of the current operating
environment or quantify the impact that current business conditions will have on
our future operations.
Our
external manufacturing backlog, which consists of executed contracts and
customer commitments, was approximately $413 million at December 31, 2009,
compared to $562 million at December 31, 2008, and included $217 million related
to offshore rig projects, $71 million related to land rig projects, $67 million
of mining and forestry equipment, $29 million of drilling equipment and $29
million primarily for parts and other components. We expect that
about 95% of our external backlog at December 31, 2009, will be realized as
revenue in 2010 and the balance in 2011 and 2012. We can provide no
assurance we will be able to maintain or significantly increase our backlog
going forward.
Facing
reduced liquidity, certain of our customers sought to modify existing orders by
delaying deliveries and related payments. Others attempted to reduce
or cancel orders altogether. Though we fully intend to enforce our
contractual rights, such actions by our customers could adversely impact our
results of operations and cash flows to the extent that collections are delayed,
administrative costs are increased, and we are otherwise unable to fully recover
the in-process cost attributable to such orders. We estimate that
approximately $15 million or less than 4% of our December 31, 2009,
manufacturing backlog is at risk of being delayed or canceled. Should
market conditions worsen, these actions may intensify, though we cannot assess
that likelihood or the resulting impact on our results of operations or cash
flows.
We
currently have no further plans for rig construction at our Vicksburg shipyard
following the delivery of our third 240C class rig, the Joe Douglas, in
2011. Absent additional orders or sufficient prospects for future
work, the activities at the facility would be significantly reduced at that
time, in which case we would incur additional costs such as employee
severance, among other charges. Closing or significantly reducing
activity levels at the facility could result in the incurrence of cash charges
ranging from $5 million to $6 million and noncash charges ranging from $7
million to $10 million.
LIQUIDITY
AND CAPITAL RESOURCES
Key
balance sheet amounts and ratios for 2009 and 2008 were as follows (dollars in
millions):
|
December
31,
|
December
31,
|
|||||||
|
2009
|
2008
|
|||||||
|
Cash
and cash equivalents
|
$ | 639.7 | $ | 222.4 | ||||
|
Current
assets
|
$ | 1,549.8 | $ | 1,369.2 | ||||
|
Current
liabilities
|
$ | 568.3 | $ | 744.6 | ||||
|
Current
ratio
|
2.73 | 1.84 | ||||||
|
Current
maturities of long-term debt
|
$ | 64.9 | $ | 64.9 | ||||
|
Long-term
debt, less current maturities
|
$ | 787.5 | $ | 355.6 | ||||
|
Stockholders'
equity
|
$ | 3,110.4 | $ | 2,659.8 | ||||
|
Long-term
debt/total capitalization
|
0.20 | 0.12 | ||||||
Reflected
in the comparison above are the effects of the following sources and uses of
cash and cash equivalents in 2009, with comparable amounts for
2008:
|
2009
|
2008
|
|||||||
|
Net
operating cash flows
|
$ | 544.1 | $ | 694.5 | ||||
|
Borrowings,
net of issue costs
|
491.7 | 80.0 | ||||||
|
Proceeds
from asset disposals
|
8.6 | 97.6 | ||||||
|
Proceeds
from equity compensation and debenture plans and other
|
1.5 | 33.8 | ||||||
|
Capital
expenditures
|
(566.4 | ) | (829.1 | ) | ||||
|
Debt
repayments
|
(64.9 | ) | (144.9 | ) | ||||
|
Cash
dividend payments
|
- | (45.0 | ) | |||||
|
Net
change in restricted cash balance
|
- | 50.0 | ||||||
|
All
other, net
|
2.7 | 1.1 | ||||||
|
Total
sources (uses)
|
$ | 417.3 | $ | (62.0 | ) | |||
Operating
Cash Flows
Operating
cash flows approximated $544.1 million for 2009 as compared to $694.5 million
for 2008. Our cash flows from operations have benefited and will
continue to benefit from long-term drilling contracts entered into when rates
were significantly higher than current market rates. Several of our
offshore rigs are operating under contracts at above-market rates negotiated in
periods of stronger demand. As a result, operating cash flows may be
negatively affected in the future as these higher day-rate contracts are
completed.
Capital
Expenditures
Capital
expenditures in 2009 totaled $566 million and included:
|
·
|
$261
million towards construction of the four EXL class
rigs;
|
|
·
|
$99
million towards construction of our second and third 240C class rigs,
the Ralph Coffman
and Joe
Douglas;
|
|
·
|
$164
million for improvements to the existing offshore
fleet;
|
|
·
|
$8
million for our land rig fleet, including $5 million towards construction
of two new land rigs.
|
The
remaining $34 million included the cost of drill pipe, improvements to our rig
service and repair facility at Sabine Pass and other enhancements.
Reference
should be made to Note 6 of “Notes to Consolidated Financial Statements” in this
Form 10-K for a detailed status of our newbuild projects.
Our 2010
capital budget, as approved by our Board of Directors, is approximately
$501 million, and includes $107 million toward construction of the
240C-class rig, Joe
Douglas, $229 million toward construction of the four EXL class rigs and $119 million
for upgrades to existing rigs.
Over the
past few years, as a result of our fleet expansion program, our cash flows from
operations have not been sufficient to cover our capital expenditures and debt
service requirements. As noted under “Long-term Debt” below, in July
2009, the Company completed the issuance and sale of $500 million aggregate
principal amount of 7.875% Senior Notes due August 2019 (the “Senior Notes”),
and received net proceeds of $492 million. Despite the current weak
operating environment, we anticipate that our cash flows from operations will
continue to cover a significant amount of our capital expenditures, debt
service, and other cash requirements over the next twelve months, and cash flows
from operations plus available cash balances will be sufficient to meet such
requirements over this period.
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 drilling and manufacturing businesses, the availability of financing
sources, and alternative uses of capital to enhance shareholder
value. Certain such adjustments would require Board
approval.
Long-term
Debt
On July
21, 2009, the Company completed the issuance and sale of $500 million aggregate
principal amount of 7.875% Senior Notes. Net proceeds to the Company,
after underwriting discount and offering expenses, were $492
million. The Company intends to use the net proceeds from the
offering for general corporate purposes. Interest on the Senior Notes
is payable in semi-annual installments of $19.7 million on February 1 and August
1 of each year, commencing in 2010. No principal payments are
required prior to maturity.
The
Company may, at its option, redeem all or part of the Senior Notes at any time
at a make-whole price. The Senior Notes are general unsecured, senior
obligations that rank (a) pari
passu in right of payment with any of the Company’s existing and future
unsecured indebtedness that is not by its terms subordinated to the Senior
Notes, including any indebtedness under the Company’s senior revolving credit
facility (other than letter of credit reimbursement obligations that are secured
by cash deposits), (b) effectively junior to the Company’s existing and future
secured indebtedness (including indebtedness under its secured notes issued
pursuant to the MARAD Title XI program to finance several offshore drilling
rigs), in each case, to the extent of the value of the Company’s assets
constituting collateral securing that indebtedness and (c) effectively junior to
all existing and future indebtedness and other liabilities of the Company’s
subsidiaries (other than indebtedness and liabilities owed to the
Company).
In August
2009, we fixed the interest rate for the remaining term on the $65.7 million of
outstanding MARAD debt collateralized by the offshore rig, Bob Keller, at an annual rate
of 3.525%. Prior to that time, the rate floated based on a short-term
commercial-paper rate plus 0.15%.
In
November 2009, we fixed the interest rate for the remaining term on the $124.9
million of outstanding MARAD debt collateralized by the offshore rig, Bob Palmer, at an annual rate
of 3.158%. Prior to that time, the rate floated based on a short-term
commercial-paper rate plus 0.25%.
Rowan’s
first two Tarzan Class
jack-up rigs and each of our four Super Gorilla class rigs were
substantially financed through long-term bank loans guaranteed by the
U.S. Department of Transportation’s Maritime Administration (“MARAD”).
Under the MARAD Title XI program, we obtained financing as a reimbursement
for qualifying expenditures up to a pre-approved limit and based upon actual
construction progress. Each note requires semi-annual payments of
principal and interest and is secured by a preferred mortgage on the
rig. The following table summarizes the status of each of our
Title XI borrowings at December 31, 2009 (dollars in
millions):
|
Rig
|
Delivery
|
Borrowings
|
Repayments
|
Balance
|
Interest
rate (a)
|
Principal
repayment dates
|
Principal
repayment amounts
|
Final
maturity
|
|||||||||||||||
|
Gorilla
V
|
Dec
1998
|
$ | 153.1 | $ | 140.4 | $ | 12.7 | 6.50 | % |
Jan 1,
July 1
|
$ | 6.4 |
Jul
2010
|
||||||||||
|
Gorilla
VI
|
Jun
2000
|
171.0 | 135.4 | 35.6 | 5.88 | % |
Mar 15,
Sep 15
|
$ | 7.1 |
Mar
2012
|
|||||||||||||
|
Gorilla
VII
|
Dec
2001
|
185.4 | 123.6 | 61.8 | 2.80 | % |
Apr 20,
Oct 20
|
$ | 7.7 |
Oct
2013
|
|||||||||||||
|
Scooter
Yeargain
|
Apr
2004
|
91.2 | 33.4 | 57.8 | 4.33 | % |
May 1,
Nov 1
|
$ | 3.0 |
May
2019
|
|||||||||||||
|
Bob
Keller
|
Aug
2005
|
89.7 | 26.9 | 62.8 | 3.53 | % |
May 1,
Nov 1
|
$ | 3.0 |
May
2020
|
|||||||||||||
|
Bob
Palmer
|
Aug
2003
|
187.3 | 62.4 | 124.9 | 3.16 | % |
Jan 15,
July 15
|
$ | 5.2 |
Jul
2021
|
|||||||||||||
|
Total
|
$ | 877.7 | $ | 522.1 | $ | 355.6 | |||||||||||||||||
|
(a)
Interest rates are as of December 31, 2009. The interest rate for the
Gorilla V is a weighted-average of
two notes for that rig.
|
|||||||||||||||||||||||
Our debt
agreements contain provisions that require minimum levels of working capital and
stockholders’ equity and limit the amount of long-term debt and, in the event of
noncompliance, restrict investment activities, asset purchases and sales, lease
obligations, borrowings and mergers or acquisitions. Our debt agreements also
specify the minimum insurance coverage for our financed rigs. The
extent of hurricane damage sustained throughout the Gulf Coast area in recent
years has dramatically increased the cost and reduced the availability of
insurance coverage for windstorm losses. As a result, we determined that
windstorm coverage meeting the requirements of our existing debt agreements was
cost-prohibitive. At the Company’s request, MARAD waived certain
windstorm insurance coverage requirements under the loan agreements, for which
the Company agreed to a covenant to maintain a minimum cash balance, which is
currently $25 million. Rowan remains subject to restrictions on the
use of certain insurance proceeds should the Company experience future windstorm
losses. Each of these security provisions will be released by MARAD
should Rowan be able to obtain windstorm coverage that satisfies the original
terms of its debt agreements.
In June
2008, we entered into a three-year $155 million revolving credit facility, which
we intend to use, as necessary, for general corporate purposes. The
underlying credit agreement limits new borrowings, requires minimum cash flows,
provides that the facility will not be available in the event of a material
adverse change in our condition, operations, business, assets, liabilities or
ability to perform, and otherwise contains restrictions similar to those noted
above. We had no borrowings outstanding under the credit facility at
December 31, 2009. We believe that funding under the credit facility
continues to be available, if necessary.
We were
in compliance with each of our debt covenants at December 31, 2009 and, based on
current projections, we expect to be in compliance in 2010. We
believe our most restrictive financial covenant is the requirement that our
prior 12-month earnings before interest, taxes and depreciation be at least
three times interest expense. At December 31, 2009, we exceeded that
requirement by $579 million.
Pension
Obligations
Minimum
pension contributions 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. As of December 31, 2009, our
financial statements reflected an aggregate unfunded pension liability of $195
million, most of which relates to our drilling employees’ plan. In
order to slow the rate at which plan benefits were growing, we amended the
benefit formula for new drilling plan entrants effective January 1, 2008, and
further amended the plan for remaining active participants effective July 1,
2009. The plan changes that became effective in 2009 resulted in an
approximately $15 million annualized reduction in pension
expense. Despite the changes to the drilling plan, we will need to
make significant pension contributions over the next several years, and
additional funding would be required if asset values decline. We
currently expect to make minimum pension contributions of approximately
$57 million in 2010.
Cash
Dividends
In May
2006, our Board of Directors approved a regular quarterly cash dividend of $0.10
per common share, which we paid approximately every three months thereafter
through November 2008. In January 2009, in light of prevailing
business conditions, our Board of Directors decided to discontinue the payment
of dividends, and no dividends have been paid since that time. Future
dividends, if any, will only be paid at the discretion of the Board of
Directors. At December 31, 2009, we had approximately
$615 million of retained earnings available for distribution to
stockholders under provisions of our debt agreements. We do not
expect to pay dividends in the foreseeable future.
Proceeds
from Asset Disposals
In 2008,
we sold our London office building for $17.6 million and a land rig for $10.8
million, and recognized gains of $14.5 million and $4.7 million, respectively.
In 2008 we also received approximately $16.5 million in cash and recognized a
$5.4 million gain in connection with the sale of our Fourchon, Louisiana service
facility.
In 2008,
we lost the jack-up rig Rowan-Anchorage
during Hurricane Ike. The rig was insured for $60 million and subject to
a $17.5 million deductible. In 2008, we received the full $42.5
million of insurance proceeds and recognized a $37.1 million gain.
In 2005,
we sold our semi-submersible rig, the Rowan-Midland, for
approximately $60 million in cash, which was received over a 15-month period
ending in January 2007, at which time title to the rig was transferred to the
buyer. We retained ownership of much of the drilling equipment on the
rig through 2006 and 2007 and continued to provide a number of operating
personnel under a separate services agreement through February
2007. The transaction was accounted for as a sales-type lease with
the expected gain on sale and imputed interest income of approximately $46
million deferred until the net book value of the rig had been
recovered. During 2007, we received remaining payments totaling $23.4
million and recognized such amount as additional gain on the
sale. Another $14.1 million of gain was realized in 2007 on the June
sale of our Alaska drilling camps.
Contractual
Obligations and Commercial Commitments
The
following is a summary of our contractual obligations at December 31, 2009
(dollars in millions):
|
Payments
due by period
|
||||||||||||||||||||
|
Total
|
Within
1 year
|
2
to 3 years
|
4
to 5 years
|
After
5 years
|
||||||||||||||||
|
Long-term
debt obligations, including interest
|
$ | 1,312 | $ | 117 | $ | 195 | $ | 152 | $ | 848 | ||||||||||
|
Purchase
obligations, including capital expenditures
|
1,254 | 761 | 493 | - | - | |||||||||||||||
|
Operating
leases
|
17 | 6 | 5 | 2 | 4 | |||||||||||||||
|
Total
|
$ | 2,583 | $ | 884 | $ | 693 | $ | 154 | $ | 852 | ||||||||||
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 $42.0 million at December 31, 2009.
Based on
current and anticipated near-term operating levels, we believe that operating
cash flows together with existing working capital and our currently available
borrowing capacity will be adequate to sustain planned capital expenditures and
debt service and other requirements at least through the remainder of
2010.
Contingent
Liabilities
Reference
should be made to Note 6 of “Notes to Consolidated Financial Statements” in Item
8 of this Form 10-K for a discussion of the status of significant legal
proceedings.
Critical
Accounting Policies and Management Estimates
Rowan’s
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 revenue
recognition (primarily upfront service fees for equipment moves and
modifications and longer-term manufacturing projects), inventory (primarily
valuation allowances for excess and obsolete inventories), property and
depreciation (particularly capitalizable costs, useful lives and salvage
values), 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.
Revenue
recognition
Our
drilling contracts generally provide for payment on a day rate basis, and
revenues are recognized as the work progresses with the passage of
time. We frequently receive lump-sum payments at the outset of a
drilling assignment as upfront service fees for equipment moves or
modifications, and such payments (and related costs) are recognized as drilling
revenues (and expenses) over the contract period. At December 31,
2009, we had deferred $38.4 million of revenues and $27.5 million of costs
related to such upfront service fees, with such amounts primarily related to
mobilization and modification activities in connection with our foreign drilling
contracts.
We also
recognize revenue for certain reimbursable costs. Each reimbursable
item and amount is stipulated in our drilling contract with the customer, and
such items and amounts frequently vary between contracts. We have
recognized reimbursable costs on the gross basis, as both revenues and expenses,
because we are the primary obligor in the arrangement, we have discretion in
supplier selection, we are involved in determining product or service
specifications and we assume full credit risk related to the reimbursable
costs.
We
generally recognize manufacturing sales and related costs when title passes as
products are shipped. Revenues from longer-term contracts such as for
the construction of offshore rigs and rig kits are recognized on the
percentage-of-completion basis using contract costs incurred relative to total
estimated project costs. An offshore rig construction project
typically occurs over a two-year period at our Vicksburg, Mississippi, shipyard
and includes a significant labor cost component for fabrication and
assembly. A rig kit includes selected rig components and parts
manufactured over a six- to nine-month period in our Longview, Texas,
facility. Costs are recorded separately for each offshore rig or rig
kit project, and by significant activity or component within each project, and
include materials issued to the project, labor expenses that are incurred
directly for the project and overhead expenses that are allocated across all
projects at consistent rates per labor hour.
Incurred
costs include only those that measure project work
performed. Material costs incurred, for example, do not include
materials purchased but remaining in inventory. Only when such
materials have been used in production on the project are they included in
incurred project costs. The determination of total estimated project
costs is performed monthly based upon then-current information. This
process involves an evaluation of progress towards project milestones and an
assessment of work left to complete each project activity or component, and is
based on physical observations by project managers and engineers. An
estimate of project costs is then developed for each significant activity or
component based upon the assessment of project status, actual costs incurred to
date and outstanding commitments for project materials and
services. We do not recognize any estimated profit until such
projects are at least 10% complete, though a full provision is made immediately
for any anticipated losses.
During
2007, we recognized a $15.8 million loss on our external rig construction
project, bringing the total loss on the project to approximately $17.9
million. This was the first rig construction project for an external
customer that we had performed in over a decade, and we have no further plans
for additional external rig construction projects at this time. With
respect to our rig kits, due to the smaller size and duration of the projects
and lesser labor cost component, we have not experienced any significant
fluctuations in the percentage-of-completion measurements, nor have we incurred
any losses on such projects. In 2009 we recognized $101.4 million of
manufacturing revenues and $69.5 million of costs related to rig kit projects on
the percentage-of-completion basis.
Inventory
Inventory
is carried at the lower of average cost or estimated net realizable value. Costs
include labor, material and an allocation of production overhead. We
determine valuation allowances or reserves for inventory based on historical
usage of inventory on-hand, assumptions about future demand based on market
conditions, and estimates about potential alternative uses, which are usually
limited. Our inventory generally consists of spare parts, work in process, and
raw materials to support ongoing manufacturing operations and the Company’s
installed base of drilling, mining and timber equipment. Customers
rely on us to stock these specialized items to ensure that their equipment can
be repaired and serviced in a timely manner. The estimated carrying
value of our inventory therefore ultimately depends upon demand driven by oil,
natural gas and other commodity prices, general economic conditions worldwide
and the potential obsolescence of various types of equipment we sell, among
other factors. At December 31, 2009 and 2008, our inventory
reserves totaled 8% and 13% of gross inventory, respectively. As a
result of declines in oil and natural gas prices, the onset of global recession
and weakness in capital markets in 2008, we reduced our estimates of the future
usage of our drilling equipment inventories and significantly increased our
inventory valuation reserves at December 31, 2008.
Further
deterioration in worldwide demand for oil, natural gas and certain other
commodities, or the development of new technologies which make older drilling,
mining and timber equipment technologies obsolete, could require us to record
additional reserves to reduce the value of our inventory.
Property
and depreciation
Expenditures
for new property or enhancements to existing property are capitalized, and
expenditures for maintenance and repairs are charged to operations as
incurred. Capitalized cost includes labor expended during
installation and, on newly constructed assets, a portion of interest cost
incurred during the construction period. We provide depreciation
under the straight-line method from the date an asset is placed into service
based upon estimated service lives ranging up to 40 years and salvage values
ranging up to 20%. Thirteen of our twenty-three jack-up rigs were
placed into service at various dates during the period from 1971 to
1986. Many of those rigs had met or far exceeded their assigned
useful lives of 12 to 15 years by the time our Super Gorilla class rig, the
Gorilla V, was
delivered in 1998. The Super Gorilla class and the
subsequent Tarzan Class
and 240C
class have been
assigned 25-year useful lives. Each class of rig has been
specifically designed to achieve greater drilling performance while encountering
tougher well conditions and employs technological advances in load-bearing
capability, power distribution, and solids control designed to provide more
efficient drilling to greater depths, helping to ensure continuing economic life
to the Company.
Impairment
of long-lived assets
We
evaluate the carrying value of our property and equipment, primarily our
drilling rigs, when events or changes in circumstances indicate that the
carrying value of such rigs may not be recoverable. Generally, extended periods
of idle time and/or our inability to contract rigs at economical rates are an
indication that a rig may be impaired. However, 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
change. Likewise, during periods of excess supply, rigs are
frequently 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 carrying values of assets and
operating results.
Pension
and other postretirement benefit liabilities and costs
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, 2009, included discount rates ranging from 5.83% to 5.97%, an
expected long-term rate of return on pension plan assets of 8% and annual
healthcare cost increases ranging from 8.7% in 2010 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 $90 million, while a
one-percentage-point change in the expected long-term rate of return on plan
assets would change annual net benefits cost by approximately $3.5
million. A one-percentage-point increase in the assumed healthcare
cost trend rate would increase 2010 net other postretirement benefit cost by
$0.6 million.
Income
taxes
As
discussed in Note 9 to the financial statements, in 2009 we recognized tax
benefits of $25 million as a result of applying our facts to a recent
third-party tax case that provides a more favorable tax treatment for certain
foreign contracts entered into in prior years. In accordance with
accounting guidelines for income tax uncertainties, we evaluate a tax position
to determine if it is more likely than not that the tax position will be
sustained upon examination, based on its merits. A tax position that
meets the more-likely-than-not recognition threshold is subject to a measurement
assessment to determine the amount of benefit to recognize in income for the
period, and a reserve, if any. Our income tax returns are subject to
audit by U.S. federal, state, and foreign tax
authorities. Determinations by such taxing authorities that differ
materially from our recorded estimates, either favorably or unfavorably, may
have a material impact on our results of operations, financial position and cash
flows. We believe our reserve for uncertain tax positions totaling
$55 million at December 31, 2009, is properly recorded in accordance with the
accounting guidelines.
New
Accounting Standards
In
October 2009, the FASB issued Accounting Standards Update (“ASU”) No. 2009-13,
Revenue Recognition (Topic
605), Multiple-Deliverable Revenue Arrangements, a consensus of the FASB
Emerging Issues Task Force. ASU No. 2009-13 addresses
accounting by vendors who provide multiple products or services to customers at
different points in time or over different time
periods. Specifically, ASU No. 2009-13 eliminates the residual method
of allocating revenues to each activity and requires that revenue be allocated
at inception of the arrangement to all deliverables using a relative selling
price method. ASU No. 2009-13 is effective for fiscal years beginning
on or after June 15, 2010 and may be applied prospectively for arrangements
entered into after the effective date or retrospectively for all periods
presented. The Company is currently studying what impact, if any,
adoption may have on its financial statements.
Rowan’s
outstanding debt at December 31, 2009, was comprised entirely of fixed-rate
debt with a carrying value of $852.4 million, bearing a weighted-average
annual interest rate of 6.2%. Due to the fixed-rate nature of the
Company’s debt, management believes the risk of loss due to changes in market
interest rates is not material.
The
majority of Rowan’s transactions are denominated in United States dollars. The
Company has some exposure to currency exchange fluctuations primarily in Brazil
and Australia as a result of its manufacturing presence in those
countries. In order to reduce the impact of exchange rate
fluctuations, Rowan generally requires customer payments to be in U.S. dollars
and limits foreign currency holdings to the extent they are needed to pay
liabilities denominated in such currencies. The Company recognized a
net foreign currency gain of $5.4 million in 2009 and a loss of $10.8 million in
2008, primarily attributable to operations in Australia and Brazil.
Fluctuating
commodity prices affect Rowan’s future earnings materially to the extent that
they influence demand for the Company’s products and services. As a
general practice, Rowan does not hold or issue derivative financial
instruments.
|
INDEX
|
Page
|
|
Consolidated
Balance Sheets, December 31, 2009 and 2008
|
42
|
|
Consolidated
Statements of Income for the Years Ended December 31, 2009, 2008 and
2007
|
43
|
|
Consolidated
Statements of Comprehensive Income for the Years Ended December 31,
2009, 2008 and 2007
|
44
|
|
Consolidated
Statements of Changes in Stockholders’ Equity for the Years Ended
December 31, 2009, 2008 and 2007
|
45
|
|
Consolidated
Statements of Cash Flows for the Years Ended December 31, 2009, 2008
and 2007
|
46
|
|
Notes
to Consolidated Financial Statements
|
47
|
|
Report
of Independent Registered Public Accounting Firm
|
71
|
|
Management’s
Report On Internal Control Over Financial Reporting Pursuant To
Section 404 Of The Sarbanes-Oxley Act of 2002
|
72
|
|
Report
of Independent Registered Public Accounting Firm
|
73
|
|
Selected
Quarterly Financial Data (Unaudited)
|
74
|
Rowan
Companies, Inc.
CONSOLIDATED
BALANCE SHEETS
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
(In
thousands, except share amounts)
|
||||||||
|
ASSETS
|
||||||||
|
CURRENT
ASSETS:
|
||||||||
|
Cash
and cash equivalents
|
$ | 639,681 | $ | 222,428 | ||||
|
Receivables
- trade and other
|
343,642 | 484,962 | ||||||
|
Inventories
- at cost:
|
||||||||
|
Raw
materials and supplies
|
309,682 | 337,503 | ||||||
|
Work-in-progress
|
141,036 | 213,177 | ||||||
|
Finished
goods
|
941 | 749 | ||||||
|
Prepaid
expenses and other current assets
|
76,744 | 59,466 | ||||||
|
Deferred
tax assets - net
|
38,071 | 50,902 | ||||||
|
Total
current assets
|
1,549,797 | 1,369,187 | ||||||
|
PROPERTY,
PLANT AND EQUIPMENT - at cost:
|
||||||||
|
Drilling
equipment
|
3,975,006 | 3,503,590 | ||||||
|
Manufacturing
plant and equipment
|
251,882 | 249,725 | ||||||
|
Construction
in progress
|
528,669 | 425,182 | ||||||
|
Other
property and equipment
|
144,337 | 126,915 | ||||||
|
Property,
plant and equipment - gross
|
4,899,894 | 4,305,412 | ||||||
|
Less
accumulated depreciation and amortization
|
1,320,409 | 1,157,884 | ||||||
|
Property, plant and
equipment - net
|
3,579,485 | 3,147,528 | ||||||
|
Other
assets
|
81,412 | 32,177 | ||||||
|
TOTAL
ASSETS
|
$ | 5,210,694 | $ | 4,548,892 | ||||
|
LIABILITIES
AND STOCKHOLDERS' EQUITY
|
||||||||
|
CURRENT
LIABILITIES:
|
||||||||
|
Current
maturities of long-term debt
|
$ | 64,922 | $ | 64,922 | ||||
|
Accounts
payable - trade
|
124,562 | 235,048 | ||||||
|
Deferred
revenues
|
139,398 | 174,086 | ||||||
|
Billings
in excess of costs and estimated profits on uncompleted
contracts
|
25,226 | 57,119 | ||||||
|
Accrued
liabilities
|
214,164 | 213,467 | ||||||
|
Total
current liabilities
|
568,272 | 744,642 | ||||||
|
Long-term
debt - less current maturities
|
787,490 | 355,560 | ||||||
|
Other
liabilities
|
278,862 | 362,026 | ||||||
|
Deferred
income taxes - net
|
465,700 | 426,848 | ||||||
|
Commitments
and contingent liabilities (Note 6)
|
- | - | ||||||
|
STOCKHOLDERS'
EQUITY:
|
||||||||
|
Preferred
stock, $1.00 par value, 5,000,000 shares authorized, issuable in
series:
|
||||||||
|
Series
C Preferred Stock, 9,606 shares authorized, none
outstanding
|
- | - | ||||||
|
Series
A Junior Preferred Stock, 1,500,000 shares authorized, none
issued
|
- | - | ||||||
|
Common
stock, $0.125 par value, 150,000,000 shares authorized, 113,885,661 shares
and 113,115,830 shares issued at December 31, 2009 and 2008,
respectively
|
14,237 | 14,141 | ||||||
|
Additional
paid-in capital
|
1,078,337 | 1,063,202 | ||||||
|
Retained
earnings
|
2,169,526 | 1,802,022 | ||||||
|
Cost
of 52,342 and 79,948 treasury shares at December 31, 2009 and 2008,
respectively
|
(1,409 | ) | (2,533 | ) | ||||
|
Accumulated
other comprehensive loss
|
(150,321 | ) | (217,016 | ) | ||||
|
Total
stockholders' equity
|
3,110,370 | 2,659,816 | ||||||
|
TOTAL
LIABILITIES AND STOCKHOLDERS' EQUITY
|
$ | 5,210,694 | $ | 4,548,892 | ||||
See Notes
to Consolidated Financial Statements.
Rowan
Companies, Inc.
CONSOLIDATED
STATEMENTS OF INCOME
|
For
the years ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
thousands, except per share amounts)
|
||||||||||||
|
REVENUES:
|
||||||||||||
|
Drilling
services
|
$ | 1,214,896 | $ | 1,451,623 | $ | 1,382,571 | ||||||
|
Manufacturing
sales and services
|
555,284 | 761,113 | 712,450 | |||||||||
|
Total
revenues
|
1,770,180 | 2,212,736 | 2,095,021 | |||||||||
|
COSTS
AND EXPENSES:
|
||||||||||||
|
Drilling
services (excluding items below)
|
525,157 | 629,795 | 591,412 | |||||||||
|
Manufacturing
sales and services (excluding items below)
|
475,553 | 624,815 | 596,541 | |||||||||
|
Depreciation
and amortization
|
171,445 | 141,395 | 118,796 | |||||||||
|
Selling,
general and administrative
|
102,760 | 115,226 | 94,905 | |||||||||
|
Gain
on disposals of property and equipment
|
(5,748 | ) | (30,701 | ) | (40,506 | ) | ||||||
|
Material
charges and other operating expenses
|
- | 111,171 | - | |||||||||
|
Gain
on hurricane-related event
|
- | (37,088 | ) | - | ||||||||
|
Total
costs and expenses
|
1,269,167 | 1,554,613 | 1,361,148 | |||||||||
|
INCOME
FROM OPERATIONS
|
501,013 | 658,123 | 733,873 | |||||||||
|
OTHER
INCOME (EXPENSE):
|
||||||||||||
|
Interest
expense
|
(29,514 | ) | (18,624 | ) | (25,913 | ) | ||||||
|
Interest
capitalized
|
21,486 | 17,426 | 9,977 | |||||||||
|
Interest
income
|
1,240 | 6,295 | 20,923 | |||||||||
|
Other
- net
|
6,866 | (9,129 | ) | 226 | ||||||||
|
Total
other income (expense) - net
|
78 | (4,032 | ) | 5,213 | ||||||||
|
INCOME
BEFORE INCOME TAXES
|
501,091 | 654,091 | 739,086 | |||||||||
|
Provision
for income taxes
|
133,587 | 226,463 | 255,286 | |||||||||
|
NET
INCOME
|
$ | 367,504 | $ | 427,628 | $ | 483,800 | ||||||
|
PER
SHARE AMOUNTS:
|
||||||||||||
|
Net
income - basic
|
$ | 3.24 | $ | 3.80 | $ | 4.36 | ||||||
|
Net
income - diluted
|
$ | 3.24 | $ | 3.77 | $ | 4.31 | ||||||
See Notes
to Consolidated Financial Statements.
Rowan
Companies, Inc.
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
|
For
the years ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
thousands)
|
||||||||||||
|
NET
INCOME
|
$ | 367,504 | $ | 427,628 | $ | 483,800 | ||||||
|
Other
comprehensive income (loss):
|
||||||||||||
|
Pension
and other postretirement benefit adjustments, net of income tax expense
(benefit) of $35,912, ($65,095) and $7,670, respectively
|
66,695 | (120,891 | ) | 14,245 | ||||||||
|
COMPREHENSIVE
INCOME
|
$ | 434,199 | $ | 306,737 | $ | 498,045 | ||||||
See Notes
to Consolidated Financial Statements.
Rowan
Companies, Inc.
CONSOLIDATED
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
|
Shares
of common stock outstanding
|
Common
stock
|
Additional
paid-in capital
|
Retained
earnings
|
Treasury
stock
|
Accumulated
other comprehensive income (loss)
|
Total
stockholders' equity
|
||||||||||||||||||||||
|
(In
thousands)
|
||||||||||||||||||||||||||||
|
Balance,
January 1, 2007
|
110,462 | $ | 13,808 | $ | 988,998 | $ | 981,610 | $ | - | $ | (110,370 | ) | $ | 1,874,046 | ||||||||||||||
|
Stock
issued under share-based compensation plans
|
826 | 103 | 13,143 | - | - | - | 13,246 | |||||||||||||||||||||
|
Cash
dividends ($0.40 per common share)
|
- | - | - | (44,368 | ) | - | - | (44,368 | ) | |||||||||||||||||||
|
Stock-based
compensation
|
- | - | 8,418 | - | - | - | 8,418 | |||||||||||||||||||||
|
Excess
tax benefit from stock-based compensation plans
|
- | - | 1,655 | - | - | - | 1,655 | |||||||||||||||||||||
|
Treasury
stock acquired
|
(25 | ) | - | - | - | (979 | ) | - | (979 | ) | ||||||||||||||||||
|
Retirement
benefit adjustments, net of taxes of $7,670
|
- | - | - | - | - | 14,245 | 14,245 | |||||||||||||||||||||
|
Adjustment
resulting from adoption of new guidance for uncertain tax
positions
|
- | - | - | (1,625 | ) | - | - | (1,625 | ) | |||||||||||||||||||
|
Net
income
|
- | - | - | 483,800 | - | - | 483,800 | |||||||||||||||||||||
|
Balance,
December 31, 2007
|
111,263 | 13,911 | 1,012,214 | 1,419,417 | (979 | ) | (96,125 | ) | 2,348,438 | |||||||||||||||||||
|
Stock
issued under share-based compensation plans
|
1,828 | 230 | 33,551 | - | - | - | 33,781 | |||||||||||||||||||||
|
Cash
dividends ($0.40 per common share)
|
- | - | - | (45,023 | ) | - | - | (45,023 | ) | |||||||||||||||||||
|
Stock-based
compensation
|
- | - | 14,754 | - | - | - | 14,754 | |||||||||||||||||||||
|
Excess
tax benefit from stock-based compensation plans
|
- | - | 2,683 | - | - | - | 2,683 | |||||||||||||||||||||
|
Treasury
stock acquired
|
(55 | ) | - | - | - | (1,554 | ) | - | (1,554 | ) | ||||||||||||||||||
|
Retirement
benefit adjustments, net of taxes of ($65,095)
|
- | - | - | - | - | (120,891 | ) | (120,891 | ) | |||||||||||||||||||
|
Net
income
|
- | - | - | 427,628 | - | - | 427,628 | |||||||||||||||||||||
|
Balance,
December 31, 2008
|
113,036 | 14,141 | 1,063,202 | 1,802,022 | (2,533 | ) | (217,016 | ) | 2,659,816 | |||||||||||||||||||
|
Stock
issued under share-based compensation plans
|
797 | 96 | 336 | - | 1,124 | - | 1,556 | |||||||||||||||||||||
|
Stock-based
compensation
|
- | - | 12,127 | - | - | - | 12,127 | |||||||||||||||||||||
|
Excess
tax benefit from stock-based compensation plans
|
- | - | 2,672 | - | - | - | 2,672 | |||||||||||||||||||||
|
Retirement
benefit adjustments, net of taxes of $35,912
|
- | - | - | - | - | 66,695 | 66,695 | |||||||||||||||||||||
|
Net
income
|
- | - | - | 367,504 | - | - | 367,504 | |||||||||||||||||||||
|
Balance,
December 31, 2009
|
113,833 | $ | 14,237 | $ | 1,078,337 | $ | 2,169,526 | $ | (1,409 | ) | $ | (150,321 | ) | $ | 3,110,370 | |||||||||||||
See Notes
to Consolidated Financial Statements.
Rowan
Companies, Inc.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
|
For
the years ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
(In
thousands)
|
||||||||||||
|
CASH
PROVIDED BY OPERATIONS:
|
||||||||||||
|
Net
income
|
$ | 367,504 | $ | 427,628 | $ | 483,800 | ||||||
|
Adjustments
to reconcile net income to net cash provided by
operations:
|
||||||||||||
|
Depreciation
and amortization
|
171,445 | 141,395 | 118,796 | |||||||||
|
Deferred
income taxes
|
15,771 | 51,070 | 51,186 | |||||||||
|
Provision
for pension and postretirement benefits
|
39,664 | 32,479 | 37,170 | |||||||||
|
Stock-based
compensation expense
|
13,034 | 15,834 | 9,326 | |||||||||
|
Goodwill
impairment
|
- | 13,606 | - | |||||||||
|
Postretirement
benefit claims paid
|
(3,495 | ) | (3,017 | ) | (2,824 | ) | ||||||
|
Gain
on disposals of property, plant and equipment
|
(5,748 | ) | (30,701 | ) | (40,506 | ) | ||||||
|
Estimated
net benefits from income tax claims
|
(25,392 | ) | - | - | ||||||||
|
Contributions
to pension plans
|
(36,248 | ) | (31,749 | ) | (10,811 | ) | ||||||
|
Gain
on hurricane-related event
|
- | (37,088 | ) | - | ||||||||
|
Changes
in current assets and liabilities:
|
||||||||||||
|
Receivables
- trade and other
|
147,340 | (6,777 | ) | (59,032 | ) | |||||||
|
Inventories
|
92,357 | (92,772 | ) | (111,268 | ) | |||||||
|
Prepaid
expenses and other current assets
|
(17,278 | ) | 1,703 | 1,138 | ||||||||
|
Accounts
payable
|
(134,648 | ) | 128,897 | (57,144 | ) | |||||||
|
Accrued
income taxes
|
(17,327 | ) | 32,062 | 23,073 | ||||||||
|
Deferred
revenues
|
(34,688 | ) | 63,490 | (35,634 | ) | |||||||
|
Billings
in excess of costs and estimated profits on uncompleted
contracts
|
(31,893 | ) | (12,748 | ) | (1,284 | ) | ||||||
|
Other
current liabilities
|
3,209 | 18,105 | 14,810 | |||||||||
|
Net
changes in other noncurrent assets and liabilities
|
487 | (16,948 | ) | 11,747 | ||||||||
|
Net
cash provided by operations
|
544,094 | 694,469 | 432,543 | |||||||||
|
CASH
USED IN INVESTING ACTIVITIES:
|
||||||||||||
|
Capital
expenditures
|
(566,383 | ) | (829,156 | ) | (462,640 | ) | ||||||
|
Proceeds
from disposals of property, plant and equipment
|
8,592 | 56,108 | 45,806 | |||||||||
|
Proceeds
from hurricane-related event
|
- | 41,550 | - | |||||||||
|
Change
in restricted cash balance
|
- | 50,000 | 106,077 | |||||||||
|
Net
cash used in investing activities
|
(557,791 | ) | (681,498 | ) | (310,757 | ) | ||||||
|
CASH
PROVIDED BY (USED IN) FINANCING ACTIVITIES:
|
||||||||||||
|
Proceeds
from borrowings, net of issue costs
|
491,729 | 80,000 | - | |||||||||
|
Repayments
of borrowings
|
(64,922 | ) | (144,922 | ) | (64,922 | ) | ||||||
|
Payment
of cash dividends
|
- | (44,989 | ) | (44,368 | ) | |||||||
|
Proceeds
from stock option and convertible debenture plans and
other
|
1,471 | 33,781 | 13,245 | |||||||||
|
Excess
tax benefit from stock-based compensation
|
2,672 | 2,683 | 1,655 | |||||||||
|
Payments
to acquire treasury stock
|
- | (1,554 | ) | (979 | ) | |||||||
|
Net
cash provided by (used in) financing activities
|
430,950 | (75,001 | ) | (95,369 | ) | |||||||
|
INCREASE
(DECREASE) IN CASH AND CASH EQUIVALENTS
|
417,253 | (62,030 | ) | 26,417 | ||||||||
|
CASH
AND CASH EQUIVALENTS, BEGINNING OF PERIOD
|
222,428 | 284,458 | 258,041 | |||||||||
|
CASH
AND CASH EQUIVALENTS, END OF PERIOD
|
$ | 639,681 | $ | 222,428 | $ | 284,458 | ||||||
See Notes
to Consolidated Financial Statements.
NOTE
1 – NATURE OF OPERATIONS AND BASIS OF PRESENTATION
Rowan
Companies, Inc., operating through its drilling subsidiaries, is a major
provider of international and domestic oil and gas contract drilling
services. Rowan’s wholly owned manufacturing subsidiary, LeTourneau
Technologies, Inc. (“LeTourneau”), produces equipment for the international and
domestic oil and gas drilling, mining and timber industries.
The
consolidated financial statements are presented in U.S. dollars in accordance
with accounting principles generally accepted in the United States of America
and include the accounts of Rowan Companies, Inc. and its subsidiaries
(hereafter referred to as “Rowan” or the “Company”), all of which are wholly
owned. Intercompany balances and transactions are eliminated in
consolidation. Certain prior period amounts have been reclassified to
conform to the current presentation.
NOTE
2 – SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use
of Estimates
The
preparation of financial statements in conformity with generally accepted
accounting principles (“GAAP”) requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities and
disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
Revenue
and Expense Recognition
Drilling Services. Rowan’s
drilling contracts generally provide for payment on a daily rate basis, and
revenues are recognized as the work progresses with the passage of
time. Rowan frequently receives lump-sum payments at the outset of a
drilling assignment as upfront service fees for equipment moves or
modifications, and such payments (and related costs) are recognized as drilling
revenues (and expenses) over the contract period. Drilling revenues
received but unearned are included in current and other liabilities and totaled
$38.4 million and $47.6 million at December 31, 2009 and 2008,
respectively. Deferred drilling costs are included in prepaid
expenses and other assets and totaled $27.5 million and $32.9 million
at December 31, 2009 and 2008, respectively.
Rowan
also recognizes revenue for certain reimbursable costs. Each
reimbursable item and amount is stipulated in the Company’s contract with the
customer, and such items and amounts frequently vary between
contracts. The Company recognizes reimbursable costs on the gross
basis, as both revenues and expenses, because Rowan is the primary obligor in
the arrangement, has discretion in supplier selection, is involved in
determining product or service specifications and assumes full credit risk
related to the reimbursable costs.
Manufacturing Sales and
Services.
Rowan generally recognizes revenues and costs from sales of manufactured
products when title passes as products are shipped. Revenues from
longer-term contracts such as for the construction of offshore rigs and rig kits
are recognized on the percentage-of-completion basis using contract costs
incurred relative to total estimated contract costs. An offshore rig
construction project typically occurs over a two-year period at the Company’s
Vicksburg, Mississippi, shipyard and includes a significant labor cost component
for fabrication and assembly. Rowan’s latest offshore rig
construction project for an external customer was completed in 2007, and the
Company has no such projects currently underway. A rig kit includes
selected rig components and parts manufactured over a six- to nine-month period
at the Company’s Longview, Texas, facility. Costs are recorded
separately for each offshore rig or rig kit project, and by significant activity
or component within each project, and include materials issued to the project,
labor expenses that are incurred directly for the project and overhead expenses
that are allocated across all projects at consistent rates per labor
hour. Incurred costs include only those costs that measure project
work performed. Material costs incurred, for example, do not include
materials purchased but remaining in inventory. Only when such
materials have been used in production on a project are they included in
incurred project costs. The determination of total estimated project
costs is performed monthly based upon then-current information. This
process involves an evaluation of progress towards project milestones and an
assessment of work left to complete each project activity or component, and is
based on physical observations by project managers and engineers. An
estimate of project costs is then developed for each significant activity or
component based upon the assessment of project status, actual costs incurred to
date, and outstanding commitments for project materials and
services. The Company does not recognize any estimated profit until
projects are at least 10% complete, though a full provision is made immediately
for any anticipated losses.
The
following table summarizes the status of long-term manufacturing contracts in
process. Payments, revenues and costs are cumulative from inception
of the contract through the date indicated. Payments include those
received for contracts in progress or not yet begun and completed contracts with
outstanding collections (in thousands):
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Total
contract value of long-term contracts in process or not yet
begun
|
$ | 204,201 | $ | 290,697 | ||||
|
Payments
received
|
119,653 | 168,653 | ||||||
|
Revenues
recognized
|
102,155 | 119,738 | ||||||
|
Costs
recognized
|
61,407 | 74,526 | ||||||
|
Payments
received in excess of revenues recognized
|
17,498 | 48,915 | ||||||
|
Billings
in excess of costs and estimated profits on uncompleted contracts
(included in current liabilities)
|
$ | 25,226 | $ | 57,119 | ||||
|
Costs
and estimated profits in excess of billings on uncompleted contracts
(included in prepaid expenses and other current assets)
|
$ | 7,728 | $ | 8,204 | ||||
Manufacturing
service revenues are recognized as the work progresses, and totaled
$22.9 million, $21.1 million and $21.9 million in 2009, 2008 and 2007,
respectively.
Product
Warranties
Rowan’s
manufacturing operations offer warranties and parts guarantees extending for
stipulated periods of ownership or hours of usage, whichever occurs
first. In most cases, dealers of the Company’s products perform the
warranty work. For drilling equipment, the Company generally performs
warranty work directly and accrues for estimated future warranty costs based on
historical experience. Accrued liabilities for product warranties
totaled $10.4 million and $9.9 million at December 31, 2009 and 2008,
respectively.
Cash
Equivalents
Cash
equivalents consist of highly liquid temporary cash investments with maturities
no greater than three months at the time of purchase.
Accounts
Receivable and Allowance for Doubtful Accounts
Inherent
in the Company’s revenue recognition policy is the assessment of receivable
collectability, and
an allowance for
uncollectible
accounts, recorded as an
offset to accounts receivable, is estimated to cover the risk of credit
losses. The
allowance is
based on historical and other factors that predict collectability, including
write-offs, recoveries and the monitoring of credit quality. The
Company’s allowance for uncollectible accounts was $3.1 million and $1.2 million
at December 31, 2009 and 2008, respectively.
Receivables
included unreimbursed costs related to the salvage of lost or damaged rigs and
related equipment totaling $29.5 million and $53.2 million at December 31, 2009
and 2008, respectively. See Note 6 for additional information
regarding the Company’s salvage operations and related insurance
reimbursements.
Inventories
Inventories
are carried at the lower of average cost or estimated net realizable
value. Costs include labor, material and an allocation of production
overhead. Management regularly reviews inventory for obsolescence and
reserves for items unlikely to be sold in order to reduce the cost to its
estimated realizable value. Allowances for excess and obsolete
inventories are determined based on both historical and projected
usage.
The
following table summarizes the changes in the Company’s inventory reserves for
each of the past three years (in thousands):
|
Balance,
beginning of year
|
Additions
(deductions) charged (credited) to expenses
|
Other
deductions
|
Balance,
end of year
|
|||||||||||||
|
Year
ended December 31,
|
||||||||||||||||
|
2009
|
$ | 83,700 | $ | (6,500 | ) | $ | (34,900 | ) | $ | 42,300 | ||||||
|
2008
|
12,500 | 72,000 | (800 | ) | 83,700 | |||||||||||
|
2007
|
19,100 | (5,000 | ) | (1,600 | ) | 12,500 | ||||||||||
Property
and Depreciation
Rowan
provides depreciation under the straight-line method from the date an asset is
placed into service until it is sold or becomes fully depreciated based on the
following estimated lives and salvage values. Lives for jack-ups
reflect weighted averages of the hull, legs, other major components and related
equipment:
|
|
Years
|
Salvage Value
|
|
Offshore
drilling equipment:
|
||
|
Super Gorilla, Tarzan Class
and 240C
jack-ups
|
25
|
20%
|
|
Gorilla and other
cantilever jack-ups
|
15
|
20%
|
|
Conventional
jack-ups
|
12
|
20%
|
|
Land
drilling equipment
|
12
to 15
|
20%
|
|
Drill
pipe and tubular equipment
|
4
|
10%
|
|
Manufacturing
plant and equipment:
|
||
|
Buildings
and improvements
|
10
to 25
|
10
to 20%
|
|
Other
equipment
|
2
to 12
|
various
|
|
Other
property and equipment
|
3
to 40
|
various
|
Expenditures
for new property or enhancements to existing property are capitalized and
depreciated over the asset’s estimated useful life. Expenditures for
maintenance and repairs are charged to operations as incurred. As
assets are sold or retired, property cost and related accumulated depreciation
are removed from the accounts, and any resulting gain or loss is included in
results of operations. Rowan capitalizes a portion of interest cost
incurred during the construction period. Long-lived assets are
reviewed for impairment whenever circumstances indicate their carrying amounts
may not be recoverable, based upon estimated future cash flows.
The
amounts of depreciation and amortization expense, capital expenditures and
repairs and maintenance expense by operating segment for each of the last three
years are presented in Note 10.
Foreign
Currency Transactions
The U.S.
dollar is the functional currency for all of Rowan’s
operations. Non-U.S. subsidiaries translate their nonmonetary assets
at exchange rates prevailing at the time they were acquired; monetary assets and
liabilities are translated at year-end rates. Resulting translation
gains and losses and foreign currency transaction gains and losses are included
in “other income” on the Company’s Consolidated Statements of
Income. In order to reduce the impact of exchange rate fluctuations,
Rowan generally requires customer payments to be in U.S. dollars and limits
foreign currency holdings to the extent they are needed to pay liabilities
denominated in such currencies. The Company recognized a net foreign
currency gain of $5.4 million in 2009 and a loss of $10.8 million in 2008,
primarily attributable to operations in Australia and Brazil.
Income
Taxes
Rowan
recognizes deferred income tax assets and liabilities for the estimated future
tax consequences of differences between the financial statement and tax bases of
assets and liabilities. Valuation allowances are provided against
deferred tax assets that are not likely to be realized. See
Note 9 for further information regarding the Company’s income tax assets
and liabilities.
Environmental
Costs
Environmental
remediation costs are accrued using estimates of future monitoring, testing and
clean-up costs where it is probable that such costs will be
incurred. Estimates of future monitoring, testing and clean-up costs,
and assessments of the probability that such costs will be incurred incorporate
many factors, including approved monitoring, testing and/or remediation plans;
ongoing communications with environmental regulatory agencies; the expected
duration of remediation measures; historical monitoring, testing and clean-up
costs, and current and anticipated operational plans and manufacturing
processes. Ongoing environmental compliance costs are expensed as
incurred, and expenditures to mitigate or prevent future environmental
contamination are capitalized. Environmental liabilities at December
31, 2009 and 2008, were not material. See Note 6 for further
information regarding the Company’s environmental liabilities.
Income
Per Common Share
Basic
income per share is computed by dividing income available to common stockholders
by the weighted-average number of common shares outstanding during the
period. Diluted income per share includes the additional effect of
all potentially dilutive securities, which includes dilutive stock options and
stock appreciation rights, contingently issuable shares such as
performance-based stock awards, and shares issuable under the 1998 Convertible
Debenture Incentive Plan (see Note 7).
A
reconciliation of shares for basic and diluted income per share for each of the
past three years is set forth below. There were no income adjustments
to the numerators of the basic or diluted computations for the periods presented
(in thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Average
common shares outstanding
|
113,515 | 112,632 | 110,940 | |||||||||
|
Add
dilutive securities:
|
||||||||||||
|
Employee
and director stock options
|
69 | 645 | 996 | |||||||||
|
Convertible
debentures
|
- | 69 | 329 | |||||||||
|
Average
shares for diluted computations
|
113,584 | 113,346 | 112,265 | |||||||||
The
following table sets forth the share effects of securities excluded from the
diluted calculations because they were antidilutive for the periods
indicated. Options and other potentially dilutive securities are
antidilutive when the exercise or conversion price exceeds the average stock
market price during the period. Such securities could potentially
dilute earnings per share in the future (in thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Employee
and director stock options
|
1,481 | 63 | 63 | |||||||||
|
Stock
appreciation rights
|
50 | - | - | |||||||||
|
Convertible
debentures
|
35 | - | - | |||||||||
|
Total
potentially dilutive shares
|
1,566 | 63 | 63 | |||||||||
Comprehensive
Income
Comprehensive
income is comprised of net income and other comprehensive income (loss). Other
comprehensive income (loss) for 2009, 2008 and 2007, consisted solely of
adjustments relating to pension and other postretirement benefits, the
components of which were as follows, net of income taxes (in
thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Net
(loss) gain arising during the period
|
$ | 14,225 | $ | (126,952 | ) | $ | 5,078 | |||||
|
Prior
service (cost) credit arising during the period
|
43,703 | (28 | ) | - | ||||||||
|
Amortization
of (gain) loss
|
10,721 | 5,958 | 9,008 | |||||||||
|
Amortization
of transition obligation
|
431 | 430 | 430 | |||||||||
|
Amortization
of prior service cost (credit)
|
(2,385 | ) | (299 | ) | (271 | ) | ||||||
|
Total
other comprehensive income (loss), net of tax
|
$ | 66,695 | $ | (120,891 | ) | $ | 14,245 | |||||
See
Note 8 for further information regarding the Company’s pension and other
postretirement benefits.
New
Accounting Standards
In June
2009, the Financial Accounting Standards Board (“FASB”) issued The FASB Accounting Standards
Codification and Hierarchy of
Generally Accepted Accounting Principles, which establishes the
Accounting Standards Codification (“ASC”) as the authoritative source of U.S.
GAAP to be applied to nongovernmental entities. On the effective
date, the ASC superseded all then-existing non-SEC accounting and reporting
standards, with certain limited exceptions. Concurrently, all
nongrandfathered, non-SEC accounting literature not included in the ASC was
deemed nonauthoritative. The ASC will be updated by Accounting
Standards Updates (“ASUs”), which will replace guidance previously issued as
FASB Statements, Interpretations, Staff Positions and other non-SEC
GAAP. Rowan adopted the ASC in the third quarter of
2009. Adoption had no material impact on the Company’s financial
statements other than to change references to previously issued accounting
standards to conform to the ASC.
In May
2009, the FASB issued new guidance under ASC 855, Subsequent
Events. The new guidance establishes general standards of
accounting and disclosure of events that occur after the balance sheet date but
before financial statements are issued or are available to be issued, and is
effective for interim or annual periods ending after June 15,
2009. Rowan adopted the provisions of ASC 855 in the second quarter
of 2009. Adoption had no material impact on the Company’s financial
statements. (See Note 13.)
In
October 2009, the FASB issued Accounting Standards Update No. 2009-13, Revenue Recognition (Topic 605),
Multiple-Deliverable Revenue Arrangements, a consensus of the FASB Emerging
Issues Task Force. ASU No. 2009-13 addresses accounting by
vendors who provide multiple products or services to customers at different
points in time or over different time periods. Specifically, ASU No.
2009-13 eliminates the residual method of allocating revenues to each activity
and requires that revenue be allocated at inception of the arrangement to all
deliverables using a relative selling price method. ASU No. 2009-13
is effective for fiscal years beginning on or after June 15, 2010, and may be
applied prospectively for arrangements entered into after the effective date or
retrospectively for all periods presented. The Company is currently
studying what impact, if any, adoption may have on its financial
statements.
In
December 2008, the FASB issued new guidance under ASC 715, Compensation – Retirement
Benefits. The new guidance requires sponsors of defined
benefit pension or other postretirement plans to disclose (i) how plan asset
investment allocation decisions are made, (ii) the fair value of each major
category of plan assets, (iii) the inputs and valuation techniques used to
develop fair value measurements, and (iv) significant concentrations of risk in
plan assets. The Company adopted the new disclosure provisions of the
guidance effective December 31, 2009. (See Note 8.)
NOTE 3
– ACCRUED LIABILITIES
Accrued
liabilities consisted of the following (in thousands):
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Compensation
and related employee costs
|
$ | 110,526 | $ | 108,060 | ||||
|
Income
taxes
|
40,990 | 58,317 | ||||||
|
Interest
|
20,100 | 5,171 | ||||||
|
Taxes
and other
|
42,548 | 41,919 | ||||||
|
Total
accrued liabilities
|
$ | 214,164 | $ | 213,467 | ||||
NOTE 4
– LONG-TERM DEBT
Long-term
debt consisted of the following (in thousands):
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
6.15%
Title XI note payable, due July 2010, secured by the Gorilla
V
|
$ | 7,177 | $ | 14,351 | ||||
|
6.94%
Title XI note payable, due July 2010, secured by the Gorilla
V
|
5,598 | 11,180 | ||||||
|
5.88%
Title XI note payable, due March 2012, secured by the Gorilla
VI
|
35,613 | 49,865 | ||||||
|
2.80%
Title XI note payable, due October 2013, secured by the Gorilla
VII
|
61,798 | 77,248 | ||||||
|
4.33%
Title XI note payable, due May 2019, secured by the Scooter
Yeargain
|
57,758 | 63,838 | ||||||
|
7.875%
Senior Notes, due August 2019, net of discount (8.0% effective
rate)
|
496,852 | - | ||||||
|
3.525%
Title XI note payable, due May 2020, secured by the Bob
Keller
|
62,757 | 68,735 | ||||||
|
3.158%
Title XI note payable, due July 2021, secured by the Bob
Palmer
|
124,859 | 135,265 | ||||||
|
Total
long-term debt
|
852,412 | 420,482 | ||||||
|
Less:
Current maturities
|
(64,922 | ) | (64,922 | ) | ||||
|
Long-term
debt, excluding current maturities
|
$ | 787,490 | $ | 355,560 | ||||
Annual
maturities over the next five years are $64.9 million in 2010, $52.2
million in 2011, $45.0 million in 2012, $37.9 million in 2013 and $22.5 million
in 2014.
The
Company’s Title XI notes (the “Title XI Notes”) are guaranteed by the U.S.
Government under the U.S. Department of Transportation’s Maritime
Administration (“MARAD”) Title XI Federal Ship Financing
Program. Principal and interest on the Title XI Notes are payable
semiannually on various dates throughout the year.
On July
21, 2009, Rowan issued $500 million aggregate principal amount of 7.875% Senior
Notes due 2019 (the “Senior Notes”), in an SEC registered offering at a price to
the public of 99.341% of the principal amount. After deduction for
underwriters’ discount and offering expenses, the Company received net proceeds
of approximately $492 million, and expects to use the net proceeds for general
corporate purposes. The Senior Notes will mature on August 1,
2019. Interest on the Senior Notes is payable semiannually on
February 1 and August 1 of each year, beginning February 1, 2010, to the holders
of record on the immediately preceding January 15 or July 15,
respectively.
The
Senior Notes are general unsecured, senior obligations. Accordingly,
they rank:
• senior
in right of payment to all of the Company’s subordinated indebtedness, if
any;
• pari passu in right of
payment with any of the Company’s existing and future unsecured indebtedness
that is not by its terms subordinated to the Senior Notes, including any
indebtedness under the Company’s senior revolving credit facility (other than
letter of credit reimbursement obligations that are secured by cash
deposits);
•
effectively junior to the Company’s existing and future secured indebtedness
(including indebtedness under its secured notes issued pursuant to the MARAD
Title XI program to finance several offshore drilling rigs), in each case, to
the extent of the value of the Company’s assets constituting collateral securing
that indebtedness; and
•
effectively junior to all existing and future indebtedness and other liabilities
of the Company’s subsidiaries (other than indebtedness and liabilities owed to
the Company).
The
Company may, at its option, redeem any or all of the Senior Notes at any time
for an amount equal to 100% of the principal amount to be redeemed plus a
make-whole premium and accrued and unpaid interest to the redemption
date. The Company may purchase Senior Notes in the open market, or
otherwise, at any time without restriction under the indenture. The
Company is not required to make mandatory redemption or sinking fund payments
with respect to the Senior Notes.
On
November 24, 2009, Rowan fixed the interest rate for the remainder of the term
on the Title XI Note collateralized by the offshore rig, Bob Palmer, at an annual rate
of 3.158%. Prior to that time, the rate floated based on a short-term
commercial-paper rate plus 0.25%.
On August
4, 2009, Rowan fixed the interest rate for the remainder of the term on the
Title XI Note collateralized by the offshore rig, Bob Keller, at an annual rate
of 3.525%. Prior to that time, the rate floated based on a short-term
commercial paper rate plus 0.15%.
On June
23, 2008, Rowan entered into a three-year $155 million revolving credit facility
agreement. In July 2008, the Company borrowed $80 million under the
facility to complete the purchase of the Cecil Provine and repaid such
amount in full in August 2008. The Company had no borrowings under
the credit facility outstanding during 2009 or at December 31,
2009.
The
Company had $1.0 million of Series C Floating Rate Subordinated
Convertible Debentures (the “Convertible Debentures”) outstanding at
December 31, 2009, issued pursuant to the Rowan Companies, Inc. 1998
Convertible Debenture Incentive Plan. The Convertible Debentures are
convertible into common stock through April 27, 2010, at a price of
$28.25 per share for each $1,000 principal amount of
debenture. The Convertible Debentures were issued in exchange for
promissory notes receivable containing provisions for setoff, protecting Rowan
against any credit risk. The Convertible Debentures and notes
receivable and related accrued interest have been offset in the consolidated
financial statements pursuant to ASC 210-20 of the FASB Accounting Standards
Codification. See Note 7 for further information regarding the
1998 Convertible Debenture Incentive Plan.
Rowan’s
debt agreements contain provisions that require minimum levels of working
capital, stockholders’ equity and “EBITDA,” as defined in the agreements, 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
each of its debt covenants at December 31, 2009.
Rowan’s
debt agreements also specify the minimum insurance coverage for the Company’s
financed rigs. The extent of hurricane damage sustained throughout
the Gulf Coast area in recent years has dramatically increased the cost and
reduced the availability of insurance coverage for windstorm losses. As a
result, management has determined that windstorm coverage meeting the
requirements of the Company’s existing debt agreements was
cost-prohibitive. At the Company’s request, MARAD waived certain
windstorm insurance coverage requirements under the loan agreements, for which
the Company agreed to a covenant to maintain a minimum cash balance, which is
currently $25 million. Rowan remains subject to restrictions on the
use of certain insurance proceeds should the Company experience future windstorm
losses. Each of these security provisions will be released by MARAD
should Rowan be able to obtain windstorm coverage that satisfies the original
terms of its debt agreements.
NOTE 5
– FINANCIAL INSTRUMENTS
Fair
Values of Financial Instruments
The
carrying amounts of the Company’s cash and cash equivalents and trade
receivables and payables approximated their fair values due to their short
maturity.
Carrying
values and fair values of the Company’s fixed-rate debt at December 31, 2009,
were as follows (amounts in thousands):
|
Carrying
value
|
Fair
value
|
|||||||
|
Senior
Notes
|
$ | 496,852 | $ | 560,100 | ||||
|
Fixed-rate
Title XI Notes
|
355,560 | 363,186 | ||||||
| $ | 852,412 | $ | 923,286 | |||||
Concentrations
of Credit Risk
Rowan
invests its excess cash primarily in time deposits at several large commercial
banks with strong credit ratings and high-quality money market accounts and
therefore believes that its risk of loss is minimal.
Approximately
90% of the Company’s revenues are attributable to the Drilling Services and
Drilling Products and Services segments, and a substantial portion of the
Company’s accounts receivable are from customers in the oil and gas drilling
industry. The Company’s drilling customers largely consist of
international oil and gas exploration companies and foreign national oil
companies; Rowan routinely evaluates the credit quality of potential customers
and, with respect to manufacturing operations, may require letters of credit,
down payments, milestone payments and/or payment in full prior to shipping in
some instances. Rowan’s customers are diversified
geographically. One customer provided 10% or more of consolidated
revenues in any of the last three years – Saudi Aramco accounted for 15% of
consolidated revenues in 2009 and 2008, and 13% in 2007. The Company
maintains reserves for credit losses and actual losses have been within
management’s expectations.
NOTE 6
– COMMITMENTS AND CONTINGENT LIABILITIES
The
Company has operating leases covering office space and
equipment. Certain of the leases are subject to escalations based on
increases in building operating costs. Rental expense under all
operating leases was $7.1 million in 2009, $10.9 million in 2008, and
$15.4 million in 2007.
At
December 31, 2009, future minimum payments to be made under noncancelable
operating leases were as follows (in thousands):
|
2010
|
$ | 5,887 | ||
|
2011
|
2,913 | |||
|
2012
|
1,851 | |||
|
2013
|
1,143 | |||
|
2014
|
1,099 | |||
|
Later
years
|
4,362 | |||
| $ | 17,255 |
The
following table presents the status of all of the Company’s rigs under
construction as of December 31 2009. Project costs include
capitalized interest (in millions):
|
Total
estimated project costs
|
Total
costs incurred through Dec. 31, 2009
|
Projected
costs in 2010
|
Projected
costs in 2011
|
Projected
costs in 2012
|
||||||||||||||||
|
Ralph
Coffman (240C)
|
$ | 229 | $ | 225 | $ | 4 | $ | - | $ | - | ||||||||||
|
Joe
Douglas (240C)
|
253 | 81 | 106 | 66 | - | |||||||||||||||
|
EXL
#1
|
190 | 164 | 26 | - | - | |||||||||||||||
|
EXL
#2
|
191 | 136 | 55 | - | - | |||||||||||||||
|
EXL
#3
|
195 | 119 | 76 | - | - | |||||||||||||||
|
EXL
#4
|
196 | 36 | 74 | 54 | 32 | |||||||||||||||
|
Total
rigs under construction
|
$ | 1,254 | $ | 761 | $ | 341 | $ | 120 | $ | 32 | ||||||||||
Rowan
periodically employs letters of credit or other bank-issued guarantees in the
normal course of its businesses, and had outstanding letters of credit of
approximately $42.0 million at December 31, 2009.
Legal
Proceedings
During
2005, Rowan lost four offshore rigs, including the Rowan-Halifax, and incurred
significant damage on a fifth as a result of Hurricanes Katrina and
Rita. The Company had leased the Rowan-Halifax under a charter
agreement that commenced in 1984 and was scheduled to expire in March
2008. The rig was insured for $43.4 million, a value that Rowan
believes to be more than sufficient to satisfy its obligations under the charter
agreement, and by a margin sufficient to cover the $6.3 million carrying value
of Rowan equipment installed on the rig. However, the parties holding
interests in the rig under the charter claimed that the rig should have been
insured for its fair market value and sought recovery from Rowan for
compensation above the insured value. Thus, Rowan assumed no
insurance proceeds related to the Rowan-Halifax and recorded a
charge during 2005 for the full carrying value of its equipment. On
November 3, 2005, the Company filed a declaratory judgment action styled Rowan Companies, Inc. vs. Textron
Financial Corporation and Wilmington Trust Company as Owner Trustee of the
Rowan-Halifax 116-C Jack-Up Rig in the 215th Judicial District Court of
Harris County, Texas. The owner interests filed a counterclaim for a
variety of relief, claiming a right to payment under the charter based on a
post-casualty rig valuation of approximately $83 million. The
insurance proceeds were placed in escrow. The district court
ultimately granted judgment against Rowan for the difference between (a) what
Rowan had already paid to the Owner Trustee out of the escrowed insurance
proceeds and (b) that rig valuation. On March 31, 2009, the Court of
Appeals for the 14th
District of Texas reversed this judgment, holding that the Company’s
interpretation of the charter was substantially correct, but directing Rowan to
pay additional amounts due under the charter. The Company has since
made this payment out of the escrowed insurance proceeds. In
addition, the Court of Appeals remanded the case for further proceedings in the
district court to resolve additional issues and to determine the parties’
respective rights to the balance of the escrowed insurance proceeds, which is
currently $21.4 million. The owner interests filed a motion for
rehearing of the Court of Appeals’ decision. On October 8, 2009, the
Court of Appeals denied the motion, but issued a substitute opinion to clarify
the scope of the remand. The Court of Appeals again held that the
trial court is to resolve issues concerning the proper disposition of excess
insurance proceeds. The Court of Appeals further held that the owner
interests’ claim that Rowan breached the charter agreement by failing to
maintain adequate insurance remains to be decided by the trial
court. The owner interests filed another motion for rehearing, which
motion was denied in January 2010. The Company believes that no
further payment is owed to the opposing parties under the charter and intends to
pursue that position vigorously in all subsequent court
proceedings.
During
2004, Rowan learned that the Environmental and Natural Resources Division,
Environmental Crimes Section of the U.S. Department of Justice (“DOJ”) had
begun conducting a criminal investigation of environmental matters involving
several of the Company’s offshore drilling rigs, including a rig known as
the Rowan-Midland,
which at various times operated in the Gulf of Mexico. In
2007, the Company entered into a plea agreement with the DOJ, as amended, under
which the Company paid fines and made community service payments totaling
$9 million and agreed to be subject to unsupervised probation for a period
of three years. During this period the Company must ensure that it
commits no further criminal violations of federal, state, or local laws or
regulations and must also continue to implement its comprehensive Environmental
Management System Plan. Subsequent to the conduct at issue, the
Company sold the
Rowan-Midland to a third party. Concurrent with the plea
agreement, the Environmental Protection Agency approved a compliance
agreement
with
Rowan which, among other things, contains a certification that the conditions
giving rise to the violations to which the Company entered guilty pleas have
been corrected. The Company believes that if it fully complies with
the terms of the compliance agreement, it will not be suspended or debarred from
entering into or participating in contracts with the U.S. Government or any of
its agencies.
On
January 3, 2008, a civil lawsuit styled State of Louisiana, ex. rel. Charles
C. Foti, Jr., Attorney General vs. Rowan Companies, Inc. was filed in U.S
District Court, Eastern District of Texas, Marshall Division, seeking damages,
civil penalties and costs and expenses for alleged commission of maritime torts
and violations of environmental and other laws and regulations involving the
Rowan-Midland and other
facilities in areas in or near Louisiana. Subsequently, the case was
transferred to U.S. District Court, Southern District of Texas, Houston
Division. The Company intends to vigorously defend its position in
this case but cannot estimate any potential liability at this time.
In June
2007, Rowan received a subpoena for documents from the U.S. District Court,
Eastern District of Louisiana, relating to a grand jury hearing. The
agency requesting the information is the U.S. Department of the Interior, Office
of Inspector General Investigations. The documents requested include
all records relating to use of the Company’s entertainment facilities and
entertainment expenses for a former employee of the Minerals Management Service,
U.S. Department of Interior, and other records relating to items of value
provided to any official or employee of the U.S. Government. The Company
fully cooperated with the subpoena.
The
construction of Rowan’s fourth Tarzan Class jack-up rig, the
J.P. Bussell, was
originally subcontracted to an outside Gulf of Mexico shipyard, Signal
International LLC (“Signal”), and scheduled for delivery in the third quarter of
2007 at a total cost of approximately $145 million. As a result of
various problems encountered on the project, Rowan exercised its right to take
over the rig construction pursuant to the terms of the construction contract,
and Signal turned the rig over to the Company in March 2008. The rig
was later completed by the Company more than one year behind schedule, and its
final cost was approximately 40% over the original
estimate. Accordingly, Rowan has declared Signal in breach of
contract and initiated court proceedings styled Rowan Companies, Inc. and LeTourneau
Technologies, Inc. vs. Signal International LLC in the 269th
Judicial District Court of Harris County, Texas, to recover the cost to
complete the rig over and above the agreed contract price and other damages,
plus interest. Signal filed a separate counterclaim against Rowan
styled Signal International
LLC vs. LeTourneau, Inc., in the U.S. District Court, Southern District
of Texas, Houston Division, alleging breach of contract and claiming unspecified
damages for cost overruns. That case has been administratively stayed
in favor of the State Court proceeding filed by the Company. Signal
reasserted its claimed damages for amounts owed and additional costs incurred,
totaling approximately $88 million, as a counterclaim in the State Court
suit. The Company intends to vigorously defend its rights under the
contract. The Company does not believe that it is probable that
Signal will prevail in its claim and has made no accrual for such at December
31, 2009.
On
December 9, 2008, the Company received a termination letter from a customer
regarding two contracts for the purchase of nine land rigs in the amount of
$90.2 million and nine top drives in the amount of $10.3 million. In
the letter, the customer alleged that the top drive contract had not become
effective because a down payment was never made and further alleged that they
had the right to terminate the land rig contract because of late
deliveries. The Company firmly believes that both allegations are
without merit. Accordingly, the Company initiated court proceedings
styled LeTourneau Technologies
Drilling Systems, Inc. (“LTDSI”) vs. Nomac Drilling, LLC (“Nomac”) in
State District Court, Harris County, Texas, on December 13, 2008, requesting a
declaratory judgment and alleging anticipatory repudiation. On
January 5, 2009, the case was removed to U.S. District Court, Southern District
of Texas, Houston Division. In December 2009, the Company entered
into a Compromise Settlement Agreement, including the dismissal of court
proceedings, termination of the two contracts for the purchase of drilling
equipment, and other terms deemed satisfactory to the Company.
During
2005, the Company learned that the DOJ was conducting an investigation of
potential antitrust violations among helicopter transportation providers in the
Gulf of Mexico. Rowan's former aviation subsidiary, which was sold
effective December 31, 2004, received a subpoena in connection with the
investigation. The Company has not been contacted by the DOJ, but the
purchaser claimed that Rowan is responsible for any exposure it may
have. The Company has disputed that claim. On August 6, 2009, the
Company received a letter from the purchaser informing the Company that Rowan’s
former aviation subsidiary has been named as a defendant in a purported class
action lawsuit alleging antitrust violations and claiming that Rowan is
responsible for any exposure the purchaser may have under the
lawsuit. The Company disputes that claim, as well.
Rowan is
involved in various other legal proceedings incidental to its businesses and is
vigorously defending its position in all such matters. The Company believes that
there are no other known contingencies, claims or lawsuits that could have a
material adverse effect on its financial position, results of operations or cash
flows.
NOTE 7
– STOCKHOLDERS’ EQUITY
Stock-Based
Incentive Plans
In May
2009, stockholders of the Company approved the adoption of the 2009 Rowan
Companies, Inc. Incentive Plan (the “2009 Plan” or “Plan”), which authorizes the
Compensation Committee of the Company’s Board of Directors to grant employees
and nonemployee directors, through May 2019, incentive awards covering up to
4,500,000 shares of Rowan common stock. The awards may be in the form
of stock options, stock appreciation rights, restricted stock awards, restricted
stock units, and performance-based awards, in which the number of shares issued
is dependent on the achievement of certain long-term market or performance
conditions over a specified period. The 2009 Plan replaced the 2005
Rowan Companies, Inc. Long-Term Incentive Plan. All awards
outstanding under the 2005 Plan remained outstanding at the effective date of
the 2009 Plan. Subsequent grants can only be made under the 2009
Plan.
Shares
issued pursuant to the Plan may be treasury shares, authorized but unissued
shares, or shares acquired in the open market. The Plan provides that
shares not issued as a result of forfeitures or the withholding of shares for
the payment of income taxes or exercise price, for example, shall thereafter
become available for the grant of additional awards. As of December
31, 2009, there were 3,268,567 shares available for future grant under the
Plan.
Generally,
restricted stock, stock appreciation rights and options grants awarded by the
Company have multiple vesting dates. The Company recognizes
compensation cost for such awards on a straight-line basis over the requisite
service period for the entire award. Compensation cost under all
stock-based incentive awards recognized in income is presented below (in
thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Restricted
stock and units
|
$ | 10,334 | $ | 11,580 | $ | 5,660 | ||||||
|
Performance-based
awards
|
1,467 | 2,952 | 1,174 | |||||||||
|
Stock
appreciation rights
|
855 | - | - | |||||||||
|
Stock
options
|
378 | 1,302 | 2,497 | |||||||||
|
Total
compensation cost
|
$ | 13,034 | $ | 15,834 | $ | 9,331 | ||||||
Restricted Stock – Restricted
stock represents a full share of Rowan common stock issued with a restrictive
legend that prevents its sale until the restriction is later
removed. In general, the shares vest and the restrictions lapse in
one-third increments each year over a three-year service period, or in some
cases, cliff vest at the end of a two- or three-year service
period. The Company measures compensation related to each share based
upon the market price of the common stock on the date of the grant, adjusted for
the estimated effect of the restriction. A summary of restricted
stock activity for the year ended December 31, 2009, is presented
below:
|
Shares
|
Weighted-average
grant-date fair value per share
|
|||||||
|
Nonvested
at January 1, 2009
|
514,503 | $ | 36.63 | |||||
|
Granted
|
682,599 | 16.84 | ||||||
|
Vested
|
(200,868 | ) | 38.91 | |||||
|
Forfeited
|
(8,504 | ) | 40.58 | |||||
|
Nonvested
at December 31, 2009
|
987,730 | $ | 22.46 | |||||
The fair
value of shares vested (measured at the vesting date) in 2009, 2008 and 2007 was
$3.2 million, $6.4 million, and $5.2 million, respectively. As of
December 31, 2009, unrecognized compensation cost related to nonvested
restricted stock totaled $14.9 million, which is expected to be recognized over
a weighted-average period of 1.9 years.
Restricted Stock Units –
Restricted stock units (“RSUs”) are rights to receive a specified number
of shares of Rowan common stock or an equivalent value in cash. RSUs
are typically granted to nonemployee directors and generally cliff vest at the
end of a one-year service period; however, shares are not issued until the
director terminates service to the Company. The Company measures
compensation related to each unit based upon the market price of the underlying
common stock on the grant date. Nonemployee directors were awarded
36,000 RSUs in 2009 with a weighted-average grant-date fair value per share of
$17.27, compared to 27,000 RSUs granted in each of 2008 and 2007. The
Company issued 13,205 shares of stock with a fair value of $0.3 million in 2009
in connection with the settlement of previously vested RSUs. No
shares were issued in either 2008 or 2007 in settlement of outstanding
RSUs. As of December 31, 2009, unrecognized compensation cost related
to nonvested RSUs totaled $0.2 million, which is expected to be recognized over
a weighted-average period of 0.3 years.
Performance-Based Awards –
The Committee may grant awards in which payment is contingent upon the
achievement of certain market or performance-based conditions over a period of
time specified by the Committee. Payment of such awards may be in
Rowan common stock or cash as determined by the Committee. The number
of awards granted is expressed as the number of shares that would be issued in
the event the “target” goal is attained. The number of shares
actually issued may range from zero to 200% of the target share
amount.
Under the
total shareholder return (“TSR”) criterion, under which the number of shares
that may be issued is based on the Company’s TSR ranking among an industry peer
group at the end of the performance period, fair value is estimated using the
Monte Carlo simulation model, which considers the probabilities of the Company’s
ending TSR at each rank, the number of shares issuable at each rank, and the
expected stock price subject to each rank to determine the probability-weighted
expected payout. A TSR criterion is deemed a “market condition” under
GAAP. Compensation expense for awards with a market condition is
reduced only for forfeitures; no adjustment to expense is otherwise made,
regardless of the number of shares issued, if any. The Company
recognizes compensation expense on a straight-line basis over the performance
period.
The
per-share fair value of awards with return-on-investment (“ROI”) or
return-on-capital-employed (“ROCE”) criteria is equal to the market price of the
stock on the date of grant. The Company initially accrues
compensation expense based on the number of shares that would vest in the event
the target goal is met, subject to reduction for estimated forfeitures, and the
resulting compensation expense is recognized on a straight-line basis over the
performance period. ROI and ROCE criteria are deemed “performance
conditions” under GAAP. Compensation expense for awards with
performance conditions is remeasured annually based on the Company’s progress
towards achieving the performance goal and is recognized for only the actual
number of shares that vest. In the event that awards do not vest or
lapse as a result of the failure to meet the minimum performance criteria, all
previously recognized expense, if any, would be reversed.
A summary
of performance-based award activity for the year ended December 31, 2009, is
presented below:
|
Number
of shares issuable at target
|
Weighted-average
grant-date fair value per share
|
|||||||
|
Outstanding
at January 1, 2009
|
258,809 | $ | 41.89 | |||||
|
Granted
|
- | - | ||||||
|
Forfeited
|
- | - | ||||||
|
Lapsed
|
(99,393 | ) | 43.18 | |||||
|
Outstanding
at December 31, 2009
|
159,416 | $ | 41.08 | |||||
Performance-based
awards outstanding at January 1, 2009, included those for 99,393 shares (net of
16,398 of forfeitures) granted to a group of key employees in 2006, under which
as many as 198,786 shares could have been issued in April 2009 in the event the
Company had attained certain goals related to TSR and ROI as compared to an
industry peer group. At the conclusion of the three-year performance
period in April 2009, the Company’s TSR and ROI rank did not result in the
issuance of Rowan common stock, and all such 2006 awards lapsed.
Performance-based
awards outstanding at December 31, 2009, consisted of (i) 74,401 shares (net of
16,667 of forfeitures) granted in 2007, under which anywhere from zero to
148,802 shares of Rowan common stock will be issued in May 2010 based upon an
equal weighting of the Company’s TSR ranking as compared to an industry peer
group and its ROCE over the three-year period then ended, and (ii) 85,015 shares
(net of 41,985 of forfeitures) granted in 2008, under which from zero to 170,030
shares of Rowan common stock will be issued in April 2011 based upon an equal
weighting of the Company’s TSR ranking as compared to an industry peer group and
its ROCE over the three-year period then ended.
No shares
were issued in 2009, 2008 or 2007 in connection with performance-based
awards. As of December 31, 2009, unrecognized compensation cost
related to outstanding performance-based awards totaled $1.3 million, which is
expected to be recognized over a weighted-average period of 1.1
years.
Stock Options – Stock options
granted to employees generally become exercisable in one-third or one-quarter
annual increments over a three or four-year service period at a price not less
than 100% of the market price of the stock on the date of grant. Any
options not exercised expire ten years after the grant date.
Fair
values of options granted were determined using the Black-Scholes option pricing
model with the following weighted-average assumptions (no options were granted
in 2009 or 2007):
|
2008
|
||||
|
Expected
life in years
|
5.0 | |||
|
Risk-free
interest rate
|
2.50 | % | ||
|
Expected
volatility
|
48.96 | % | ||
The
weighted-average grant-date per-share fair value of options granted in 2008 was
$7.01.
A summary
of stock option activity for the year ended December 31, 2009, is presented
below:
|
Number
of shares under option
|
Weighted-average
exercise price
|
Weighted-average
remaining contractual term (in years)
|
Aggregate
intrinsic value (in thousands)
|
|||||||||||||
|
Outstanding
at January 1, 2009
|
2,087,977 | $ | 21.68 | |||||||||||||
|
Granted
|
- | - | ||||||||||||||
|
Exercised
|
(146,213 | ) | 10.77 | |||||||||||||
|
Forfeited
or expired
|
(105,514 | ) | 22.90 | |||||||||||||
|
Outstanding
at December 31, 2009
|
1,836,250 | $ | 22.50 | 3.5 | $ | 808 | ||||||||||
|
Exercisable
at December 31, 2009
|
1,720,400 | $ | 22.72 | 3.2 | $ | 378 | ||||||||||
The total
intrinsic value of options exercised was $1.1 million in 2009, $10.7 million in
2008 and $8.6 million in 2007. As of December 31, 2009, unrecognized
compensation cost related to stock options totaled $0.5 million, which is
expected to be recognized over a weighted-average period of 1.9
years.
Stock Appreciation Rights –
Stock appreciation rights (“SARs”) give the holder of the award the right
to receive, at no cost to the employee, shares of Rowan common stock, or cash at
the discretion of the Committee, equal in value to the excess of (i) the market
price of the stock on the date of exercise over (ii) the exercise price, which
is the market price of the stock on the date of grant. SARs granted
to employees in 2009 become exercisable in one-third annual increments over a
three-year service period. Any SARs not exercised expire ten years
after the grant date.
Fair
values of SARs granted were determined using the Black-Scholes option pricing
model with the following weighted-average assumptions (no SARs were granted
prior to 2009):
|
2009
|
||||
|
Expected
life in years
|
6.0 | |||
|
Risk-free
interest rate
|
2.375 | % | ||
|
Expected
volatility
|
52.86 | % | ||
The
weighted-average grant-date per-share fair value of SARs granted in 2009 was
$9.03.
A summary
of SARs activity for the year ended December 31, 2009, is presented
below:
|
Number
of shares under SARs
|
Weighted-average
exercise price
|
Weighted-average
remaining contractual term (in years)
|
Aggregate
intrinsic value (in thousands)
|
|||||||||||||
|
Outstanding
at January 1, 2009
|
- | $ | - | |||||||||||||
|
Granted
|
513,834 | 17.39 | ||||||||||||||
|
Exercised
|
- | - | ||||||||||||||
|
Forfeited
or expired
|
- | - | ||||||||||||||
|
Outstanding
at December 31, 2009
|
513,834 | $ | 17.39 | 9.3 | $ | 2,852 | ||||||||||
|
Exercisable
at December 31, 2009
|
- | $ | - | - | $ | - | ||||||||||
As of
December 31, 2009, unrecognized compensation cost related to SARs totaled $3.5
million, which is expected to be recognized over a weighted-average period of
2.3 years.
1998
Convertible Debenture Incentive Plan
Under the
Rowan Companies, Inc. 1998 Convertible Debenture Incentive Plan, as amended, up
to $35.0 million principal amount of floating-rate subordinated convertible
debentures were authorized for issuance in series from time to time to key
employees through April 24, 2008, at a price equal to the higher of (i) the face
value plus accrued interest or (ii) the fair value as determined by an
independent investment banking firm at the time of purchase. The
debentures, to the extent not previously converted or redeemed, are initially
convertible into preferred stock, which has no voting rights (except as required
by law or the Company’s charter), no dividend and a nominal liquidation
preference. The preferred stock is immediately convertible into
common stock. From 1998 through 2001, the Company issued convertible
debentures with principal amounts aggregating $30.0 million maturing from 2008
through 2011 and convertible into 1,233,719 shares of common
stock. As of December 31, 2009, debentures totaling $29.0 million
were converted into 1,198,710 shares of common stock, including 992,002 shares
in 2008 and 78,707 shares in 2007. No debentures were converted in
2009. The $1.0 million of debentures outstanding at December 31,
2009, are convertible into 35,009 shares of common stock through April
2010.
Stockholder
Rights Agreement
In 1992,
Rowan adopted a Stockholder Rights Agreement to protect against coercive
takeover tactics. The agreement, as amended (the “Rights Agreement”),
provided for the distribution to Rowan’s stockholders of one Right for each
outstanding share of common stock. Each Right entitled the holder to
purchase from the Company one one-hundredth of a share of Series A Junior
Preferred Stock of Rowan at an exercise price of $80. The Rights were
exercisable only if a person or group knowingly acquired 15% or more of Rowan’s
outstanding common stock or made a tender offer for 30% or more of the Company’s
outstanding common stock.
On
October 30, 2009, Rowan entered into an amendment to the Rights Agreement,
pursuant to which the final expiration date for the exercise of Rights was
changed to November 2, 2009. The Rights Agreement terminated on
November 2, 2009, and ceased to be of any further force and
effect.
Restrictions
on Retained Earnings
Rowan’s
debt agreements contain financial covenants that limit the amount the Company
may distribute to its stockholders. Under the most restrictive of
such covenants, Rowan had approximately $615 million of retained earnings
available for distribution at December 31, 2009. Subject to this
and other restrictions, the Board of Directors will determine payment, if any,
of future dividends or distributions in light of conditions then existing,
including the Company’s earnings, financial condition and cash requirements,
opportunities for reinvesting earnings, general business conditions and other
factors.
NOTE 8
– PENSION AND OTHER POSTRETIREMENT BENEFIT PLANS
Rowan
sponsors defined benefit pension plans covering substantially all of its
employees, and provides health care and life insurance benefits upon retirement
for certain employees.
The
following table presents the changes in benefit obligations and plan assets
during the years indicated and the funded status and weighted-average
assumptions used to determine the benefit obligation at each year end (in
thousands):
|
Year
ended December 31, 2009
|
Year
ended December 31, 2008
|
|||||||||||||||||||||||
|
Pension
benefits
|
Other
benefits
|
Total
|
Pension
benefits
|
Other
benefits
|
Total
|
|||||||||||||||||||
|
Benefit
obligations:
|
||||||||||||||||||||||||
|
Balance,
January 1
|
$ | 562,212 | $ | 80,896 | $ | 643,108 | $ | 480,747 | $ | 71,756 | $ | 552,503 | ||||||||||||
|
Interest
cost
|
32,477 | 4,594 | 37,071 | 31,599 | 4,419 | 36,018 | ||||||||||||||||||
|
Service
cost
|
15,941 | 2,040 | 17,981 | 14,392 | 2,019 | 16,411 | ||||||||||||||||||
|
Actuarial
(gain) loss
|
9,953 | (2,849 | ) | 7,104 | 54,406 | 5,719 | 60,125 | |||||||||||||||||
|
Plan
amendment
|
(67,236 | ) | - | (67,236 | ) | 43 | - | 43 | ||||||||||||||||
|
Benefits
paid
|
(21,019 | ) | (3,495 | ) | (24,514 | ) | (18,975 | ) | (3,017 | ) | (21,992 | ) | ||||||||||||
|
Balance,
December 31
|
532,328 | 81,186 | 613,514 | 562,212 | 80,896 | 643,108 | ||||||||||||||||||
|
Plan
assets:
|
||||||||||||||||||||||||
|
Fair
value, January 1
|
264,189 | - | 264,189 | 357,283 | - | 357,283 | ||||||||||||||||||
|
Actual
return
|
57,863 | - | 57,863 | (105,868 | ) | - | (105,868 | ) | ||||||||||||||||
|
Employer
contributions
|
36,249 | - | 36,249 | 31,749 | - | 31,749 | ||||||||||||||||||
|
Benefits
paid
|
(21,019 | ) | - | (21,019 | ) | (18,975 | ) | - | (18,975 | ) | ||||||||||||||
|
Fair
value, December 31
|
337,282 | - | 337,282 | 264,189 | - | 264,189 | ||||||||||||||||||
|
Net
benefit liabilities
|
$ | (195,046 | ) | $ | (81,186 | ) | $ | (276,232 | ) | $ | (298,023 | ) | $ | (80,896 | ) | $ | (378,919 | ) | ||||||
|
Amounts
recognized in Consolidated Balance Sheet:
|
||||||||||||||||||||||||
|
Accrued
liabilities
|
$ | (57,265 | ) | $ | (4,510 | ) | $ | (61,775 | ) | $ | (42,600 | ) | $ | (4,360 | ) | $ | (46,960 | ) | ||||||
|
Other
liabilities (long-term)
|
(137,781 | ) | (76,676 | ) | (214,457 | ) | (255,423 | ) | (76,536 | ) | (331,959 | ) | ||||||||||||
|
Net
benefit liabilities
|
$ | (195,046 | ) | $ | (81,186 | ) | $ | (276,232 | ) | $ | (298,023 | ) | $ | (80,896 | ) | $ | (378,919 | ) | ||||||
|
Net
(expense) credit recognized in net benefit cost
|
$ | 20,873 | $ | (65,842 | ) | $ | (44,969 | ) | $ | 16,980 | $ | (62,029 | ) | $ | (45,049 | ) | ||||||||
|
Amounts
not yet reflected in net periodic benefit cost:
|
||||||||||||||||||||||||
|
Actuarial
loss
|
(281,959 | ) | (14,221 | ) | (296,180 | ) | (317,272 | ) | (17,287 | ) | (334,559 | ) | ||||||||||||
|
Transition
obligation
|
- | (1,986 | ) | (1,986 | ) | - | (2,648 | ) | (2,648 | ) | ||||||||||||||
|
Prior
service (cost) credit
|
66,040 | 863 | 66,903 | 2,269 | 1,068 | 3,337 | ||||||||||||||||||
|
Total
accumulated other comprehensive loss
|
(215,919 | ) | (15,344 | ) | (231,263 | ) | (315,003 | ) | (18,867 | ) | (333,870 | ) | ||||||||||||
|
Net
benefit liabilities
|
$ | (195,046 | ) | $ | (81,186 | ) | $ | (276,232 | ) | $ | (298,023 | ) | $ | (80,896 | ) | $ | (378,919 | ) | ||||||
|
Weighted-average
assumptions:
|
||||||||||||||||||||||||
|
Discount
rate
|
5.97 | % | 5.83 | 6.12 | % | 6.34 | % | |||||||||||||||||
|
Rate
of compensation increase
|
4.15 | % | 4.15 | % | ||||||||||||||||||||
The
benefit obligations in the preceding table are the projected benefit obligations
(PBO). The PBO, as it relates to pension benefits, is the actuarial
present value of benefits accrued based on services rendered to date, and
includes the estimated effect of future salary increases. The
accumulated benefit obligation (ABO) is also based on services rendered to date,
but differs from the PBO in that the ABO is based on actual compensation,
excluding the effect of future salary increases. The ABO for all
pension plans in the aggregate is presented below (in thousands):
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
Accumulated
benefit obligation
|
$ | 523,668 | $ | 482,929 | ||||
Each of
the Company’s pension plans has benefit obligations that exceed the fair value
of plan assets.
Rowan
expects that the following amounts, which are classified in accumulated other
comprehensive loss, a component of stockholders’ equity, will be recognized as
net periodic benefits cost in 2010 (in thousands):
|
Pension
benefits
|
Other
retirement benefits
|
Total
|
||||||||||
|
Actuarial
loss
|
$ | 21,333 | $ | 392 | $ | 21,725 | ||||||
|
Transition
obligation
|
- | 662 | 662 | |||||||||
|
Prior
service cost (credit)
|
(6,677 | ) | (205 | ) | (6,882 | ) | ||||||
|
Total
amortization
|
$ | 14,656 | $ | 849 | $ | 15,505 | ||||||
Effective
July 1, 2009, the Company amended the benefit formula for its largest pension
plan for active employees who were earning benefits in the plan prior to January
1, 2008. The effect of the change was to reduce 2009 pension expense
by approximately $7.3 million, or $0.04 per share net of tax.
The
components of net periodic pension cost and the weighted-average assumptions
used to determine net cost were as follows (dollars in thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Service
cost
|
$ | 15,941 | $ | 14,392 | $ | 14,565 | ||||||
|
Interest
cost
|
32,477 | 31,599 | 28,965 | |||||||||
|
Expected
return on plan assets
|
(28,875 | ) | (29,319 | ) | (26,615 | ) | ||||||
|
Recognized
actuarial loss
|
16,277 | 8,901 | 13,328 | |||||||||
|
Amortization
of prior service cost
|
(3,465 | ) | (255 | ) | (213 | ) | ||||||
|
Net
periodic pension cost
|
$ | 32,355 | $ | 25,318 | $ | 30,030 | ||||||
|
Discount
rate
|
6.41 | % | 6.54 | % | 5.92 | % | ||||||
|
Expected
return on plan assets
|
8.00 | % | 8.00 | % | 8.00 | % | ||||||
|
Rate
of compensation increase
|
4.15 | % | 4.15 | % | 4.15 | % | ||||||
The
components of net periodic cost of other postretirement benefits and the
discount rate used to determine net cost were as follows (dollars in
thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Service
cost
|
$ | 2,040 | $ | 2,019 | $ | 2,066 | ||||||
|
Interest
cost
|
4,594 | 4,419 | 4,085 | |||||||||
|
Recognized
actuarial loss
|
216 | 265 | 532 | |||||||||
|
Amortization
of transition obligation
|
662 | 662 | 662 | |||||||||
|
Amortization
of prior service cost
|
(204 | ) | (204 | ) | (205 | ) | ||||||
|
Net
periodic cost of other postretirement benefits
|
$ | 7,308 | $ | 7,161 | $ | 7,140 | ||||||
|
Discount
rate
|
6.34 | % | 6.37 | % | 6.37 | % | ||||||
The
assumed health care cost trend rates used to measure the expected cost of
retirement health benefits was 9% for 2010, gradually decreasing to 4.5% for
2029 and thereafter. A one-percentage-point change in the assumed health care
cost trend rates would change the reported amounts as follows (in
thousands):
|
One-percentage-point
change
|
||||||||
|
Increase
|
Decrease
|
|||||||
|
Effect
on total service and interest cost components for the year
|
$ | 567 | $ | (488 | ) | |||
|
Effect
on postretirement benefit obligation at year-end
|
5,367 | (4,740 | ) | |||||
The
pension plans’ investment objectives for fund assets are: to achieve over the
life of the plans a return equal the plans’ expected investment return or the
inflation rate plus 3%, whichever is greater; to invest assets in a manner such
that contributions are minimized and future assets are available to fund
liabilities; to maintain liquidity sufficient to pay benefits when due; and to
diversify among asset classes so that assets earn a reasonable return with an
acceptable level of risk. Consistent with the investment objectives,
the plans have target allocations of 60-80% in equities and 20-40% in fixed
income and cash and equivalents. Target allocations within the equity
component include the S&P 500 stock index (15-25%), large cap value (5-15%),
large cap growth (5-15%), small cap (5-15%), and international
(10-30%). The plans will periodically reallocate assets in accordance
with the allocation targets, after giving consideration to the expected level of
cash required to pay current benefits and plan expenses. The plans
employ several active managers with proven long-term records in their specific
investment discipline.
The fair
value of each major category of plan assets as of December 31, 2009, classified
by level within the fair value hierarchy (as described in GAAP) is presented
below (in thousands):
|
Total
|
Quoted
prices in active markets for identical assets (Level 1)
|
Significant
observable inputs (Level 2)
|
Significant
unobservable inputs (Level 3)
|
|||||||||||||
|
Cash
and cash equivalents
|
$ | 10,806 | $ | 1 | $ | 10,805 | $ | - | ||||||||
|
Equity
securities:
|
||||||||||||||||
|
S&P
500 Stock Index
|
63,833 | 63,833 | - | - | ||||||||||||
|
Large
cap growth
|
32,492 | - | 32,492 | - | ||||||||||||
|
Large
cap value
|
31,044 | 31,044 | - | - | ||||||||||||
|
Small
cap growth
|
15,275 | 15,275 | - | - | ||||||||||||
|
Small
cap value
|
15,044 | 15,044 | - | - | ||||||||||||
|
International
|
58,428 | - | 58,428 | - | ||||||||||||
|
Fixed
income:
|
||||||||||||||||
|
Aggregate
fixed income
|
49,688 | - | 49,688 | - | ||||||||||||
|
Core
plus fixed income
|
60,672 | 60,672 | - | - | ||||||||||||
|
Total
|
$ | 337,282 | $ | 185,869 | $ | 151,413 | $ | - | ||||||||
Assets in
the large cap growth, large cap value, small cap growth, and small cap value
categories include common and preferred stocks (and equivalents such as American
Depository Receipts and convertible bonds) and include assets invested in
separate accounts, commingled funds and an institutional mutual
fund. Assets in the international category include a broad range of
international equity securities, including both developed and emerging markets,
and are invested primarily in a commingled fund. Securities in both
the aggregate and “core plus” fixed income categories include U.S. government,
corporate, mortgage- and asset-backed securities and Yankee bonds, and both
categories target an average credit rating of “A” or better at all
times. Individual securities in the aggregate fixed income category
must be investment grade or above at the time of purchase, whereas securities in
the core plus category may have a rating of “B” or
above. Additionally, the core plus category may invest in foreign
securities. Assets in the aggregate and core plus fixed income
categories are invested primarily in a commingled fund and an institutional
mutual fund, respectively.
To
develop the expected long-term rate of return on assets assumption, Rowan
considered the current level of expected returns on risk-free investments
(primarily government bonds), the historical level of the risk premium
associated with the plans’ other asset classes and the expectations for future
returns of each asset class. The expected return for each asset class was then
weighted based upon the current asset allocation to develop the expected
long-term rate of return on assets assumption for the plans, which was
maintained at 8% at December 31, 2009, unchanged from December 31,
2008.
Rowan
currently expects to contribute approximately $57.3 million to its pension plans
in 2010 and approximately $4.5 million for the direct payment of unfunded other
postretirement benefits.
Rowan
estimates that the plans will make the following annual payments for pension and
other postretirement benefits based upon existing benefit formulas and including
amounts attributable to future employee service (in thousands):
|
Pension
benefits
|
Other
postretirement benefits
|
|||||||
|
Year
ended December 31,
|
||||||||
|
2010
|
$ | 25,010 | $ | 4,510 | ||||
|
2011
|
26,930 | 4,910 | ||||||
|
2012
|
29,050 | 5,150 | ||||||
|
2013
|
30,430 | 5,480 | ||||||
|
2014
|
32,500 | 5,800 | ||||||
|
2015
though 2019
|
193,080 | 32,370 | ||||||
Rowan
sponsors defined contribution plans covering substantially all employees to
which it contributed approximately $9.7 million in 2009, $9.5 million in
2008, and $5.2 million in 2007.
NOTE 9 – INCOME
TAXES
The
detail of income tax provisions is presented below (in thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Current:
|
||||||||||||
|
Federal
|
$ | 52,454 | $ | 148,801 | $ | 171,556 | ||||||
|
Foreign
|
27,530 | 24,823 | 24,705 | |||||||||
|
State
|
949 | (594 | ) | 3,617 | ||||||||
|
Total
current provision
|
80,933 | 173,030 | 199,878 | |||||||||
|
Deferred
|
52,654 | 53,433 | 55,408 | |||||||||
|
Total
provision
|
$ | 133,587 | $ | 226,463 | $ | 255,286 | ||||||
Rowan’s
provision for income taxes differs from that determined by applying the federal
income tax rate (statutory rate) to income before income taxes, as follows (in
thousands):
|
Year
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Statutory
rate
|
35 | % | 35 | % | 35 | % | ||||||
|
Tax
at statutory rate
|
$ | 175,382 | $ | 228,932 | $ | 258,680 | ||||||
|
Increase
(decrease) due to:
|
||||||||||||
|
State
tax expense
|
(95 | ) | (882 | ) | 2,083 | |||||||
|
Domestic
production activities
|
(5,619 | ) | (6,984 | ) | (5,489 | ) | ||||||
|
Research
and development tax credit
|
(225 | ) | (318 | ) | (818 | ) | ||||||
|
Extraterritorial
income exclusion
|
(25,391 | ) | - | - | ||||||||
|
Foreign
companies' operations
|
(7,341 | ) | (292 | ) | (146 | ) | ||||||
|
Goodwill
|
- | 4,762 | - | |||||||||
|
Other,
net
|
(3,124 | ) | 1,245 | 976 | ||||||||
|
Total
provision
|
$ | 133,587 | $ | 226,463 | $ | 255,286 | ||||||
Temporary
differences and carryforwards which gave rise to deferred tax assets and
liabilities at December 31, 2009 and 2008, were as follows (in
thousands):
|
December
31,
|
||||||||||||||||
|
2009
|
2008
|
|||||||||||||||
|
Current
|
Noncurrent
|
Current
|
Noncurrent
|
|||||||||||||
|
Deferred
tax assets:
|
||||||||||||||||
|
Accrued
employee benefit plan costs
|
$ | 17,949 | $ | 62,312 | $ | 14,790 | $ | 104,552 | ||||||||
|
Inventory
|
9,060 | - | 22,372 | - | ||||||||||||
|
Rig
relocation operations - net
|
9,478 | - | 9,804 | - | ||||||||||||
|
Net
operating losses
|
- | 100,590 | - | - | ||||||||||||
|
Other
|
10,580 | 36,160 | 10,166 | 11,108 | ||||||||||||
|
Total
deferred tax assets
|
47,067 | 199,062 | 57,132 | 115,660 | ||||||||||||
|
Deferred
tax liabilities:
|
||||||||||||||||
|
Property,
plant and equipment
|
- | 661,400 | - | 537,808 | ||||||||||||
|
Other
|
8,996 | 3,362 | 6,230 | 4,700 | ||||||||||||
|
Total
deferred tax liabilities
|
8,996 | 664,762 | 6,230 | 542,508 | ||||||||||||
|
Net
deferred tax asset (liability)
|
$ | 38,071 | $ | (465,700 | ) | $ | 50,902 | $ | (426,848 | ) | ||||||
At
December 31, 2009, the Company had approximately $287.4 million of net operating
loss carryforwards expiring in 2028 and 2029. Management has
determined that no valuation allowances were necessary at December 31, 2009
and 2008, as anticipated future tax benefits relating to all recognized deferred
income tax assets are expected to be fully realized when measured against a more
likely than not standard.
Undistributed
earnings of Rowan’s foreign subsidiaries in the amount of approximately $57.7
million could potentially be subject to additional income taxes of approximately
$4 million. The Company has not provided any deferred income taxes on
such undistributed foreign earnings because it considers them to be permanently
invested abroad.
At
December 31, 2009, 2008 and 2007, Rowan had $53.0 million, $3.8 million and
$3.4 million, respectively, of net unrecognized tax benefits, all of which would
reduce the Company’s income tax provision if recognized. The
Company does not expect to recognize significant increases or decreases in
unrecognized tax benefits during the next twelve months.
The
following table highlights the changes in the Company’s gross unrecognized tax
benefits during the years ended December 31 (in thousands):
|
2009
|
2008
|
2007
|
||||||||||
|
Gross
unrecognized tax benefits - beginning of year
|
$ | 7,300 | $ | 5,000 | $ | 5,500 | ||||||
|
Gross
increases - tax positions in prior period
|
37,600 | 2,300 | - | |||||||||
|
Gross
decreases - tax positions in prior period
|
- | - | (500 | ) | ||||||||
|
Gross
increases - current period tax positions
|
11,900 | - | - | |||||||||
|
Settlements
|
- | - | - | |||||||||
|
Lapse
of statute of limitations
|
(1,800 | ) | - | - | ||||||||
|
Gross
unrecognized tax benefit - end of year
|
$ | 55,000 | $ | 7,300 | $ | 5,000 | ||||||
Interest
and penalties relating to income taxes are included in current income tax
expense. At December 31, 2009, 2008 and 2007, accrued interest
was $0.7 million, $0.8 million and $0.3 million, respectively, and accrued
penalties were $0.4 million, $0.3 million and $0.3 million,
respectively. To the extent accrued interest and penalties relating
to uncertain tax positions are not actually assessed, such accruals will be
reversed and the reversals will reduce the Company’s overall income tax
provision.
Rowan’s
U.S. federal tax returns for 2006 and 2007 are currently under audit by the
Internal Revenue Service (“IRS”), and 2002 and later years remain subject to
examination. Various state tax returns for 2004 and subsequent years
remain open for examination. In the Company’s foreign tax
jurisdictions, returns for 2006 and subsequent years remain open for
examination. Rowan is undergoing other routine tax examinations in
various foreign, U.S. federal, state and local taxing jurisdictions in which the
Company has operated. These examinations cover various tax years and are
in various stages of finalization. Rowan believes that any income taxes
ultimately assessed by any foreign, U.S. federal, state or local taxing
authorities will not materially exceed amounts for which the Company has already
provided.
In 2009,
the Company recognized a $25.4 million tax benefit as a result of applying our
facts to a recent third-party tax case that provides a more favorable tax
treatment for certain foreign contracts entered into in prior
years. The Company has deferred recognition of a remaining $49.2
million estimated benefit in accordance with the accounting guidelines for
income tax uncertainties. In connection with the above, the Company
has recorded a long-term receivable, which is included in other assets on the
Condensed Consolidated Balance Sheet at December 31, 2009, for the gross claim
of approximately $74.6 million and a long-term liability of approximately $49.2
million.
Income
from continuing operations before income taxes consisted of domestic earnings of
$558.3 million, $597.1 million, and $722.4 million in 2009, 2008, and
2007, respectively, a foreign loss of $57.2 million in 2009, and foreign
earnings of $56.9 million and $16.7 million in 2008 and 2007,
respectively.
NOTE 10
– SEGMENT INFORMATION
Rowan has
three principal operating segments – Drilling Services, Drilling Products and
Systems, and Mining, Forestry and Steel Products. The Drilling
Services segment provides onshore and offshore oil and gas contract drilling
services on a daily rate basis. The Drilling Products and Systems
segment manufactures equipment and parts for the oil and gas drilling industry
featuring jack-up rigs, rig kits and related components and parts, mud pumps,
drawworks, top drives, rotary tables, other rig equipment, variable-speed
motors, drives and other electrical components. The Mining, Forestry
and Steel Products segment manufactures large-wheeled mining and timber
equipment and related parts, and carbon and alloy steel and steel
plate. The Drilling Products and Systems and Mining, Forestry and
Steel Products segments operate under LeTourneau.
Rowan’s
reportable segments reflect an aggregation of separately managed, strategic
business units for which financial information is separately prepared and
monitored based upon qualitative and quantitative factors. The
Company evaluates segment performance based upon income from
operations.
Prior to
2008, products and services provided by the Drilling Products and Systems
segment to the Drilling Services segment were recorded as cost transfers; thus,
the Drilling Products and Systems segment did not report intersegment revenues
or costs. Effective January 1, 2008, such intersegment transactions
were recorded as sales based on the terms and conditions and rates of
compensation which approximated those that were customarily included in
third-party contracts for similar items. During 2007, Rowan’s
Drilling Products and Systems segment provided approximately $263 million
of products and services to Drilling Services at cost. Certain
administrative costs are allocated between segments generally based upon
revenues. Refer to Note 2 for further information with regard to
significant accounting policies applicable to the Company’s operating
segments.
Certain
information by operating segment is set forth below (in thousands):
|
Drilling
Services
|
Drilling
Products and Systems
|
Mining,
Forestry and Steel Products
|
Eliminations
|
Consolidated
|
||||||||||||||||
|
2009:
|
||||||||||||||||||||
|
Revenues
from external customers
|
$ | 1,214,896 | $ | 369,371 | $ | 185,913 | $ | - | $ | 1,770,180 | ||||||||||
|
Intersegment
revenues
|
- | 278,892 | - | (278,892 | ) | - | ||||||||||||||
|
Income
from operations
|
466,961 | 99,973 | 25,504 | (91,425 | ) | 501,013 | ||||||||||||||
|
Depreciation
and amortization
|
155,923 | 9,013 | 6,510 | - | 171,446 | |||||||||||||||
|
Repairs
and maintenance
|
92,745 | 8,555 | 10,508 | - | 111,808 | |||||||||||||||
|
Material
charges
|
- | - | - | - | - | |||||||||||||||
|
Capital
expenditures
|
587,237 | 460 | 9,003 | - | 596,700 | |||||||||||||||
|
Total
assets (at end of year)
|
4,527,435 | 474,768 | 208,491 | - | 5,210,694 | |||||||||||||||
|
2008:
|
||||||||||||||||||||
|
Revenues
from external customers
|
$ | 1,451,623 | $ | 493,456 | $ | 267,657 | $ | - | $ | 2,212,736 | ||||||||||
|
Intersegment
revenues
|
- | 382,893 | - | (382,893 | ) | - | ||||||||||||||
|
Income
from operations
|
666,803 | 30,595 | 32,569 | (71,844 | ) | 658,123 | ||||||||||||||
|
Depreciation
and amortization
|
125,861 | 9,461 | 6,073 | - | 141,395 | |||||||||||||||
|
Repairs
and maintenance
|
108,143 | 14,458 | 13,602 | - | 136,203 | |||||||||||||||
|
Material
charges 1
|
24,635 | 81,841 | 4,695 | - | 111,171 | |||||||||||||||
|
Capital
expenditures
|
817,276 | 9,632 | 6,238 | - | 833,146 | |||||||||||||||
|
Total
assets (at end of year)
|
3,714,289 | 583,055 | 251,548 | - | 4,548,892 | |||||||||||||||
|
2007:
|
||||||||||||||||||||
|
Revenues
from external customers
|
$ | 1,382,571 | $ | 498,620 | $ | 213,830 | $ | - | $ | 2,095,021 | ||||||||||
|
Intersegment
revenues
|
- | - | - | - | - | |||||||||||||||
|
Income
from operations
|
661,789 | 42,968 | 29,116 | - | 733,873 | |||||||||||||||
|
Depreciation
and amortization
|
101,802 | 11,660 | 5,334 | - | 118,796 | |||||||||||||||
|
Repairs
and maintenance
|
105,936 | 15,779 | 12,373 | - | 134,088 | |||||||||||||||
|
Material
charges
|
- | - | - | - | - | |||||||||||||||
|
Capital
expenditures
|
436,894 | 25,931 | 15,726 | - | 478,551 | |||||||||||||||
|
Total
assets (at end of year)
|
3,140,456 | 499,225 | 235,624 | - | 3,875,305 | |||||||||||||||
_____________________________________
1 See
Note 11 of “Notes to Consolidated Financial Statements” for an analysis of
material charges.
One
customer provided 10% or more of consolidated revenues in any of the last three
years. Saudi Aramco accounted for 15% of consolidated revenues in
2009 and 2008, and 13% in 2007.
The
classifications of revenues and assets among geographic areas in the tables
which follow were determined based on the physical location of
assets. Because the Company’s offshore drilling rigs are mobile,
classifications by area are dependent on the rigs’ location at the time revenues
are earned, and may vary from one period to the next.
Revenues
by geographic area are set forth below (in thousands):
|
2009
|
2008
|
2007
|
||||||||||
|
United
States
|
$ | 952,023 | $ | 1,331,214 | $ | 1,298,672 | ||||||
|
Middle
East
|
379,062 | 486,265 | 400,422 | |||||||||
|
Europe
|
172,610 | 166,486 | 249,608 | |||||||||
|
West
Africa
|
115,992 | 117,466 | - | |||||||||
|
Canada
|
57,337 | - | (1,186 | ) | ||||||||
|
Australia
|
58,581 | 69,144 | 68,272 | |||||||||
|
Mexico
|
14,101 | - | - | |||||||||
|
Egypt
|
12,019 | - | - | |||||||||
|
Trinidad
|
- | 41,522 | 79,233 | |||||||||
|
Other
|
8,455 | 639 | - | |||||||||
|
Consolidated
revenues
|
$ | 1,770,180 | $ | 2,212,736 | $ | 2,095,021 | ||||||
Long-lived
assets by geographic area are set forth below (in thousands):
|
December
31,
|
||||||||
|
2009
|
2008
|
|||||||
|
United
States
|
$ | 2,084,852 | $ | 2,008,424 | ||||
|
Middle
East
|
584,838 | 554,358 | ||||||
|
Europe
|
387,546 | 371,830 | ||||||
|
Egypt
|
214,814 | - | ||||||
|
West
Africa
|
202,290 | 208,626 | ||||||
|
Mexico
|
56,032 | - | ||||||
|
Canada
|
40,553 | 178 | ||||||
|
Australia
|
6,948 | 4,093 | ||||||
|
Other
|
1,612 | 19 | ||||||
|
Consolidated
long-lived assets
|
$ | 3,579,485 | $ | 3,147,528 | ||||
NOTE 11
– MATERIAL CHARGES AND OTHER OPERATING EXPENSES
Operating
expenses for the fourth quarter of 2008 included the following adjustments, by
operating segment (in thousands):
|
Drilling
Services
|
Drilling
Products and Systems
|
Mining,
Forestry and Steel Products
|
Consolidated
|
|||||||||||||
|
Termination
of construction of fourth 240C
rig
|
$ | 11,830 | $ | - | $ | - | $ | 11,830 | ||||||||
|
Severance
and retirement costs
|
8,531 | 2,248 | - | 10,779 | ||||||||||||
|
Suspension
of LeTourneau monetization process
|
2,781 | 6,338 | 3,445 | 12,564 | ||||||||||||
|
Goodwill
impairment
|
1,493 | 10,863 | 1,250 | 13,606 | ||||||||||||
|
Increase
in inventotry valuation reserve
|
- | 62,392 | - | 62,392 | ||||||||||||
| $ | 24,635 | $ | 81,841 | $ | 4,695 | $ | 111,171 | |||||||||
NOTE 12
– RELATED PARTY TRANSACTIONS
In 2008,
Rowan paid an investment bank, in which a Rowan director served as managing
director until March 2009, $4.1 million for services provided to the
Company. In 2009, Rowan paid the investment bank $1.8 million for
services provided in connection with the Company’s July 2009 public offering of
$500 million Senior Notes, though the transaction occurred several months
following his departure.
Another
Rowan director serves as “of counsel” to a law firm that represents Rowan on
certain matters and to which the Company paid approximately $0.6 million, $1.6
million and $0.3 million for legal fees and expenses in 2009, 2008 and 2007,
respectively.
In each
case, the director’s services were approved by the Company’s Board of Directors,
and compensation from his employer was not tied to amounts received from the
Company. Rowan believes that the fees paid for services reflected
market rates.
NOTE
13 – SUPPLEMENTAL CASH FLOW INFORMATION
Noncash
investing and financing activities excluded from the Consolidated Statements of
Cash Flows and other supplemental cash flow information follows (dollars in
thousands):
|
Years
ended December 31,
|
||||||||||||
|
2009
|
2008
|
2007
|
||||||||||
|
Noncash
investing and financing activities:
|
||||||||||||
|
Accrued
additions to property and equipment
|
$ | 23,340 | $ | 4,157 | $ | 15,911 | ||||||
|
Conversion
of employee debentures into 992,002 shares of common stock in 2008 and
78,707 shares in 2007
|
- | 24,922 | 2,289 | |||||||||
|
Other
supplemental cash flow information:
|
||||||||||||
|
Cash
interest payments in excess of (less than) interest
capitalized
|
$ | (7,568 | ) | $ | 3,930 | $ | 16,969 | |||||
|
Cash
income tax payments, net of refunds
|
137,648 | 150,660 | 156,900 | |||||||||
Interest
capitalized in 2009 exceeded the amount of interest payments due to the timing
of the first interest payment on the 7.875% Senior Notes, which were issued in
July 2009. Interest on the Senior Notes is payable each February and
August beginning February 2010.
NOTE
14 – SUBSEQUENT EVENTS
There
were no events or transactions that occurred subsequent to December 31, 2009
requiring recognition or disclosure in the financial
statements.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders of
Rowan
Companies, Inc.
Houston,
Texas
We have
audited the accompanying consolidated balance sheets of Rowan Companies, Inc.
and subsidiaries (the "Company") as of December 31, 2009 and 2008, and the
related consolidated statements of income, comprehensive income, changes in
stockholders' equity, and cash flows for each of the three years in the period
ended December 31, 2009. 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 the Company as of December 31, 2009 and
2008, and the results of their operations and their cash flows for each of the
three years in the period ended December 31, 2009, in conformity with accounting
principles generally accepted in the United States of America.
We have
also audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the Company's internal control over financial
reporting as of December 31, 2009, 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, 2010, expressed an unqualified
opinion on the Company's internal control over financial reporting.
/s/ DELOITTE &
TOUCHE LLP
Houston,
Texas
March 1,
2010
Rowan
Companies, Inc.
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
PURSUANT
TO SECTION 404 OF THE SARBANES-OXLEY ACT OF 2002
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.
Under
Section 404 of the Sarbanes-Oxley Act of 2002, 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, 2009.
The
registered public accounting firm Deloitte & Touche LLP has audited
Rowan’s consolidated financial statements included in our 2009 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/ W. H.
WELLS
|
|
W.
Matt Ralls
|
W.
H. Wells
|
|
President
and Chief Executive Officer
|
Vice
President, Finance and Chief Financial Officer
|
|
March
1, 2010
|
March
1, 2010
|
REPORT OF
INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Board of Directors and Stockholders of
Rowan
Companies, Inc.
Houston,
Texas
We have
audited the internal control over financial reporting of Rowan Companies, Inc.
and subsidiaries (the "Company") as of December 31, 2009, 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, 2009, 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, 2009 of the Company and our report dated March
1, 2010, expressed an unqualified opinion
on those financial statements.
/s/ DELOITTE & TOUCHE
LLP
Houston,
Texas
March 1,
2010
SELECTED
QUARTERLY FINANCIAL DATA (UNAUDITED)
Unaudited
quarterly financial data for each full quarter within the two most recent fiscal
years follows (in thousands except per share amounts):
|
First
|
Second
|
Third
|
Fourth
|
|||||||||||||
|
Quarter
|
Quarter
|
Quarter
|
Quarter
|
|||||||||||||
|
2009:
|
||||||||||||||||
|
Revenues
|
$ | 494,808 | $ | 482,160 | $ | 393,421 | $ | 399,791 | ||||||||
|
Income
from operations
|
198,245 | 130,543 | 87,088 | 85,137 | ||||||||||||
|
Income
from continuing operations
|
131,700 | 96,583 | 78,392 | 60,829 | ||||||||||||
|
Net
income
|
131,700 | 96,583 | 78,392 | 60,829 | ||||||||||||
|
Per
share amounts:
|
||||||||||||||||
|
Income
from continuing operations — Basic
|
$ | 1.16 | $ | 0.85 | $ | 0.69 | $ | 0.53 | ||||||||
|
Income
from continuing operations — Diluted
|
1.16 | 0.85 | 0.69 | 0.53 | ||||||||||||
|
Net
income — Basic
|
1.16 | 0.85 | 0.69 | 0.53 | ||||||||||||
|
Net
income — Diluted
|
1.16 | 0.85 | 0.69 | 0.53 | ||||||||||||
|
2008:
|
||||||||||||||||
|
Revenues
|
$ | 485,489 | $ | 587,142 | $ | 527,058 | $ | 613,047 | ||||||||
|
Income
from operations
|
147,671 | 181,760 | 172,176 | 156,516 | ||||||||||||
|
Income
from continuing operations
|
98,625 | 120,608 | 114,114 | 94,281 | ||||||||||||
|
Net
income
|
98,625 | 120,608 | 114,114 | 94,281 | ||||||||||||
|
Per
share amounts:
|
||||||||||||||||
|
Income
from continuing operations — Basic
|
$ | 0.88 | $ | 1.07 | $ | 1.01 | $ | 0.83 | ||||||||
|
Income
from continuing operations — Diluted
|
0.88 | 1.06 | 1.00 | 0.83 | ||||||||||||
|
Net
income — Basic
|
0.88 | 1.07 | 1.01 | 0.83 | ||||||||||||
|
Net
income — Diluted
|
0.88 | 1.06 | 1.00 | 0.83 | ||||||||||||
The sum
of the per-share amounts for the quarters may not equal the per-share amounts
for the full year since the quarterly and full year per share computations are
made independently.
The
fourth quarter of 2008 includes certain year-end adjustments and other material
items, which are described in Note 11 of “Notes to Consolidated Financial
Statements” in Item 8 of this Form 10-K.
None
The
Company’s management has evaluated, with the participation of the Company’s
Chief Executive Officer and Chief Financial Officer, the effectiveness of the
Company’s disclosure controls and procedures, as of the end of the period
covered by this report, pursuant to Exchange Act Rule 13a-15. Based upon
that evaluation, the Company’s Chief Executive Officer, along with the Company’s
Chief Financial Officer, concluded that the Company’s disclosure controls and
procedures were effective as of December 31, 2009.
Our
management is responsible for establishing and maintaining internal control over
financial reporting (ICFR). Our internal control system was designed to provide
reasonable assurance to the Company’s management and Board of Directors
regarding the preparation and fair presentation of published financial
statements. All internal control systems, no matter how well designed, have
inherent limitations, and therefore can only provide reasonable assurance with
respect to financial statement preparation and presentation.
Our
management’s assessment is that the Company did maintain effective ICFR as of
December 31, 2009, within the context of the framework established by the
Committee of Sponsoring Organizations of the Treadway Commission (COSO), and
that the Company did not have a material change in ICFR during the fourth
quarter of 2009.
See
“Management’s Report on Internal Control over Financial Reporting” included in
Item 8 of this Form 10-K.
Not
applicable
Information
concerning our directors will appear in our Proxy Statement for the 2010 Annual
Meeting of Stockholders, to be filed pursuant to Regulation 14A on or before
March 15, 2010, under the caption “Election of Directors.” Such
information is incorporated herein by reference.
Information
concerning our executive officers appears in Part 1 under the caption “Executive
Officers of the Registrant” of this Form 10-K.
Information
concerning our Audit Committee will appear in our Proxy Statement for the 2010
Annual Meeting of Stockholders, to be filed pursuant to Regulation 14A on or
before March 15, 2010, under the caption “Committees of the Board of
Directors.” Such information is incorporated herein by
reference.
Information
concerning compliance with Section 16(a) of the Securities Exchange
Act will appear in our Proxy Statement for the 2010 Annual Meeting of
Stockholders, to be filed pursuant to Regulation 14A of the Exchange Act
(“Regulation 14A”) on or before March 15, 2010, under the caption “Additional
Information - Section 16(a) Beneficial Ownership Reporting
Compliance.” Such information is incorporated herein by
reference.
Information
concerning director and executive compensation will appear in our Proxy
Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to
Regulation 14A on or before March 15, 2010, under the captions “Director
Compensation and Attendance,” “Compensation Discussion & Analysis,”
“Compensation Committee Report,” and “Executive Compensation.” Such information
is incorporated herein by reference.
Information
concerning the security ownership of management will appear in our Proxy
Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to
Regulation 14A on or before March 15, 2010, under the caption “Security
Ownership of Certain Beneficial Owners and Management.” Such
information is incorporated herein by reference.
The
business address of all directors is the principal executive offices of the
Company as set forth on the cover page of this Form 10-K.
Equity
Compensation Plan Information
The
following table provides information about our common stock that may be issued
under equity compensation plans as of December 31, 2009.
|
Number
of securities to be issued upon exercise of outstanding options, warrants
and rights (1)
|
Weighted-average
exercise price of outstanding options, warrants and rights (2)
|
Number
of securities remaining available for future issuance under equity
compensation plans (excluding securities reflected in column
(a))
|
||||||||||
|
(a)
|
(b)
|
(c)
|
||||||||||
|
Equity
compensation plans approved by security holders
|
2,149,828 | $ | 22.19 | 3,268,567 | ||||||||
|
Equity
compensation plans not approved by security holders
|
- | - | - | |||||||||
|
Total
|
2,149,828 | $ | 22.19 | 3,268,567 | ||||||||
|
(1)
|
The
number of securities to be issued includes (i) 1,836,250 options and
119,153 shares issuable under outstanding SARs (see note (2) below), (ii)
159,416 contingent shares in connection with performance-based stock
awards, and (iii) 35,009 shares issuable under the 1998 Convertible
Debenture Incentive Plan. The exact number of shares to be
issued under performance-based awards is dependent on meeting certain
market-based or performance-based criteria and can range between zero and
318,832 shares (see Note 7 of Notes to Consolidated Financial Statements
for a further discussion of performance-based stock awards and the 1998
Convertible Debenture Incentive Plan).
|
|
(2)
|
The
weighted-average exercise price in column (b) is based on (i) 1,836,250
shares under outstanding options with a weighted average exercise price of
$22.50 per share, and (ii) 119,153 shares of stock that would be issuable
in connection with 513,834 stock appreciation rights (SARs) outstanding at
December 31, 2009. The number of shares issuable under SARs is
equal in value to the excess of the Rowan stock price on the date of
exercise over the exercise price. The number of shares under SARs included
in column (a) was based on a December 31, 2009 closing stock price of
$22.64 and an exercise price of $17.39 per
share.
|
Information
concerning director and executive related party transactions will appear in our
Proxy Statement for the 2010 Annual Meeting of Stockholders, to be filed
pursuant to Regulation 14A on or before March 15, 2010, within the section and
under the captions “Director Independence” and “Related Party
Transactions.” Such information is incorporated herein by
reference.
Information
concerning principal account fees and services will appear in our Proxy
Statement for the 2010 Annual Meeting of Stockholders, to be filed pursuant to
Regulation 14A on or before March 15, 2010, in the last paragraph under the
caption “Fees of Audit Firm.” Such information is incorporated herein by
reference.
(a) Index
to Financial Statements, Financial Statement Schedules and Exhibits
(1) Financial
Statements
See
Item 8, “Financial Statements and Supplementary Data,” beginning on
page 41 of this Form 10-K for a list of financial statements filed as a
part of this report.
(2) Financial Statement
Schedules
Financial
Statement Schedules I, II, III, IV, and V are not included in
this Form 10-K because such schedules are not required, the required
information is not significant, or the information is presented elsewhere in the
financial statements.
(3) Exhibits
Unless
otherwise indicated below as being incorporated by reference to another filing
of the Company with the Securities and Exchange Commission, each of the
following exhibits is filed herewith:
|
3.1
|
Restated
Certificate of Incorporation of the Company, dated February 17, 1984
(incorporated by reference to Exhibit 4.1 to Registration Statement
No. 333-84369 on Form S-8) and the Certificates of Designation
for the Company’s Series A Preferred Stock (and Certificate of Correction
related thereto) (incorporated by reference to Exhibit 4.8 to
Registration Statement No. 333-84369 on Form S-8), Series B
Preferred Stock (incorporated by reference to Exhibit 4d to
Form 10-K for the year ended December 31, 1999), Series D
Preferred Stock (incorporated by reference to Exhibit 4.11 to
Registration Statement No. 333-82804 on Form S-3 filed on
February 14, 2002), and Series E Preferred Stock (incorporated by
reference to Exhibit 4.12 to Registration Statement
No. 333-82804 on Form S-3 filed on February 14,
2002).
|
|
3.2
|
Amended
and Restated Bylaws of Rowan Companies, Inc., effective as of
October 29, 2009, incorporated by reference to Exhibit 3.1 of the
Company’s Current Report on Form 8-K dated November 2, 2009 (File No.
1-5491).
|
|
4.1
|
Certificate
of Change of Address of Registered Office and of Registered Agent dated
July 25, 1984, incorporated by reference to Exhibit 4.4 to
Registration Statement No. 333-84369 on Form S-8 (File
No. 1-5491).
|
|
4.2
|
Certificate
of Amendment of Certificate of Incorporation dated April 24, 1987,
incorporated by reference to Exhibit 4.5 to Registration Statement
No. 333-84369 on Form S-8 (File
No. 1-5491).
|
|
4.3
|
Certificate
of Designation of the Series A Junior Preferred Stock dated
March 2, 1992, incorporated by reference to Exhibit 4.2 to
Registration Statement on Form 8-A/A filed on February 12, 2002
(File No. 1-5491).
|
|
4.4
|
Certificate
of Designation of the Series C Preferred Stock dated July 28,
2000, incorporated by reference to Exhibit 4.10 to Registration
Statement No. 333-44874 on Form S-8 (File
No. 1-5491).
|
|
4.5
|
Specimen
Common Stock certificate, incorporated by reference to Exhibit 4k to
Form 10-K for the year ended December 31, 2001 (File
No. 1-5491).
|
|
4.6
|
Form
of Promissory Note date April 27, 2000 between purchasers of
Series C Floating Rate Subordinated Convertible Debentures due 2010
and Rowan, incorporated by reference to Exhibit 4n to Form 10-K
for the year ended December 31, 2000 (File
No. 1-5491).
|
|
4.7
|
Indenture
for Senior Debt Securities dated as of July 21, 2009, between Rowan
Companies, Inc. and U.S. Bank National Association, as trustee,
incorporated by reference to Exhibit 4.1 of the Company’s Current Report
on Form 8-K dated July 21, 2009 (File No. 1-5491).
|
|
4.8
|
First
Supplemental Indenture dated as of July 21, 2009, between Rowan Companies,
Inc. and U.S. Bank National Association, as trustee, incorporated by
reference to Exhibit 4.2 of the Company’s Current Report on Form 8-K dated
July 21, 2009 (File No. 1-5491).
|
|
10.1
|
Restated
1988 Nonqualified Stock Option Plan, incorporated by reference to
Appendix C to the Notice of Annual Meeting and Proxy Statement dated
March 20, 2002 (File No. 1-5491) and Form of Stock Option
Agreement related thereto, incorporated by reference to Exhibit 10c
to Form 10-K for the year ended December 31, 2004 (File
No. 1-5491).
|
|
10.2
|
1998
Nonemployee Director Stock Option Plan, incorporated by reference to
Exhibit 10b of Form 10-Q for the quarter ended March 31,
1998 (File No. 1-5491) and Form of Stock Option Agreement related
thereto, incorporated by reference to Exhibit 10c to Form 10-K
for the year ended December 31, 2004 (File
No. 1-5491).
|
|
10.3
|
1998
Convertible Debenture Incentive Plan, incorporated by reference to
Appendix B to the Notice of Annual Meeting and Proxy Statement dated
March 20, 2002 (File No. 1-5491) and Form of Debenture related
thereto, incorporated by reference to Exhibit 10c to Form 10-K
for the year ended December 31, 2004 (File
No. 1-5491).
|
|
10.4
|
2009
Rowan Companies, Inc. Incentive Plan, incorporated by reference to
Appendix A of the Company’s definitive proxy statement dated March 19,
2009 (File No. 1-5491) and Form of 2009 Stock Appreciation Right
Agreement, Form of 2009 Restricted Stock Agreement, and Form of
Non-Employee Director 2009 Restricted Stock Unit Agreement under the 2009
Rowan Companies, Inc. Incentive Plan, incorporated by reference to
Exhibits 10.2, 10.3 and 10.4, respectively, of the Company’s Quarterly
Report on Form 10-Q dated August 10, 2009 (File No.
1-5491).
|
|
10.5
|
Pension
Restoration Plan of LeTourneau Technologies, Inc., a wholly owned
subsidiary of the Company, incorporated by reference to Exhibit 10j
to Form 10-K for the year ended December 31, 1994 (File
No. 1-5491).
|
|
10.6
|
Participation
Agreement dated December 1, 1984 between Rowan and Textron Financial
Corporation et al. and Bareboat Charter dated December 1, 1984
between Rowan and Textron Financial Corporation et al., incorporated
by reference to Exhibit 10c to Form 10-K for the year ended
December 31, 1985 (File No. 1-5491).
|
|
10.7
|
Participation
Agreement dated December 1, 1985 between Rowan and Eaton Leasing
Corporation et. al. and Bareboat Charter dated December 1, 1985
between Rowan and Eaton Leasing Corporation et. al., incorporated by
reference to Exhibit 10d to Form 10-K for the year ended
December 31, 1985 (File No. 1-5491).
|
|
10.8
|
Election
and acceptance letters with respect to the exercise of the Fixed Rate
Renewal Option set forth in the Bareboat Charter dated December 1,
1984 between Rowan and Textron Financial Corporation et al,
incorporated by reference to Exhibit 10j to Form 10-K for the
year ended December 31, 1999 (File
No. 1-5491).
|
|
10.9
|
Election
and acceptance letters with respect to the exercise of the Fixed Rate
Renewal Option set forth in the Bareboat Charter dated December 1,
1985 between Rowan and Eaton Leasing Corporation et. al, incorporated by
reference to Exhibit 10k to Form 10-K for the year ended
December 31, 1999 (File No. 1-5491).
|
|
10.10
|
Commitment
to Guarantee Obligations dated December 17, 1996 and First Preferred
Ship Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to Gorilla V),
incorporated by reference to Exhibit 10t to Form 10-K for year
ended December 31, 1996 (File No. 1-5491).
|
|
10.11
|
Amendment
No. 1 dated June 30, 1997 to Commitment to Guarantee Obligations
between Rowan and the Maritime Administration of the U.S. Department
of Transportation (relating to Gorilla V),
incorporated by reference to Exhibit 10p to 10-K for the year ended
December 31, 1997 (File No. 1-5491).
|
|
10.12
|
Amendment
No. 2 dated July 1, 1998 to Commitment to Guarantee Obligations
between Rowan and the Maritime Administration of the U.S. Department
of Transportation (relating to Gorilla V),
incorporated by reference to Exhibit 10o to Form 10-K for the
year ended December 31, 1998 (File
No. 1-5491).
|
|
10.13
|
Credit
Agreement and Trust Indenture both dated December 17, 1996 between
Rowan and Citibank, N.A. (relating to Gorilla V),
incorporated by reference to Exhibit 10u to Form 10-K for the
year ended December 31, 1996 (File
No. 1-5491).
|
|
10.14
|
Amendment
No. 1 to the Credit Agreement and Supplement No. 1 to
Trust Indenture both dated July 1, 1997 between Rowan and
Citibank, N.A. (relating to Gorilla V),
incorporated by reference to Exhibit 10r to Form 10-K for the
year ended December 31, 1997 (File
No. 1-5491).
|
|
10.15
|
Supplement
No. 2 dated July 1, 1998 to Trust Indenture between Rowan and
Citibank, N.A. (relating to Gorilla V),
incorporated by reference to Exhibit 10r to Form 10-K for the
year ended December 31, 1998 (File
No. 1-5491).
|
|
10.16
|
Commitment
to Guarantee Obligations dated September 29, 1998 and First Preferred
Ship Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to Gorilla VI),
incorporated by reference to Exhibit 10a to Form 10-Q for
quarter ended September 30, 1998 (File
No. 1-5491).
|
|
10.17
|
Credit
Agreement and Trust Indenture both dated September 29, 1998 between
Rowan and Citibank, N.A. (relating to Gorilla VI),
incorporated by reference to Exhibit 10b to Form 10-Q for the
quarter ended September 30, 1998 (File
No. 1-5491).
|
|
10.18
|
Amendment
No. 1 dated March 15, 2001 to Commitment to Guarantee
Obligations between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to Gorilla VI),
incorporated by reference to Exhibit 10v to Form 10-K for the
year ended December 31, 2000 (File
No. 1-5491).
|
|
10.19
|
Supplement
No. 1 dated March 15, 2001 to Trust Indenture between Rowan and
Citibank, N.A. (relating to Gorilla VI),
incorporated by reference to Exhibit 10v to Form 10-K for the
year ended December 31, 2000 (File
No. 1-5491).
|
|
10.20
|
Commitment
to Guarantee Obligations dated October 29, 1999 and First Preferred
Ship Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to Gorilla VII),
incorporated by reference to Exhibit 10v to Form 10-K for the
year ended December 31, 1999 (File
No. 1-5491).
|
|
10.21
|
Credit
Agreement and Trust Indenture both dated October 29, 1999 between
Rowan and Citibank, N.A. (relating to Gorilla VII),
incorporated by reference to Exhibit 10w to Form 10-K for the
year ended December 31, 1999 (File
No. 1-5491).
|
|
10.22
|
Amendment
No. 1 dated June 30, 2003 to the Commitment to Guarantee
Obligations between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to Gorilla VII),
incorporated by reference to Exhibit 10x to Form 10-K for the
year ended December 31, 2003 (File
No. 1-5491).
|
|
10.23
|
Supplement
No. 1 dated June 30, 2003 to Trust Indenture between Rowan and
Citibank, N.A. (relating to Gorilla VII),
incorporated by reference to Exhibit 10y to Form 10-K for the
year ended December 31, 2003 (File
No. 1-5491).
|
|
10.24
|
Commitment
to Guarantee Obligations dated May 23, 2001 and First Preferred Ship
Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to the Bob Palmer, formerly
Gorilla VIII),
incorporated by reference to Exhibit 10y to Form 10-K for the
year ended December 31, 2001 (File
No. 1-5491).
|
|
10.25
|
Credit
Agreement and Trust Indenture both dated May 23, 2001 between Rowan
and Citibank, N.A. (relating to the Bob Palmer, formerly
Gorilla VIII),
incorporated by reference to Exhibit 10z to Form 10-K for the
year ended December 31, 2001 (File
No. 1-5491).
|
|
10.26
|
Commitment
to Guarantee Obligations dated May 28, 2003 and First Preferred Ship
Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to the Scooter Yeargain),
incorporated by reference to Exhibit 10bb to Form 10-K for the
year ended December 31, 2003 (File
No. 1-5491).
|
|
10.27
|
Credit
Agreement and Trust Indenture both dated May 28, 2003 between Rowan
and Citibank, N.A. (relating to the Scooter Yeargain),
incorporated by reference to Exhibit 10cc to Form 10-K for the
year ended December 31, 2003 (File
No. 1-5491).
|
|
10.28
|
Amendment
No. 1 dated June 15, 2005 to the Commitment to Guarantee
Obligations between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to the Scooter Yeargain),
incorporated by reference to Exhibit 10a to Form 10-Q for the
quarterly period ended June 30, 2005 (File
No. 1-5491).
|
|
10.29
|
Supplement
No. 1 dated June 15, 2005 to Trust Indenture between Rowan and
Citibank, N.A. (relating to the Scooter Yeargain),
incorporated by reference to Exhibit 10b to Form 10-Q for the
quarterly period ended June 30, 2005 (File
No. 1-5491).
|
|
10.30
|
Commitment
to Guarantee Obligations dated May 28, 2003 and First Preferred Ship
Mortgage between Rowan and the Maritime Administration of the
U.S. Department of Transportation (relating to the Bob Keller, formerly
Tarzan II), incorporated by reference to Exhibit 10dd to
Form 10-K for the year ended December 31, 2003 (File
No. 1-5491).
|
|
10.31
|
Credit
Agreement and Trust Indenture both dated May 28, 2003 between Rowan
and Citibank, N.A. (relating to the Bob Keller, formerly
Tarzan II), incorporated by reference to Exhibit 10ee to
Form 10-K for the year ended December 31, 2003 (File
No. 1-5491).
|
|
10.32
|
Amendment
No. 1 dated March 28, 2005 to Credit Agreement between Rowan and
Citibank, N.A. (relating to the Bob Keller, formerly
Tarzan II), incorporated by reference to Exhibit 10a to
Form 10-Q for the quarterly period ended March 31, 2005 (File
No. 1-5491).
|
|
10.33
|
Amendment
No. 2 dated May 4, 2005 to Credit Agreement between Rowan and
Citibank, N.A. (relating to the Bob Keller, formerly
Tarzan II), incorporated by reference to Exhibit 10b to
Form 10-Q for the quarterly period ended March 31, 2005 (File
No. 1-5491).
|
|
10.34
|
Memorandum
Agreement dated January 26, 2006 between Rowan and C. R. Palmer,
incorporated by reference to Exhibit 10jj to Form 10-K for year
ended December 31, 2005 (File No. 1-5491).
|
|
10.35
|
2005
Rowan Companies, Inc. Long-Term Incentive Plan, incorporated by reference
to Exhibit 10.1 to Form 8-K filed May 10, 2005 (File
No. 1-5491) and Form of Non-Employee Director 2005 Restricted Stock
Unit Grant, Form of Non-Employee Director 2006 Restricted Stock Unit
Grant, Form of 2005 Restricted Stock Grant Agreement, Form of 2005
Nonqualified Stock Option Agreement, Form of 2005 Performance Share Award
Agreement related thereto, each incorporated by reference to
Exhibits 10c, 10d, 10e, 10f and 10g, respectively, to Form 10-Q
for the quarterly period ended June 30, 2005 (File
No. 1-5491).
|
|
10.36
|
Change
in Control Agreement and Change in Control Supplement, incorporated by
reference to Exhibits 10.1 and 10.2 to Form 8-K filed
December 20, 2007 (File 1-5491).
|
|
10.37
|
Credit
Agreement dated as of June 23, 2008 among Rowan, as Borrower, the Lenders
Party thereto, Wells Fargo Bank, NA, as Administrative Agent, Issuing
Lender and Swingline Lender, Bayerische Hypo-Und Vereinsbank AG, as
Syndication Agent, and Amegy Bank NA, as Documentation Agent, incorporated
by reference to Form 8-K filed June 25, 2008 (File
1-5491).
|
|
10.38
|
Amendment
No. 1 dated August 4, 2009, to the Commitment to Guarantee Obligations
between Rowan and the Maritime Administration of the U.S. Department of
Transportation (relating to the Bob Keller, formerly
Tarzan II),
incorporated by reference to Exhibit 10.5 of the Company’s Quarterly
Report on Form 10-Q filed August 10, 2009 (File No.
1-5491).
|
|
10.39
|
Supplement
No. 2 dated August 4, 2009, to Trust Indenture between Rowan and Citibank,
N.A. (relating to the Bob Keller, formerly
Tarzan II),
incorporated by reference to Exhibit 10.6 of the Company’s Quarterly
Report on Form 10-Q filed August 10, 2009 (File No.
1-5491).
|
|
10.40
|
Form
of Indemnification Agreement between Rowan Companies, Inc. and each of its
directors and certain officers, incorporated by reference to Exhibit 10.1
of the Company’s Current Report on Form 8-K dated November 2, 2009 (File
No. 1-5491).
|
|
10.41
|
Amendment
No. 1 dated November 24, 2009, to the Commitment to Guarantee Obligations
between Rowan and the Maritime Administration of the U.S. Department of
Transportation (relating to the Bob Palmer, formerly
Gorilla VIII), incorporated by reference to Exhibit 10.1 of the Company’s
Current Report on Form 8-K dated November 24, 2009 (File No.
1-5491).
|
|
10.42
|
Supplement
No. 2 dated November 24, 2009, to Trust Indenture between Rowan and
Manufacturers and Traders Trust Company (relating to the Bob Palmer, formerly
Gorilla VII),
incorporated by reference to Exhibit 10.2 of the Company’s Current Report
on Form 8-K dated November 24, 2009 (File No. 1-5491).
|
|
10.43
|
Restoration
Plan of Rowan Companies, Inc. (As Restated Effective July 1,
2009).
|
|
14
|
Code
of Business Conduct for Senior Financial Officers of the Company,
incorporated by reference to Exhibit 14 to Form 10-K for the
year ended December 31, 2003 (File
No. 1-5491).
|
|
21
|
Subsidiaries
of the Registrant as of February 24, 2010.
|
|
23
|
Consent
of Independent Registered Public Accounting Firm.
|
|
24
|
Powers
of Attorney pursuant to which names were affixed to this Form 10-K
for the year ended December 31, 2009.
|
|
31.1
|
Certification
of Chief Executive Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
31.2
|
Certification
of Chief Financial Officer Pursuant to Section 302 of the Sarbanes-Oxley
Act of 2002.
|
|
32.1
|
Certification
of Chief Executive Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
|
|
32.2
|
Certification
of Chief Financial Officer Pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002.
|
|
99
|
Annual
CEO Certification to the New York Stock Exchange.
|
|
101.INS
|
XBRL
Instance Document.
|
|
101.SCH
|
XBRL
Taxonomy Extension Schema Document.
|
|
101.CAL
|
XBRL
Taxonomy Extension Calculation Linkbase Document.
|
|
101.DEF
|
XBRL
Taxonomy Extension Definition Linkbase Document.
|
|
101.LAB
|
XBRL
Taxonomy Extension Label Linkbase Document.
|
|
101.PRE
|
XBRL
Taxonomy Extension Presentation Linkbase
Document.
|
__________
|
*
|
Only
portions specifically incorporated herein are deemed to be
filed.
|
EXECUTIVE
COMPENSATION PLANS AND ARRANGEMENTS
Compensatory
plans in which Rowan’s directors and executive officers participate are listed
as follows:
|
|
•
|
Restated
1988 Nonqualified Stock Option Plan, incorporated by reference to
Appendix C to the Notice of Annual Meeting and Proxy Statement dated
March 20, 2002 (File
No. 1-5491).
|
|
|
•
|
1998
Nonemployee Director Stock Option Plan, incorporated by reference to
Exhibit 10b of Form 10-Q for the quarter ended March 31,
1998 (File No. 1-5491).
|
|
|
•
|
1998
Convertible Debenture Incentive Plan, incorporated by reference to
Appendix B to the Notice of Annual Meeting and Proxy Statement dated
March 20, 2002 (File
No. 1-5491).
|
|
|
•
|
Restoration
Plan of Rowan Companies, Inc. (As Restated Effective July 1,
2009).
|
|
|
•
|
Pension
Restoration Plan of LeTourneau, Inc., a wholly owned subsidiary of the
Company, incorporated by reference to Exhibit 10j to Form 10-K
for the year ended December 31, 1994 (File
No. 1-5491).
|
|
|
•
|
Profit
Sharing Plan, incorporated by reference to Exhibit 10.1 to
Form 8-K filed May 4, 2006 (File No.
1-5491).
|
|
|
•
|
2005
Long-Term Incentive Plan, incorporated by reference to Exhibit 10.1
to Form 8-K filed May 10, 2005 (File No.
1-5491).
|
|
|
•
|
Change
in Control Agreement and Change in Control Supplement for the Rowan
Companies, Inc. Restated 1988 Nonqualified Stock Option Plan and the 2005
Rowan Companies, Inc. Long-Term Incentive Plan incorporated by reference
to Exhibits 10.1 and 10.2 to Form 8-K filed December 20,
2007 (File 1-5491).
|
|
|
•
|
2009
Rowan Companies, Inc. Incentive Plan, incorporated by reference to
Appendix A of the Company’s definitive proxy statement dated March 19,
2009 (File No. 1-5491).
|
Rowan
agrees to furnish to the Commission upon request a copy of all instruments
defining the rights of holders of long-term debt of the Company and its
subsidiaries.
For the
purposes of complying with the amendments to the rules governing Form S-8
(effective July 13, 1990) under the Securities Act of 1933, the
undersigned registrant hereby undertakes as follows, which undertaking shall be
incorporated by reference into Registrant’s Registration Statements on
Form S-8 Nos. 2-58700, as amended by Post-Effective Amendment No. 4
(filed June 11, 1980), 33-33755, as amended by Amendment No. 1 (filed
March 29, 1990), 33-61444 (filed April 23, 1993), 333-84369 (filed
August 3, 1999), 333-84405 (filed August 3, 1999), 333-101914
(filed December 17, 2002), 333-132762 (filed March 28, 2006), and
333-158985 (filed May 5, 2009):
Insofar
as indemnification for liabilities arising under the Securities Act of 1933 may
be permitted to directors, officers and controlling persons of the Registrant
pursuant to the foregoing provisions, or otherwise, the Registrant has been
advised that in the opinion of the Securities and Exchange Commission such
indemnification is against public policy as expressed in the Securities Act of
1933 and is, therefore, unenforceable. In the event that a claim for
indemnification against such liabilities (other than the payment by the
Registrant of expenses incurred or paid by a director, officer or controlling
person of the Registrant in the successful defense of any action, suit or
proceeding) is asserted by such director, officer or controlling person in
connection with the securities being registered, the Registrant will, unless in
the opinion of its counsel the matter has been settled by controlling precedent,
submit to a court of appropriate jurisdiction the question whether such
indemnification by it is against public policy as expressed in the act and will
be governed by the final adjudication of such issue.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act
of 1934, the Registrant has duly caused this report to be signed on its behalf
by the undersigned, thereunto duly authorized.
|
ROWAN
COMPANIES, INC.
|
||
|
(Registrant)
|
||
|
By:
/s/ W. MATT RALLS
|
||
|
W.
Matt Ralls
|
||
|
President
and Chief Executive officer
|
||
|
Date:
March 1, 2010
|
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been
signed below by the following persons on behalf of the Registrant and in the
capacities and on the date indicated.
|
Signature
|
Title
|
Date
|
|
|
/s/ W. MATT
RALLS
|
President,
Chief Executive Officer and Director
|
March
1, 2010
|
|
|
(W.
Matt Ralls)
|
|||
|
/s/ W. H. WELLS
|
Principal
Financial Officer
|
March
1, 2010
|
|
|
(W.
H. Wells)
|
|||
|
/s/ GREGORY M.
HATFIELD
|
Principal
Accounting Officer
|
March
1, 2010
|
|
|
(Gregory
M. Hatfield)
|
|||
|
/s/ *R. G.
CROYLE
|
Director
|
March
1, 2010
|
|
|
(R.
G. Croyle)
|
|||
|
/s/ *WILLIAM T.
FOX III
|
Director
|
March
1, 2010
|
|
|
(William
T. Fox III)
|
|||
|
/s/ *SIR GRAHAM
HEARNE
|
Director
|
March
1, 2010
|
|
|
(Sir
Graham Hearne)
|
|||
|
/s/ *THOMAS R.
HIX
|
Director
|
March
1, 2010
|
|
|
(Thomas
R. Hix)
|
|||
|
/s/ *ROBERT E.
KRAMEK
|
Director
|
March
1, 2010
|
|
|
(Robert
E. Kramek)
|
|||
|
/s/ *FREDERICK R.
LAUSEN
|
Director
|
March
1, 2010
|
|
|
(Frederick
R. Lausen)
|
|||
|
/s/ *H. E. LENTZ
|
Chairman
of the Board
|
March
1, 2010
|
|
|
(H.
E. Lentz)
|
|||
|
/s/ *LORD
MOYNIHAN
|
Director
|
March
1, 2010
|
|
|
(Lord
Moynihan)
|
|||
|
/s/ *P. DEXTER
PEACOCK
|
Director
|
March
1, 2010
|
|
|
(P.
Dexter Peacock)
|
|||
|
/s/ *JOHN J.
QUICKE
|
Director
|
March
1, 2010
|
|
|
(John
J. Quicke)
|
|||
|
*By:
|
/s/ W. MATT
RALLS
|
||
|
(W.
Matt Ralls,
|
|||
|
Attorney-in-Fact)
|
|||