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Pride International 10-K 2007 Documents found in this filing:
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UNITED
STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
For the fiscal year ended December 31, 2006
Commission file number: 1-13289
Pride International, Inc.
(Exact name of registrant as specified in its charter)
Registrant’s telephone number, including area code:
(713) 789-1400
Securities registered pursuant to Section 12(b) of the
Act:
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. Yes o No þ
Indicate by check mark if the registrant is not required to file
reports pursuant to Section 13 of the
Act. Yes o No þ
Indicate by check mark whether the registrant (1) has filed
all reports required to be filed by Section 13 or 15(d) of
the Securities Exchange Act of 1934 during the preceding
12 months (or for such shorter period that the registrant
was required to file such reports), and (2) has been
subject to such filing requirements for the
past 90 days. Yes þ No
o
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. o
Indicate by check mark whether the registrant is a large
accelerated filer, an accelerated filer, or a non-accelerated
filer. See definition of “accelerated filer and large
accelerated filer” in
Rule 12b-2
of the Exchange Act. (Check one):
Large accelerated
filer þ Accelerated
filer o Non-accelerated
filer o
Indicate by check mark whether the registrant is a shell company
(as defined in
Rule 12b-2
of the
Act). Yes o No þ
The aggregate market value of the registrant’s common stock
held by non-affiliates as of June 30, 2006, based on the
closing price on the New York Stock Exchange on such date, was
approximately $5.1 billion. (The current executive officers
and directors of the registrant are considered affiliates for
the purposes of this calculation.)
The number of shares of the registrant’s common stock
outstanding on February 27, 2007 was 165,358,592.
Portions of the registrant’s definitive proxy statement for
the Annual Meeting of Stockholders to be held in May 2007 are
incorporated by reference into Part III of this annual
report.
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In this Annual Report on
Form 10-K,
“we,” the “Company” and “Pride”
are references to Pride International, Inc. and its
subsidiaries, unless the context clearly indicates otherwise.
Pride International, Inc. is a Delaware corporation with its
principal executive offices located at 5847 San Felipe,
Suite 3300, Houston, Texas 77057. Pride’s telephone
number at such address is
(713) 789-1400
or
(800) 645-2067.
We are a leading international provider of contract drilling and
related services to oil and natural gas companies worldwide,
operating offshore and on land. As of February 28, 2007, we
owned a global fleet of 272 rigs, consisting of two deepwater
drillships, 12 semisubmersible rigs, 28 jackup rigs, 16
tender-assisted, barge and platform rigs and 214 land-based
drilling and workover rigs.
Our operations are conducted in many of the most active oil and
natural gas basins of the world, including South America, the
Gulf of Mexico, the Mediterranean Sea, West Africa, the Middle
East and Asia Pacific. The significant diversity of our rig
fleet and areas of operation enables us to provide a broad range
of services and to take advantage of market upturns while
reducing our exposure to sharp downturns in any particular
market sector or geographic region.
We provide contract drilling services to oil and natural gas
exploration and production companies through the use of mobile
offshore drilling rigs in U.S. and international waters, as well
as land-based drilling and workover rigs in international land
markets. We provide the rigs and drilling crews and are
responsible for the payment of operating and maintenance
expenses. In addition, we also provide rig management services
on a variety of rigs, consisting of technical drilling
assistance, personnel, repair and maintenance services and
drilling operation management services.
In the third quarter of 2006, we reorganized our operations into
three principal reportable segments: Offshore, which includes
all of our offshore drilling fleet and operations; Latin America
Land, which includes our land-based drilling and workover
services in Latin America; and E&P Services, which includes
our exploration and production services business in Latin
America.
We incorporate by reference in response to this item the segment
information for the last three years set forth in
“Management’s Discussion and Analysis of Financial
Condition and Results of Operations — Segment
Review” in Item 7 of this annual report and the
information for the last three fiscal years with respect to
revenues, earnings from operations, total assets, capital
expenditures and depreciation and amortization attributable to
our segments and revenues and long-lived assets by geographic
areas of operations in Note 14 of our Notes to Consolidated
Financial Statements included in Item 8 of this annual
report. We also incorporate by reference in response to this
item the information with respect to acquisitions and
dispositions of assets set forth in “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations — Liquidity and Capital Resources” in
Item 7 and in Notes 2 and 12 of our Notes to
Consolidated Financial Statements included in Item 8 of
this annual report.
Rig
Fleet
Offshore
Rigs
The table below presents information about our offshore rig
fleet as of February 28, 2007:
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4
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Drillships. The Pride Africa and
Pride Angola are deepwater, self-propelled drillships
that can be positioned over a drill site through the use of a
computer-controlled thruster (dynamic positioning) system.
Drillships are suitable for deepwater drilling in remote
locations because of their mobility and large load-carrying
capacity. Generally, these drillships operate with crews of
approximately 100 persons.
Semisubmersible Rigs. Our semisubmersible rigs
are floating platforms that, by means of a water ballasting
system, can be submerged to a predetermined depth so that a
substantial portion of the lower hulls, or pontoons, is below
the water surface during drilling operations. The rig is
“semisubmerged,” remaining afloat in a position, off
the sea bottom, where the lower hull is about 60 to 80 feet
below the water line and the upper deck protrudes well above the
surface. This type of rig maintains its position over the well
through the use of either an anchoring system or a
computer-controlled thruster system similar to that used by our
drillships. Semisubmersible rigs generally operate with crews of
60 to 75 persons.
Jackup Rigs. The jackup rigs we operate are
mobile, self-elevating drilling platforms equipped with legs
that are lowered to the ocean floor until a foundation is
established to support the drilling platform. The rig legs may
have a lower hull or mat attached to the bottom to provide a
more stable foundation in soft bottom areas. Independent leg
rigs are better suited for harsher drilling conditions or uneven
seabed conditions. Jackup rigs are generally subject to a
maximum water depth of approximately 200 to 300 feet. The
length of the rig’s legs and the operating environment
determine the water depth limit of a particular rig. A
cantilever jackup rig has a feature that allows the drilling
platform to be extended out from the hull, enabling the rig to
perform drilling or workover operations over a pre-existing
platform or structure. Slot-type jackup rigs are configured for
drilling operations to take place through a slot in the hull.
Slot-type rigs are usually used for exploratory drilling because
their configuration makes them difficult to position over
existing platforms or structures. Jackups generally operate with
crews of 15 to 40 persons.
Tender-Assisted Rigs. Our tender-assisted rigs
are generally barges moored alongside a platform and containing
crew quarters, mud tanks, mud pumps and power generation
systems. The only equipment transferred to the platform for
drilling or workover operations is the derrick equipment set
consisting of the substructure, drillfloor, derrick and
drawworks. As a result, tender-assisted rigs allow smaller, less
costly platforms to be used for
5
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development projects. Self-erecting tender-assisted rigs carry
their own derrick equipment and have a crane capable of erecting
the derrick on the platform, thereby eliminating the cost
associated with a separate derrick barge and related equipment.
Tender-assisted rigs generally operate with crews of 15 to 25
persons.
Barge Rigs. We own two lake barge rigs on Lake
Maracaibo, Venezuela and one swamp barge in West Africa. Lake
barges are designed to work in a floating mode with a cantilever
feature and a mooring system that enables the rig to operate in
waters up to 150 feet deep. Swamp barge rigs generally
operate in marshy areas or in water depths of less than
25 feet. This type of rig is held on location by submerging
the hull onto the sea floor before commencement of work. Barge
rigs generally operate with crews of 15 to 25 persons.
Platform Rigs. Our platform rigs generally
consist of drilling equipment and machinery arranged in modular
packages that are transported to, assembled and installed on
fixed offshore platforms owned by the customer. Fixed offshore
platforms are steel, tower-like structures that stand on the
ocean floor, with the top portion, or platform, above the water
level, providing the foundation upon which the platform rig is
placed. Our platform rigs can be used to provide drilling,
workover and horizontal reentry services using top drives,
enhanced pumps and solids control equipment for drilling fluids.
The crew operating on a platform rig can vary significantly
depending upon the size of the platform and the nature of the
operations being performed.
Managed Rigs. We perform rig management
services on a variety of rigs owned by others, consisting of
providing technical drilling assistance, personnel, repair and
maintenance services, and drilling operation management services.
Contract Labor. We provide contract labor
services to two offshore rigs owned and managed by others. We
provide the labor on a cost plus or fixed fee basis and do not
have any responsibility for the drilling program of the rig
owner.
The table below presents information about our land-based rig
fleet as of February 28, 2007:
A land-based drilling rig consists of engines, drawworks, a
mast, substructure, pumps to circulate the drilling fluid,
blowout preventers, drill string and related equipment. The
intended well depth and the drilling site conditions are the
principal factors that determine the size and type of rig most
suitable for a particular drilling job. Our land-based fleet
also includes a class of rigs known as workover rigs that are
designed to perform maintenance and repair or modification to
existing wells, which are referred to as workovers. Maintenance
and repair services are required on producing oil and natural
gas wells to ensure efficient, continuous operation. These
services consist of mechanical repairs necessary to maintain or
improve production from the well, such as repairing parted
sucker rods, replacing defective downhole pumps in an oil well
or replacing defective tubing in a natural gas well. Workover
services include the opening of new producing zones in an
existing well, recompletion of a well in which production has
declined, drilling out plugs and packers and the conversion of a
producing well to an injection well during enhanced recovery
operations. All of our land-based rigs can be readily moved
between well sites and
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between geographic areas of operations. Most of our land-based
drilling and land-based workover/well service rigs operate under
short-term or
well-to-well
contracts.
We provide contract drilling and related services to a customer
base that includes large multinational oil and natural gas
companies, government-owned oil and natural gas companies and
independent oil and natural gas producers. For the year ended
December 31, 2006, we had one customer, Petroleo Brasilerio
S.A. (“Petrobras”), that accounted for 16.7% of our
consolidated revenues. The loss of this significant customer
could have a material adverse effect on our results of
operations. No other customer accounted for 10% or more of our
2006 consolidated revenues.
Our drilling contracts are awarded through competitive bidding
or on a negotiated basis. The contract terms and rates vary
depending on competitive conditions, geographical area,
geological formation to be drilled, equipment and services to be
supplied,
on-site
drilling conditions and anticipated duration of the work to be
performed.
Oil and natural gas well drilling contracts are carried out on a
dayrate, footage or turnkey basis. Under dayrate contracts, we
charge the customer a fixed amount per day regardless of the
number of days needed to drill the well. In addition, dayrate
contracts usually provide for a reduced dayrate (or lump sum
amount) for mobilizing the rig to the well location or when
drilling operations are interrupted or restricted by equipment
breakdowns, adverse weather conditions or other conditions
beyond our control. Substantially all of our contracts with
major customers are on a dayrate basis. A dayrate drilling
contract generally covers either the drilling of a single well
or group of wells or has a stated term. These contracts may
generally be terminated by the customer in the event the
drilling unit is destroyed or lost or if drilling operations are
suspended for a period of time as a result of a breakdown of
equipment or, in some cases, due to other events beyond the
control of either party. In addition, drilling contracts with
certain customers are cancelable, without cause, upon little or
no prior notice and without penalty or early termination
payments. In some instances, the dayrate contract term may be
extended by the customer exercising options for the drilling of
additional wells or for an additional length of time at fixed or
mutually agreed terms, including dayrates.
Other contracts provide for payment on a footage basis, whereby
we are paid a fixed amount for each foot drilled regardless of
the time required or the problems encountered in drilling the
well. We may also enter into turnkey contracts, whereby we agree
to drill a well to a specific depth for a fixed price and to
bear some of the well equipment costs. Compared with dayrate
contracts, footage and turnkey contracts involve a higher degree
of risk to us.
Our customers may have the right to terminate, or may seek to
renegotiate, existing contracts if we experience downtime or
operational problems above a contractual limit, if the rig is a
total loss or in other specified circumstances. A customer is
more likely to seek to cancel or renegotiate its contract during
periods of depressed market conditions. We could be required to
pay penalties if some of our contracts with our customers are
canceled due to downtime or operational problems. Suspension of
drilling contracts results in the reduction in or loss of
dayrates for the period of the suspension. If our customers
cancel some of our significant contracts and we are unable to
secure new contracts on substantially similar terms, or if
contracts are suspended for an extended period of time, it could
adversely affect our consolidated financial statements.
The contract drilling industry is highly competitive. Demand for
contract drilling and related services is influenced by a number
of factors, including the current and expected prices of oil and
natural gas and the expenditures of oil and natural gas
companies for exploration and development of oil and natural
gas. In addition, demand for drilling services remains dependent
on a variety of political and economic factors beyond our
control, including worldwide demand for oil and natural gas, the
ability of the Organization of Petroleum Exporting Countries
(“OPEC”) to set and maintain production levels and
pricing, the level of production of non-OPEC
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countries and the policies of the various governments regarding
exploration and development of their oil and natural gas
reserves.
Drilling contracts are generally awarded on a competitive bid or
negotiated basis. Pricing is often the primary factor in
determining which qualified contractor is awarded a job. Rig
availability and each contractor’s safety performance
record and reputation for quality also can be key factors in the
determination. Operators also may consider crew experience, rig
location and efficiency. We believe that the market for drilling
contracts will continue to be highly competitive for the
foreseeable future. Certain competitors may have greater
financial resources than we do, which may better enable them to
withstand periods of low utilization, compete more effectively
on the basis of price, build new rigs or acquire existing rigs.
Our competition ranges from large international companies
offering a wide range of drilling and other oilfield services to
smaller, locally owned companies. We believe we are competitive
in terms of safety, pricing, performance, equipment,
availability of equipment to meet customer needs and
availability of experienced, skilled personnel, however,
industry-wide shortages of supplies, services, skilled personnel
and equipment necessary to conduct our business can occur.
Competition for offshore rigs is usually on a global basis, as
these rigs are highly mobile and may be moved, at a cost that is
sometimes substantial, from one region to another in response to
demand. Competition for land rigs is generally on a regional
basis.
Our rigs in the Gulf of Mexico are subject to severe weather
during certain periods of the year, particularly hurricane
season, which extends from June through November. In addition,
our land rig in Kazakhstan is operating on an artificial island
in the Caspian Sea. Because winter ice conditions hinder access
and resupply, the rig may be placed in a non-operating standby
mode during winter months at a reduced dayrate. Otherwise, our
business activities are not significantly affected by seasonal
fluctuations. Most of our rigs outside the Gulf of Mexico and
Kazakhstan are located in geographical areas that are not
subject to severe weather changes that would halt operations for
prolonged periods.
Our operations are subject to hazards inherent in the drilling
of oil and natural gas wells, including blowouts and well fires,
which could cause personal injury, suspend drilling operations,
or seriously damage or destroy the equipment involved. Offshore
drilling operations are also subject to hazards particular to
marine operations including capsizing, grounding, collision and
loss or damage from severe weather. We have insurance in place
covering certain exposures, including physical damage to our
drilling rigs and personal injury claims by our drilling crews.
Our marine package policy provides coverage for damage to our
rigs and loss of hire insurance for certain assets with higher
dayrates. In addition, we maintain insurance coverage for cargo,
control of well, auto liability, non-owned aviation and similar
potential liabilities. Due to losses sustained by the offshore
drilling industry as a result of the hurricanes in the Gulf of
Mexico in 2004 and 2005, our insurance costs increased
significantly as our policies renewed in July 2006. Underwriters
have also imposed an aggregate limit of approximately
$85.0 million for damage due to named wind storms in the
U.S. Gulf of Mexico, with a $10.0 million deductible
per named wind storm.
Our operations include activities that are subject to numerous
international, federal, state and local laws and regulations,
including the U.S. Oil Pollution Act of 1990, the
U.S. Outer Continental Shelf Lands Act, the Comprehensive
Environmental Response, Compensation and Liability Act and the
International Convention for the Prevention of Pollution from
Ships, governing the discharge of materials into the environment
or otherwise relating to environmental protection. Numerous
governmental agencies issue regulations to implement and enforce
such laws, which often require difficult and costly compliance
measures that carry substantial administrative, civil and
criminal penalties or may result in injunctive relief for
failure to comply. Changes in environmental laws and regulations
occur frequently, and any changes that result in more stringent
and costly compliance could adversely affect our consolidated
financial statements. While we believe that we are in
substantial compliance with the current
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laws and regulations, there is no assurance that compliance can
be maintained in the future. We do not presently anticipate that
compliance with currently applicable environmental laws and
regulations will have a material adverse effect on our
consolidated financial statements during 2007.
Hurricanes Katrina and Rita damaged a number of the
industry’s rigs in the Gulf of Mexico fleet, and rigs that
were moved off location by the storms damaged platforms,
pipelines, wellheads and other drilling rigs. In May 2006, the
Minerals Management Service of the U.S. Department of the
Interior (“MMS”) issued interim guidelines for jackup
rig fitness requirements for the 2006 hurricane season,
effectively imposing new requirements on the offshore oil and
natural gas industry in an attempt to increase the likelihood of
survival of jackup rigs and other offshore drilling units during
a hurricane. These MMS interim guidelines, which expired on
November 30, 2006, resulted in our jackup rigs operating in
the U.S. Gulf of Mexico being required to operate with a
higher air gap during the 2006 hurricane season, effectively
reducing the water depth in which they can operate. The
guidelines also provided for enhanced information and data
requirements from oil and natural gas companies operating
properties in the U.S. Gulf of Mexico. The MMS may issue
similar guidelines for future hurricane seasons and may take
other steps that could increase the cost of operations or reduce
the area of operations for our jackup rigs, thus reducing their
marketability. Implementation of new MMS guidelines or
regulations may subject us to increased costs or limit the
operational capabilities of our rigs and could materially and
adversely affect our operations and financial condition.
As of December 31, 2006, we employed approximately 14,300
personnel and had approximately 1,000 contractors working for
us. Approximately 1,800 of our employees and contractors were
located in the United States and 13,500 were located abroad.
Hourly rig crews constitute the vast majority of our employees.
None of our U.S. employees are represented by a collective
bargaining agreement. Many of our international employees are
subject to industry-wide labor contracts within their respective
countries. We believe that our relations with our employees are
good.
Available
Information
Our annual reports on
Form 10-K,
quarterly reports on
Form 10-Q
and current reports on
Form 8-K,
and any amendments to these filings, are available free of
charge through our internet website at
www.prideinternational.com as soon as reasonably
practicable after these reports have been electronically filed
with, or furnished to, the Securities and Exchange Commission.
These reports also are available at the SEC’s internet
website at www.sec.gov. Information contained on or
accessible from our website is not incorporated by reference
into this annual report on
Form 10-K
and should not be considered part of this report or any other
filing that we make with the SEC.
We have filed the required certifications of our chief executive
officer and our chief financial officer under Section 302
of the Sarbanes-Oxley Act of 2002 as exhibits 31.1 and 31.2
to this annual report. In 2006, we submitted to the New York
Stock Exchange the chief executive officer certification
required by Section 303A.12(a) of the NYSE’s Listed
Company Manual.
A
material or extended decline in expenditures by oil and natural
gas companies due to a decline or volatility in oil and natural
gas prices, a decrease in demand for oil and natural gas or
other factors may reduce demand for our services and
substantially reduce our profitability or result in our
incurring losses.
The profitability of our operations depends upon conditions in
the oil and natural gas industry and, specifically, the level of
exploration, development and production activity by oil and
natural gas companies. Oil and natural gas prices and market
expectations regarding potential changes in these prices
significantly affect this level of activity. However, higher
commodity prices do not necessarily translate into increased
drilling activity since our customers’
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expectations of future commodity prices typically drive demand
for our rigs. Oil and natural gas prices are volatile. Commodity
prices are directly influenced by many factors beyond our
control, including:
Continued hostilities in the Middle East and the occurrence or
threat of terrorist attacks against the United States or other
countries could cause a downturn in the economies of the United
States and those of other countries. A lower level of economic
activity could result in a decline in energy consumption, which
could cause our revenues and margins to decline and limit our
future growth prospects. More specifically, these risks could
lead to increased volatility in prices for oil and natural gas
and could affect the markets for our drilling services. In
addition, these risks could increase instability in the
financial and insurance markets and make it more difficult for
us to access capital and to obtain insurance coverages that we
consider adequate or are otherwise required by our contracts.
Depending on the market prices of oil and natural gas, and even
during periods of high commodity prices, companies exploring for
and producing oil and natural gas may cancel or curtail their
drilling programs, or reduce their levels of capital
expenditures for exploration and production for a variety of
reasons, including their lack of success in exploration efforts.
Such a reduction in demand may decrease daily rates and
utilization of our rigs. Any significant decrease in daily rates
or utilization of our rigs, particularly our high-specification
drillships, semisubmersible rigs or jackup rigs, could
materially reduce our revenues and profitability.
Demand and contract prices customers pay for our rigs also are
affected by the total supply of comparable rigs available for
service in the markets in which we compete. During prior periods
of high utilization and dayrates, industry participants have
increased the supply of rigs by ordering the construction of new
units. This has often created an oversupply of drilling units
and has caused a decline in utilization and dayrates when the
rigs enter the market, sometimes for extended periods of time as
rigs have been absorbed into the active fleet. Orders for
construction of approximately 65 jackup rigs have been announced
with delivery dates ranging from 2007 to 2010. Most of these
units are cantilevered units and are considered to be premium
units. In the deepwater sector, there have been announcements of
approximately 45 new semisubmersible rigs and drillships and the
upgrade of approximately five other semisubmersibles to
ultra-deepwater units, with delivery forecast to occur from 2007
through 2010. A number of the contracts for units
currently under construction provide for options for the
construction of additional units, and we believe further new
construction announcements are likely for all classes of rigs
pursuant to the exercise of one or more of these options and
otherwise. In addition, our competitors’
“cold-stacked” (i.e., minimally crewed with
little or no scheduled maintenance being performed) rigs may
re-enter the market. The entry into service of newly
constructed, upgraded or reactivated units will increase
marketed supply
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and could curtail a further strengthening of dayrates, or reduce
them, in the affected markets as rigs are absorbed into the
active fleet. Any further increase in construction of new
drilling units may exacerbate the negative impacts on
utilization and dayrates. In addition, the new construction of
high specification rigs, as well as changes in our
competitors’ drilling rig fleets, could require us to make
material additional capital investments to keep our rig fleet
competitive.
Our industry is highly competitive. Our contracts are
traditionally awarded on a competitive bid basis. Pricing is
often the primary factor in determining which qualified
contractor is awarded a job. Rig availability and each
contractor’s safety performance record and reputation for
quality also can be key factors in the determination. Some of
our competitors in the drilling industry are larger than we are
and have more diverse fleets, or fleets with generally higher
specifications, and greater resources than we have. Some of
these competitors also are incorporated in tax-haven countries
outside the United States, which provides them with significant
tax advantages that are not available to us as a
U.S. company and which materially impairs our ability to
compete with them for many projects that would be beneficial to
our company. In addition, recent mergers within the oil and
natural gas industry have reduced the number of available
customers and suppliers, resulting in increased price
competition and fewer alternatives for sourcing of key supplies.
We may not be able to maintain our competitive position, and we
believe that competition for contracts will continue to be
intense in the foreseeable future. Our inability to compete
successfully may reduce our revenues and profitability.
Historically, the offshore service industry has been highly
cyclical, with periods of high demand, limited rig supply and
high dayrates often followed by periods of low demand, excess
rig supply and low dayrates. Periods of low demand and excess
rig supply intensify the competition in the industry and often
result in rigs, particularly lower specification rigs like a
large portion of our fleet, being idle for long periods of time.
We may be required to idle rigs or enter into lower dayrate
contracts in response to market conditions in the future.
Prolonged periods of low utilization and dayrates could result
in the recognition of impairment charges on certain of our rigs
if future cash flow estimates, based upon information available
to management at the time, indicate that the carrying value of
these rigs may not be recoverable.
We require highly skilled personnel to operate and provide
technical services and support for our business. Competition for
the skilled and other labor required for our operations
intensifies as the number of rigs activated or added to
worldwide fleets or under construction increases. In periods of
high utilization, such as the current period, we have found it
more difficult to find and retain qualified individuals. We have
experienced tightening in the relevant labor markets since 2005
and have recently sustained the loss of experienced personnel to
our customers and competitors. Our labor costs increased
significantly in 2005 and 2006, and we expect this trend to
continue in 2007. The shortages of qualified personnel or the
inability to obtain and retain qualified personnel could
negatively affect the quality and timeliness of our work. We
have intensified our recruitment and training programs in an
effort to meet our anticipated personnel needs. These efforts
may be unsuccessful, and competition for skilled personnel could
materially impact our business by limiting or affecting the
quality and safety of our operations or further increasing our
costs.
In 2006, we derived 81.2% of our revenues from countries outside
the United States. Our operations in these areas are subject to
the following risks, among others:
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We attempt to limit the risks of currency fluctuation and
restrictions on currency repatriation where possible by
obtaining contracts providing for payment in U.S. dollars
or freely convertible foreign currency. To the extent possible,
we seek to limit our exposure to local currencies by matching
the acceptance of local currencies to our expense requirements
in those currencies. Although we have done this in the past, we
may not be able to take these actions in the future, thereby
exposing us to foreign currency fluctuations that could cause
our results of operations, financial condition and cash flows to
deteriorate materially.
In 2006, we derived 6.3% of our revenues from operations in
Venezuela, which has been experiencing political, economic and
social turmoil, including labor strikes and demonstrations. The
implications and results of the political, economic and social
instability in Venezuela are uncertain at this time, but the
instability could have an adverse effect on our business. The
Venezuelan government frequently intervenes in the Venezuelan
economy and occasionally makes significant changes in policy.
Recently, the government’s actions to control inflation and
implement other policies have involved wage and price controls,
currency devaluations, capital controls and limits on imports,
among other things. Several measures imposed by the Venezuelan
government, such as exchange controls and currency transfer
restrictions, limit our ability to convert the local currency
into U.S. dollars and transfer excess funds out of
Venezuela. Although our current drilling contracts in Venezuela
call for a significant portion of our dayrates to be paid in
U.S. dollars, changes in existing regulations or the
interpretation or enforcement of those regulations could further
restrict our ability to receive U.S. dollar payments. The
exchange controls could also result in an artificially high
value being placed on the local currency, which could affect our
operating costs, revenues and financial results.
Our international operations are also subject to other risks,
including foreign monetary and tax policies and nullification or
modification of contracts. Additionally, our ability to compete
in international contract drilling markets may be limited by
foreign governmental regulations that favor or require the
awarding of contracts to local contractors or by regulations
requiring foreign contractors to employ citizens of, or purchase
supplies from, a particular jurisdiction. Furthermore, our
foreign subsidiaries may face governmentally imposed
restrictions from time to time on their ability to transfer
funds to us.
During the course of an internal audit and investigation
relating to certain of our Latin American operations, our
management and internal audit department received allegations of
improper payments to foreign government officials. In February
2006, shortly after and as a result of certain statements that
were made by an employee during the investigation, the Audit
Committee of our Board of Directors assumed direct
responsibility over the investigation and retained independent
outside counsel to investigate the allegations, as well as
corresponding accounting entries and internal control issues,
and to advise the Audit Committee.
The investigation, which is continuing, has found evidence
suggesting that payments, which may violate the U.S. Foreign
Corrupt Practices Act, were made to government officials in
Latin America aggregating less than $1 million. The
evidence to date regarding these payments suggests that payments
were made beginning in early
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2003 through 2005 (a) to vendors with the intent that they
would be transferred to government officials for the purpose of
extending drilling contracts for two jackup rigs and one
semisubmersible rig operating offshore Venezuela; and
(b) to one or more government officials, or to vendors with
the intent that they would be transferred to government
officials, for the purpose of collecting payment for work
completed in connection with offshore drilling contracts in
Venezuela. In addition, the evidence suggests that other
payments were made beginning in 2003 through early 2006
(a) to one or more government officials in Mexico in
connection with the clearing of a jackup rig and equipment
through customs or the movement of personnel through
immigration; and (b) with respect to the potentially
improper entertainment of government officials in Mexico.
The Audit Committee, through independent outside counsel, has
undertaken a review of our compliance with the FCPA in certain
of our other international operations. This review has found
evidence suggesting that in 2004 and 2005 payments may have been
made to government officials in Saudi Arabia and Kazakhstan,
aggregating less than $175,000, in connection with clearing rigs
or equipment through customs or resolving outstanding customs
issues in those countries. The investigation of the matters
related to Saudi Arabia and Kazakhstan and the Audit
Committee’s compliance review are ongoing. Accordingly,
there can be no assurances that evidence of additional potential
FCPA violations may not be uncovered in Saudi Arabia, Kazakhstan
or other countries.
Our management and the Audit Committee of our Board of Directors
believe it likely that members of our senior operations
management either were aware, or should have been aware, that
improper payments to foreign government officials were made or
proposed to be made. Our former Chief Operating Officer resigned
as Chief Operating Officer effective on May 31, 2006 and
has elected to retire from the company, although he will remain
an employee, but not an officer, during the pendency of the
investigation to assist us with the investigation and to be
available for consultation and to answer questions relating to
our business. His retirement benefits will be subject to the
determination by our Audit Committee or our Board of Directors
that it does not have cause (as defined in his retirement
agreement with us) to terminate his employment. On
December 1, 2006, our Vice President — Western
Hemisphere Operations resigned. On December 2, 2006, our
former Country Manager in Venezuela and Mexico was terminated.
We have placed another member of our senior operations
management on administrative leave pending the outcome of the
investigation.
We voluntarily disclosed information relating to the initial
allegations and other information found in the investigation and
compliance review to the U.S. Department of Justice and the
Securities and Exchange Commission and are cooperating with
these authorities as the investigation and compliance reviews
continue and as they review the matter. If violations of the
FCPA occurred, we could be subject to fines, civil and criminal
penalties, equitable remedies, including profit disgorgement,
and injunctive relief. Civil penalties under the antibribery
provisions of the FCPA could range up to $10,000 per violation,
with a criminal fine up to the greater of $2 million per
violation or twice the gross pecuniary gain to us or twice the
gross pecuniary loss to others, if larger. Civil penalties under
the accounting provisions of the FCPA can range up to $500,000
and a company that knowingly commits a violation can be fined up
to $25 million. In addition, both the SEC and the DOJ could
assert that conduct extending over a period of time may
constitute multiple violations for purposes of assessing the
penalty amounts. Often, dispositions for these types of matters
result in modifications to business practices and compliance
programs and possibly a monitor being appointed to review future
business and practices with the goal of ensuring compliance with
the FCPA.
We could also face fines, sanctions and other penalties from
authorities in the relevant foreign jurisdictions, including
prohibition of our participating in or curtailment of business
operations in those jurisdictions. Our customers in those
jurisdictions could seek to impose penalties or take other
actions adverse to our interests. In addition, disclosure of the
subject matter of the investigation could adversely affect our
reputation and our ability to obtain new business or retain
existing business from our current clients and potential
clients, to attract and retain employees and to access the
capital markets. No amounts have been accrued related to any
potential fines, sanctions or other penalties.
We cannot currently predict what, if any, actions may be taken
by the DOJ, the SEC, the applicable government or other
authorities or our customers or the effect the actions may have
on our results of operations, financial condition or cash flows,
on our consolidated financial statements or on our business in
the countries at issue and other jurisdictions.
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For the years ended December 31, 2006, 2005 and 2004, our
operations in Venezuela provided revenues of approximately
$156.9 million, $172.6 million, and
$167.1 million, or approximately 6.3%, 8.5% and 9.8% of our
total consolidated revenues, respectively. Our Venezuela
operations provided earnings (loss) from operations of
approximately $6.9 million, $16.8 million, and $(6.7)
million or approximately 1.3%, 5.2% and (2.7)% of our total
consolidated earnings from operations for 2006, 2005 and 2004,
respectively. As of December 31, 2006 and 2005, we had
accounts receivable from Petróleos de Venezuela, S.A.
totaling $27.6 million and $33.4 million, respectively.
We have a number of contracts that will expire in 2007 and 2008.
Our ability to renew these contracts or obtain new contracts and
the terms of any such contracts will depend on market
conditions. We may be unable to renew our expiring contracts or
obtain new contracts for the rigs, and the dayrates under any
new contracts may be substantially below the existing dayrates,
which could materially reduce our revenues and profitability.
Substantially all our contracts with major customers are dayrate
contracts, where we charge a fixed charge per day regardless of
the number of days needed to drill the well. During depressed
market conditions, a customer may no longer need a rig that is
currently under contract or may be able to obtain a comparable
rig at a lower daily rate. As a result, customers may seek to
renegotiate the terms of their existing drilling contracts or
avoid their obligations under those contracts. In addition, our
customers may have the right to terminate, or may seek to
renegotiate, existing contracts if we experience downtime,
operational problems above the contractual limit or
safety-related issues, if the rig is a total loss or in other
specified circumstances. Some of our contracts with our
customers include terms allowing them to terminate contracts
without cause, with little or no prior notice and without
penalty or early termination payments. In addition, we could be
required to pay penalties, which could be material, if some of
our contracts with our customers are terminated due to downtime
or operational problems. Some of our other contracts with
customers may be cancelable at the option of the customer upon
payment of a penalty, which may not fully compensate us for the
loss of the contract. Early termination of a contract may result
in a rig being idle for an extended period of time. The
likelihood that a customer may seek to terminate a contract is
increased during periods of market weakness. If our customers
cancel some of our significant contracts and we are unable to
secure new contracts on substantially similar terms, our
revenues and profitability could be materially reduced.
Our
jackup rigs and some of our lower specification semisubmersible
rigs are at a relative disadvantage to higher specification
jackup and semisubmersible rigs. These higher specification rigs
may be more likely to obtain contracts than our lower
specification rigs, particularly during market
downturns.
Many of our competitors have jackup fleets with generally higher
specification rigs than those in our jackup fleet, and our fleet
includes a number of older, lower specification semisubmersible
rigs. In addition, the announced construction of new rigs
includes approximately 110 jackup rigs, semisubmersible rigs and
ultra-deepwater drillships. Particularly during market downturns
when there is decreased rig demand, higher specification rigs
may be more likely to obtain contracts than lower specification
rigs. In the past, our lower specification rigs have been
stacked earlier in the cycle of decreased rig demand than many
of our competitors’ higher specification rigs and have been
reactivated later in the cycle, which has adversely impacted our
business and could be repeated in the future. In addition,
higher specification rigs may be more adaptable to different
operating conditions and have greater flexibility to move to
areas of demand in response to changes in market conditions.
Furthermore, in recent years, an increasing amount of
exploration and production expenditures have been concentrated
in deeper water drilling programs and deeper formations,
including deep natural gas prospects, requiring higher
specification rigs. This trend is expected to continue and could
result in a material decline in demand for the lower
specification rigs in our fleet.
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Most jackup and submersible rigs can be moved from one region to
another, and in this sense the contract drilling market is a
global market. The supply and demand balance for jackup and
semisubmersible rigs may vary somewhat from region to region,
because the cost to move a rig is significant, there is limited
availability of rig-moving vessels and some rigs are designed to
work in specific regions. However, significant variations
between regions tend not to exist on a long-term basis due to
the ability to move rigs. Our mat-supported jackup rigs are less
capable of managing variable sea floor conditions found in areas
outside the Gulf of Mexico. As a result, our ability to move
these rigs to other regions in response to changes in market
conditions is limited.
Our contract drilling business is subject to the usual risks
associated with having a limited number of customers for our
services. For the year ended December 31, 2006, Petrobras
provided 16.7% of our consolidated revenues. Our two next
largest customers, none of which individually represented more
than 10% of revenues, accounted in the aggregate for 16.3% of
our 2006 consolidated revenues. For the year ended
December 31, 2005, Petrobras and Petroleos Mexicanos S.A.
(“PEMEX”) accounted for 14.4% and 10.7%, respectively,
of consolidated revenues. Our two next largest customers,
neither of which individually represented more than 10% of
revenues, accounted in the aggregate for 13.9% of our 2005
consolidated revenues. Our results of operations could be
materially adversely affected if any of our major customers
terminates its contracts with us, fails to renew its existing
contracts or refuses to award new contracts to us.
As of December 31, 2006, we had $1,386.6 million in
long-term debt. Our current indebtedness may have several
important effects on our future operations, including:
Our ability to meet our debt service obligations and to reduce
our total indebtedness will be dependent upon our future
performance, which will be subject to general economic
conditions, industry cycles and financial, business and other
factors affecting our operations, many of which are beyond our
control.
Our operations are subject to hazards customary in the drilling
industry, such as blowouts, reservoir damage, loss of
production, loss of well control, lost or stuck drill strings,
equipment defects, punchthroughs, craterings, fires, explosions
and pollution. Contract drilling and well servicing require the
use of heavy equipment and exposure to hazardous conditions,
which may subject us to liability claims by employees, customers
and third parties. These hazards can cause personal injury or
loss of life, severe damage to or destruction of property and
equipment, pollution or environmental damage and suspension of
operations. Our offshore fleet is also subject to hazards
inherent in marine operations, either while on site or during
mobilization, such as capsizing, sinking, grounding, collision
and damage from severe weather. Operations may also be suspended
because of machinery
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breakdowns, abnormal drilling conditions, failure of
subcontractors to perform or supply goods or services, or
personnel shortages. We customarily provide contract indemnity
to our customers for:
Certain areas in and near the Gulf of Mexico are subject to
hurricanes and other extreme weather conditions on a relatively
frequent basis. Our drilling rigs in the Gulf of Mexico may be
located in areas that could cause them to be susceptible to
damage or total loss by these storms. In addition, damage caused
by high winds and turbulent seas to our rigs, our shorebases and
our corporate infrastructure could potentially cause us to
curtail operations for significant periods of time until the
damages can be repaired.
We maintain insurance for injuries to our employees, damage to
or loss of our equipment and other insurance coverage for normal
business risks, including general liability insurance. Any
insurance protection may not be sufficient or effective under
all circumstances or against all hazards to which we may be
subject. For example, pollution, reservoir damage and
environmental risks generally are not fully insurable. Except
for a portion of our deepwater fleet, we generally do not
maintain business interruption or loss of hire insurance. In
addition, some of our primary insurance policies have
substantial per occurrence or annual deductibles
and/or
self-insured aggregate amounts.
As a result of a number of catastrophic events in our industry
over the last few years, such as the hurricanes in the Gulf of
Mexico in 2004 and 2005, insurance underwriters have increased
insurance premiums for many of the coverages historically
maintained and have issued general notices of cancellation and
significant changes for a wide variety of insurance coverages.
The oil and natural gas industry in the Gulf of Mexico suffered
extensive damage from those hurricanes. As a result, our
insurance costs increased significantly as our policies renewed
in July 2006. In addition, underwriters have also imposed an
aggregate limit of approximately $85.0 million for damage
due to named wind storms in the U.S. Gulf of Mexico, with a
$10.0 million deductible per named wind storm. A number of
our customers that produce oil and natural gas in the Gulf of
Mexico have maintained business interruption insurance for their
production. This insurance may cease to be available in the
future, which could adversely impact our customers’
business prospects in the Gulf of Mexico and reduce demand for
our services.
The occurrence of a significant event against which we are not
fully insured, or of a number of lesser events against which we
are insured but are subject to substantial deductibles,
aggregate limits,
and/or
self-insured amounts, could materially increase our costs and
impair our profitability and financial condition. We may not be
able to maintain adequate insurance at rates or on terms that we
consider reasonable or acceptable or be able to obtain insurance
against certain risks.
We make significant upgrade, refurbishment and repair
expenditures for our fleet from time to time, particularly in
light of the aging nature of our rigs. Some of these
expenditures are unplanned. In addition, depending on available
opportunities, we may construct rigs for our fleet in the
future. All of these projects are subject to the risks of delay
or cost overruns, including costs or delays resulting from the
following:
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Significant cost overruns or delays could materially affect our
financial condition and results of operations. Additionally,
capital expenditures for rig upgrade, refurbishment and
construction projects could materially exceed our planned
capital expenditures. Moreover, our rigs undergoing upgrade,
refurbishment and repair may not earn a dayrate during the
period they are out of service.
The capital associated with the repair and maintenance of our
fleet increases with age. We may not be able to maintain our
fleet by extending the economic life of existing rigs, and our
financial resources may not be sufficient to enable us to make
expenditures necessary for these purposes or to acquire or build
replacement rigs.
Many aspects of our operations are affected by governmental laws
and regulations that may relate directly or indirectly to the
contract drilling and well servicing industries, including those
requiring us to control the discharge of oil and other
contaminants into the environment or otherwise relating to
environmental protection. Our operations and activities in the
United States are subject to numerous environmental laws and
regulations, including the Oil Pollution Act of 1990, the Outer
Continental Shelf Lands Act, the Comprehensive Environmental
Response, Compensation and Liability Act and the International
Convention for the Prevention of Pollution from Ships.
Additionally, other countries where we operate have
environmental laws and regulations covering the discharge of oil
and other contaminants and protection of the environment in
connection with operations. Failure to comply with these laws
and regulations may result in the assessment of administrative,
civil and even criminal penalties, the imposition of remedial
obligations, the denial or revocation of permits or other
authorizations and the issuance of injunctions that may limit or
prohibit our operations. Laws and regulations protecting the
environment have become more stringent in recent years and may
in certain circumstances impose strict liability, rendering us
liable for environmental and natural resource damages without
regard to negligence or fault on our part. These laws and
regulations may expose us to liability for the conduct of, or
conditions caused by, others or for acts that were in compliance
with all applicable laws at the time the acts were performed.
The application of these requirements, the modification of
existing laws or regulations or the adoption of new laws or
regulations curtailing exploratory or development drilling for
oil and natural gas could materially limit future contract
drilling opportunities or materially increase our costs or both.
In addition, we may be required to make significant capital
expenditures to comply with laws and regulations or materially
increase our costs or both.
Hurricanes Katrina and Rita in 2005 caused damage to a number of
rigs in the Gulf of Mexico fleet, and rigs that were moved off
location by the storms damaged platforms, pipelines, wellheads
and other drilling rigs. In May 2006, the MMS issued interim
guidelines for jackup rig fitness requirements for the 2006
hurricane season, effectively imposing new requirements on the
offshore oil and natural gas industry in an attempt to increase
the likelihood of survival of jackup rigs and other offshore
drilling units during a hurricane. These MMS interim guidelines,
which expired on November 30, 2006, resulted in our jackup
rigs operating in the U.S. Gulf of Mexico being required to
operate with a higher air gap during the 2006 hurricane season,
effectively reducing the water
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depth in which they can operate. The guidelines also provided
for enhanced information and data requirements from oil and
natural gas companies operating properties in the U.S. Gulf
of Mexico. The MMS may issue similar guidelines for future
hurricane seasons and may take other steps that could increase
the cost of operations or reduce the area of operations for our
jackup rigs, thus reducing their marketability. Implementation
of new MMS guidelines or regulations may subject us to increased
costs and limit the operational capabilities of our rigs.
We conduct our worldwide operations through various
subsidiaries. Tax laws and regulations are highly complex and
subject to interpretation. Consequently, we are subject to
changing tax laws, treaties and regulations in and between
countries in which we operate, including treaties between the
United States and other nations. Our income tax expense is based
upon our interpretation of the tax laws in effect in various
countries at the time that the expense was incurred. A change in
these tax laws, treaties or regulations, including those in and
involving the United States, or in the interpretation thereof,
could result in a materially higher tax expense or a higher
effective tax rate on our worldwide earnings.
As required by law, we file periodic tax returns that are
subject to review and examination by various revenue agencies
within the jurisdictions in which we operate. We are currently
contesting several tax assessments that could be material and
may contest future assessments where we believe the assessments
are in error. We cannot predict or provide assurance as to the
ultimate outcome of existing or future tax assessments.
A number of our contracts with our customers for our offshore
rigs are on a long-term fixed dayrate basis. Generally, costs
increase as the business environment for drilling services
improves and demand for oilfield equipment and skilled labor
increases. Long-term fixed dayrate contracts limit our ability
to adjust dayrates in response to increased costs. As a result,
substantial increase in our costs associated with these
contracts would adversely impact our profitability and this
impact could be material.
In periods of rising demand for offshore rigs, a drilling
contractor generally would prefer to enter into
well-to-well
or other shorter term contracts that would allow the contractor
to profit from increasing dayrates, while customers with
reasonably definite drilling programs would typically prefer
longer term contracts in order to maintain dayrates at a
consistent level. Conversely, in periods of decreasing demand
for offshore rigs, a drilling contractor generally would prefer
longer term contracts to preserve dayrates and utilization,
while customers generally would prefer
well-to-well
contracts or other shorter term contracts that would allow the
customer to benefit from the decreasing dayrates. As a result of
a number of our contracts for offshore rigs being on a long-term
fixed dayrate basis, our inability to fully benefit from
increasing dayrates in an improving market may limit our
profitability.
Certain of our employees in international markets are
represented by labor unions and work under collective bargaining
or similar agreements, which are subject to periodic
renegotiation. Efforts have been made from time to time to
unionize other portions of our workforce. In addition, we have
been subjected to strikes or work stoppages in certain
countries. Additional unionization efforts, new collective
bargaining agreements or work stoppages could materially
increase our costs or limit our flexibility.
Certain legal obligations require us to contribute certain
amounts to retirement funds and pension plans and restrict our
ability to dismiss employees. Future regulations or court
interpretations established in the countries in
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which we conduct our operations could increase our costs and
materially adversely affect our business, financial condition
and results of operation.
In many of the countries in which we operate, our workforce has
certain compensation and other rights relating to involuntary
terminations arising from our various collective bargaining
agreements and from statutory requirements of those countries.
If we choose to cease operations in one of those countries or if
market conditions reduce the demand for our drilling services in
such a country, we could incur costs, which may be material,
associated with workforce reductions.
Public health threats, such as the bird flu, Severe Acute
Respiratory Syndrome (SARS), and other highly communicable
diseases, outbreaks of which have already occurred in various
parts of the world in which we operate, could adversely impact
our operations, the operations of our clients and the global
economy, including the worldwide demand for oil and natural gas
and the level of demand for our services. Any quarantine of
personnel or inability to access our offices or rigs could
adversely affect our operations. Travel restrictions or
operational problems in any part of the world in which we
operate, or any reduction in the demand for drilling services
caused by public health threats in the future, may materially
impact operations and adversely affect our financial results.
None.
Our property consists primarily of mobile offshore and
land-based drilling rigs, well servicing rigs and ancillary
equipment, most of which we own. We operate some rigs under
joint venture arrangements, management agreements and lease
agreements. Some of our rigs are pledged to collateralize our
secured credit facilities. See “Management’s
Discussion and Analysis of Financial Condition and Results of
Operations — Liquidity and Capital Resources” in
Item 7 of this annual report. We also own and operate
transport and heavy duty trucks and other ancillary equipment.
We own office and operating facilities in Houma, Louisiana and
in Algeria, Angola, Argentina, Brazil, Colombia, France, Peru
and Venezuela. Additionally, we lease office and operating
facilities in Houston, Texas and in several international
locations.
We incorporate by reference in response to this item the
information set forth in Item 1 and Item 7 of this
annual report and the information set forth in Notes 3 and
5 of our Notes to Consolidated Financial Statements included in
Item 8 of this annual report.
We incorporate by reference in response to this item the
information set forth in “Management’s Discussion and
Analysis of Financial Condition and Results of
Operations — FCPA Investigation” in Item 7
of this annual report.
In August 2004, we were notified that certain of our
subsidiaries have been named, along with other defendants, in
several complaints that have been filed in the Circuit Courts of
the State of Mississippi by several hundred individuals that
allege that they were employed by some of the named defendants
between approximately 1965 and 1986. Additional suits have been
filed since August 2004. The complaints allege that certain
drilling contractors used products containing asbestos in
offshore drilling operations, land-based drilling operations and
in
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drilling structures, drilling rigs, vessels and other equipment.
The plaintiffs assert claims based on, among other things,
negligence and strict liability and claims under the Jones Act.
The complaints name as defendants numerous other companies that
are not affiliated with us, including companies that allegedly
manufactured drilling related products containing asbestos that
are the subject of the complaints. The plaintiffs seek, among
other things, an award of unspecified compensatory and punitive
damages. Eight individuals of the many plaintiffs in these suits
have been identified as allegedly having worked for us or one of
our affiliates or predecessors. Currently, discovery and
investigation is ongoing to determine whether these individuals
were employed in our offshore operations during the alleged
period of exposure. We intend to defend ourselves vigorously
and, based on the information available to us at this time, we
do not expect the outcome of these lawsuits to have a material
adverse effect on our financial position, results of operations
or cash flows; however, there can be no assurance as to the
ultimate outcome of these lawsuits.
Paul A. Bragg, our former President and Chief Executive Officer,
filed suit against us in State District Court of Harris County,
Texas in early October 2005 seeking a declaratory judgment that
the non-competition provisions of his employment agreement are
unlawful and unenforceable. Shortly thereafter, Mr. Bragg
filed a second lawsuit against us alleging that we breached
written and oral employment agreements with him and seeking
damages aggregating more than $17.0 million. The suits were
consolidated.
We filed counterclaims against Mr. Bragg related to his
non-competition claim seeking a declaratory judgment that the
non-competition provisions of his employment agreement are
enforceable and restitution of certain amounts paid to
Mr. Bragg should there be a finding that the
non-competition provisions of his employment agreement are
unenforceable. On February 1, 2007, the trial court granted
Mr. Bragg’s motion to dismiss, without prejudice, his
declaratory judgment claim related to his covenant not to
compete. We, in turn, are seeking to dismiss, without prejudice,
our counterclaims in connection with Mr. Bragg’s
covenant not to compete declaratory judgment claim.
We filed counterclaims against Mr. Bragg related to his
claims for breach of contract claiming, among other things,
(i) breach of fiduciary duty seeking disgorgement of
certain amounts previously paid to Mr. Bragg stemming from
actions that may have been taken by Mr. Bragg relating to
his employment compensation claims, (ii) declaratory
judgment that we did not breach his contract and
(iii) breach of contract. On October 25, 2006, the
trial court granted summary judgment in our favor dismissing
Mr. Bragg’s claims for damages related to an alleged
breach of written and oral employment agreements. On
December 20, 2006, the trial court granted summary judgment
against us on our counterclaim for breach of fiduciary duty. We
subsequently filed a notice of appeal with respect to the trial
court’s dismissal of our counterclaim for breach of
fiduciary duty. We are seeking to dismiss, without prejudice,
our remaining counterclaims, and we have obtained a tolling
agreement allowing us to resuscitate these counterclaims at a
later date if we so choose.
Currently, the only matter outstanding before the trial court is
Mr. Bragg’s motion for reconsideration of the trial
court’s order dismissing his breach of contract claims. We
intend to defend ourselves vigorously and, based on the
information available to us at this time, we do not expect the
outcome of this lawsuit to have a material adverse effect on our
financial position, results of operations or cash flows;
however, there can be no assurance as to the ultimate outcome of
this lawsuit.
We are routinely involved in other litigation, claims and
disputes incidental to our business, which at times involve
claims for significant monetary amounts, some of which would not
be covered by insurance. In the opinion of management, none of
the existing litigation will have a material adverse effect on
our financial position, results of operations or cash flows.
However, a substantial settlement payment or judgment in excess
of our accruals could have a material adverse effect on our
financial position, results of operations or cash flows.
None.
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We have presented below information about our executive officers
as of February 28, 2007. Officers are appointed annually by
the Board of Directors and serve until their successors are
chosen or until their resignation or removal.
Louis A. Raspino was named President, Chief Executive
Officer and a Director of Pride in June 2005. He joined Pride in
December 2003 as Executive Vice President and Chief Financial
Officer. From July 2001 until December 2003, he served as Senior
Vice President, Finance and Chief Financial Officer of Grant
Prideco, Inc. From December 2000 until March 2001, he was
employed as Executive Vice President, Chief Financial Officer
and Chief Operating Officer of JRL Enterprises, Inc. From
February 1999 until December 2000, he served as Vice President
of Finance for Halliburton Company. From October 1997 until July
1998, he was a Senior Vice President at Burlington Resources,
Inc. From 1978 until its merger with Burlington Resources, Inc.
in 1997, he held a variety of increasingly responsible positions
at Louisiana Land and Exploration Company, most recently as
Senior Vice President, Finance and Administration and Chief
Financial Officer. Mr. Raspino also is a Director of
Dresser-Rand Group Inc.
Rodney W. Eads was named Executive Vice President, Chief
Operating Officer in September 2006. Since 1997, he served as
Senior Vice President, Worldwide Operations for Diamond
Offshore, where he was responsible for their offshore drilling
fleet. From 1980 through 1997 he served in several executive and
operations management positions with Exxon Corporation,
primarily in international assignments and including Drilling
Manager, Exxon Company International. Prior to joining Exxon,
Mr. Eads served as a Senior Drilling Engineer for ARAMCO
and a Petroleum Engineer with Cities Services Corporation.
Brian C. Voegele joined Pride in December 2005 and became
Senior Vice President and Chief Financial Officer in January
2006. From June 2005 through November 2005, he served as Senior
Vice President, Chief Financial Officer, Treasurer and Secretary
of Offshore Logistics, Inc. From July 1989 until January 2005,
he held various senior management positions at Transocean Inc.
Mr. Voegele began his career at Arthur Young &
Co., where he ultimately served as Tax Manager.
Lonnie D. Bane was named Senior Vice President, Human
Resources in January 2005. He previously served as Vice
President, Human Resources since June 2004. From July 2000 until
May 2003, he served as Senior Vice President, Human Resources of
America West Airlines, Inc. From July 1998 until July 2000, he
held various senior management positions, including Senior Vice
President, Human Resources at Corporate Express, Inc. From
February 1996 until July 1998, Mr. Bane served as Senior
Vice President, Human Resources for CEMEX, S.A. de C.V. From
1994 until 1996, he was a Vice President, Human Resources at
Allied Signal Corporation. From 1987 until 1994, he held various
management positions at Mobil Oil Corporation.
W. Gregory Looser was named Senior Vice President,
General Counsel and Secretary in January 2005. He previously
served as Vice President, General Counsel and Secretary since
December 2003. He joined Pride in May 1999 as Assistant General
Counsel. Prior to that time, Mr. Looser was with the law
firm of Bracewell & Guiliani, L.L.P. in Houston, Texas.
Kevin C. Robert was named Vice President, Marketing in
March 2005 and became Senior Vice President, Marketing and
Business Development in May 2006. Prior to joining Pride, from
June 2002 to February 2005,
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Mr. Robert worked for Samsung Heavy Industries as the Vice
President, EPIC Contracts. From January 2001 through September
2001, Mr. Robert was employed by Marine Drilling Companies,
Inc. as the Vice President, Marketing. When Pride acquired
Marine in September 2001, he became our Director of Business
Development, where he served until June 2002. From November 1997
through December 2000, Mr. Robert was Managing Member of
Maverick Offshore L.L.C. From January 1981 to November 1997,
Mr. Robert was employed by Conoco Inc.
K. George Wasaff was named Chief Executive Officer
for Latin America Land and E&P Services in January 2007.
Since 2005, Mr. Wasaff has been employed by Ashmore Energy
International as Executive Vice President responsible for
worldwide operations and Senior Vice President of Operations and
Administration of Prisma Energy. Mr. Wasaff was previously
employed by Enron Corp. from 1986 to 2005 in a variety of roles,
including Senior Vice President, Wholesale Operations of South
America, Vice Chairman and Chief Executive Officer of
Transportadora de Gas del Sur S.A., Country Manager and Vice
President, Mexico and, most recently, Managing Director,
Corporate Services and member of the Management Committee. Prior
to that, Mr. Wasaff was a marketing manager for El Paso
Natural Gas Company.
Our common stock is listed on the New York Stock Exchange under
the symbol “PDE.” As of February 27, 2007, there
were approximately 1,200 stockholders of record. The
following table presents the range of high and low sales prices
of our common stock on the NYSE for the periods shown:
We have not paid any cash dividends on our common stock since
becoming a publicly held corporation in September 1988. We do
not currently intend to pay any cash dividends on our common
stock. In addition, our ability to pay cash dividends is
restricted by our existing financing arrangements.
Unregistered
Sales of Equity Securities
None.
Issuer
Purchases of Equity Securities
None.
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We have derived the following selected consolidated financial
information as of December 31, 2006 and 2005, and for the
years ended December 31, 2006, 2005 and 2004, from our
audited consolidated financial statements included in
Item 8 of this annual report. We have derived the selected
consolidated financial information as of December 31, 2004,
2003 and 2002, and for the years ended December 31, 2003
and 2002 from consolidated financial information included our
annual report on
Form 10-K
for the year ended December 31, 2005. The selected
consolidated financial information below should be read together
with “Management’s Discussion and Analysis of
Financial Condition and Results of Operations” in
Item 7 of this annual report and our audited consolidated
financial statements and related notes included in Item 8
of this annual report.
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Management’s Discussion and Analysis of Financial Condition
and Results of Operations should be read in conjunction with
“Financial Statement and Supplementary Data” in
Item 8 of this annual report. The following discussion and
analysis contains forward-looking statements that involve risks
and uncertainties. Our actual results may differ materially from
those anticipated in these forward-looking statements as a
result of certain factors, including those set forth under
“Risk Factors” in Item 1A and elsewhere in this
annual report. See “Forward-Looking Statements” below.
We provide contract drilling and related services to oil and
natural gas companies worldwide, operating both offshore and on
land. As of February 28, 2007, we owned a global fleet of
272 rigs, consisting of two deepwater drillships, 12
semisubmersible rigs, 28 jackup rigs, 16 tender-assisted, barge
and platform rigs and 214 land-based drilling and workover
rigs. Our customers include the major integrated oil and natural
gas companies, independent oil and natural gas companies and
state-owned national oil companies. Our competitors range from
large international companies offering a wide range of drilling
and other oilfield services to smaller, locally owned companies.
In September 2006, we reorganized our operations into three
principal reportable segments: Offshore, Latin America Land, and
E&P Services. The realignment of our reportable segments was
attributable to implementation of a better methodology to manage
our business and organizational changes, including the hiring of
a Chief Operating Officer responsible for all of our offshore
drilling fleet. Our Offshore segment includes all of our
offshore drilling fleet and operations. Our Latin America Land
segment includes all of our land-based drilling and workover
services in Latin America. Our E&P Services segment includes
our exploration and production services business in Latin
America. All prior year information has been reclassified to
conform to the current period presentation of these three
segments. See Note 14 of our Notes to Consolidated
Financial Statements included in Item 8 of this annual
report.
In November 2006, we acquired from our joint venture partner its
70% interest in a joint venture company the principal assets of
which are two deepwater semi-submersible drilling rigs, the
Pride Portland and the Pride Rio de Janeiro. The
acquisition increased our ownership interest in the joint
venture company and the rigs from 30% to 100%. Consideration
consisted of $215 million in cash, assumed debt valued at
$284 million, and earn-out payments, if any, to be made
during the six-year period (subject to certain extensions for
non-operating periods) following the expiration of the existing
drilling contracts for the rigs. Such earn-out payments will
equal 30% of the amount, if any, by which the standard operating
dayrate, excluding bonuses, for a rig (less adjustments to
reflect certain capital additions and certain increases in
operating costs) exceeds $294,975 (or, in the case of Petrobras,
which currently contracts with a 15% bonus opportunity,
$256,500). Due to the termination of lease agreements between us
and the joint venture company and because the related operating
contracts for the Pride Portland and the Pride Rio de
Janeiro at the time of acquisition were unfavorable compared
with current market rates, we recorded a non-cash deferred
contract liability of $191.6 million to record the
difference between stated values of the non-cancelable contracts
and the current fair value of contracts with similar terms. The
deferred contract liability will be amortized to revenues over
the remaining lives of the contracts of approximately four years.
We funded the purchase price with cash on hand and borrowings
under our senior secured revolving credit facility. As a result
of the transaction, the joint venture company, which was
accounted for as an equity investment, is now consolidated in
our financial statements, resulting in the recording of
approximately $284 million of debt, net of fair value
discount, of the joint venture company to our consolidated
balance sheet. The debt, which is guaranteed by the
U.S. Maritime Administration, is more fully described under
“Liquidity and Capital Resources — Other
Outstanding Debt.”
In a related transaction, we cancelled future obligations under
certain existing agency relationships related to five offshore
rigs we operate in Brazil, including the Pride Portland
and the Pride Rio de Janeiro. For this cancellation,
we paid $15 million in cash, which we expensed during the
fourth quarter 2006.
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In November 2006, we agreed to contract terms for four of our
rigs operating offshore Brazil: the Pride Brazil, the
Pride Carlos Walter, the Pride South Atlantic, and
the Pride South America. Expected aggregate dayrate
revenues under these contracts total approximately
$2.1 billion, with approximately $200 million of
additional performance bonus opportunities. We expect to
commence operations under the new five-year contracts after the
current contract commitment for each rig is complete, beginning
with the Pride South America during the second quarter
2007, followed by the Pride South Atlantic in the second
quarter 2008 and the Pride Brazil and the Pride Carlos
Walter in the third quarter 2008. Each of these contracts
includes cost escalation provisions that commenced upon the
contract award. We also agreed to a three year contract for the
Pride North America that includes a dayrate in the
mid-$440,000s, with the third year adjusted up or down by a
maximum of 10%, according to an index of average contract
dayrates for similar rigs during the fourth quarter 2009. This
contract, which is expected to begin during the first quarter of
2008, includes cost escalation provisions that commenced upon
signing.
During the course of an internal audit and investigation
relating to certain of our Latin American operations, our
management and internal audit department received allegations of
improper payments to foreign government officials. In February
2006, shortly after and as a result of certain statements that
were made by an employee during the investigation, the Audit
Committee of our Board of Directors assumed direct
responsibility over the investigation and retained independent
outside counsel to investigate the allegations, as well as
corresponding accounting entries and internal control issues,
and to advise the Audit Committee.
The investigation, which is continuing, has found evidence
suggesting that payments, which may violate the
U.S. Foreign Corrupt Practices Act, were made to government
officials in Latin America aggregating less than
$1 million. The evidence to date regarding these payments
suggests that payments were made beginning in early 2003 through
2005 (a) to vendors with the intent that they would be
transferred to government officials for the purpose of extending
drilling contracts for two jackup rigs and one semisubmersible
rig operating offshore Venezuela; and (b) to one or more
government officials, or to vendors with the intent that they
would be transferred to government officials, for the purpose of
collecting payment for work completed in connection with
offshore drilling contracts in Venezuela. In addition, the
evidence suggests that other payments were made beginning in
2003 through early 2006 (a) to one or more government
officials in Mexico in connection with the clearing of a jackup
rig and equipment through customs or the movement of personnel
through immigration; and (b) with respect to the
potentially improper entertainment of government officials in
Mexico.
The Audit Committee, through independent outside counsel, has
undertaken a review of our compliance with the FCPA in certain
of our other international operations. This review has found
evidence suggesting that in 2004 and 2005 payments may have been
made to government officials in Saudi Arabia and Kazakhstan,
aggregating less than $175,000, in connection with clearing rigs
or equipment through customs or resolving outstanding customs
issues in those countries. The investigation of the matters
related to Saudi Arabia and Kazakhstan and the Audit
Committee’s compliance review are ongoing. Accordingly,
there can be no assurances that evidence of additional potential
FCPA violations may not be uncovered in Saudi Arabia, Kazakhstan
or other countries.
Our management and the Audit Committee of our Board of Directors
believe it likely that members of our senior operations
management either were aware, or should have been aware, that
improper payments to foreign government officials were made or
proposed to be made. Our former Chief Operating Officer resigned
as Chief Operating Officer effective on May 31, 2006 and
has elected to retire from the company, although he will remain
an employee, but not an officer, during the pendency of the
investigation to assist us with the investigation and to be
available for consultation and to answer questions relating to
our business. His retirement benefits will be subject to the
determination by our Audit Committee or our Board of Directors
that it does not have cause (as defined in his retirement
agreement with us) to terminate his employment. On
December 1, 2006, our Vice President — Western
Hemisphere Operations resigned. On December 2, 2006, our
former Country Manager in Venezuela and Mexico was terminated.
We have placed another member of our senior operations
management on administrative leave pending the outcome of the
investigation.
We voluntarily disclosed information relating to the initial
allegations and other information found in the investigation and
compliance review to the U.S. Department of Justice and the
Securities and Exchange
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Commission and are cooperating with these authorities as the
investigation and compliance reviews continue and as they review
the matter. If violations of the FCPA occurred, we could be
subject to fines, civil and criminal penalties, equitable
remedies, including profit disgorgement, and injunctive relief.
Civil penalties under the antibribery provisions of the FCPA
could range up to $10,000 per violation, with a criminal
fine up to the greater of $2 million per violation or twice
the gross pecuniary gain to us or twice the gross pecuniary loss
to others, if larger. Civil penalties under the accounting
provisions of the FCPA can range up to $500,000 and a company
that knowingly commits a violation can be fined up to
$25 million. In addition, both the SEC and the DOJ could
assert that conduct extending over a period of time may
constitute multiple violations for purposes of assessing the
penalty amounts. Often, dispositions for these types of matters
result in modifications to business practices and compliance
programs and possibly a monitor being appointed to review future
business and practices with the goal of ensuring compliance with
the FCPA.
We could also face fines, sanctions and other penalties from
authorities in the relevant foreign jurisdictions, including
prohibition of our participating in or curtailment of business
operations in those jurisdictions. Our customers in those
jurisdictions could seek to impose penalties or take other
actions adverse to our interests. In addition, disclosure of the
subject matter of the investigation could adversely affect our
reputation and our ability to obtain new business or retain
existing business from our current clients and potential
clients, to attract and retain employees and to access the
capital markets. No amounts have been accrued related to any
potential fines, sanctions or other penalties.
We have taken and will continue to take disciplinary actions
where appropriate and various other corrective action to
reinforce our commitment to conducting our business ethically
and legally and to instill in our employees our expectation that
they uphold the highest levels of honesty, integrity, ethical
standards and compliance with the law. These actions continue a
process we had previously commenced. Since late 2003, we have
created and filled a legal and ethical compliance function under
the supervision of our Senior Vice President, General Counsel
and Secretary. We have established an antibribery compliance
committee and enhanced our antibribery compliance procedures. We
also have developed in-person and online training programs to
provide annual instruction on our Code of Business Conduct and
Ethical Practices, the FCPA, antitrust law and other key
policies as part of our commitment to educate our international
workforce.
In 2006, we also (1) continued to enhance our training of
management, including our operations managers, to emphasize
further the importance of setting the proper tone within their
organization to instill an attitude of integrity and control
awareness and the use of a thorough and proper analysis of
proposed transactions; (2) determined that our
bonus-eligible employees complete in-person and online training
on the FCPA and our Code of Business Conduct and Ethical
Practices as a prerequisite to receiving their bonuses for 2006;
(3) required our management, including our operations
managers, to reconfirm that they are not aware of any violations
of law and confirm with greater specificity that they are not
aware of any improper payments to foreign government officials
made by us or on our behalf or any other violation of our Code
of Business Conduct and Ethical Practices and to recertify their
commitment to the Code; (4) established an executive
compliance committee, consisting of our executive officers and
other management-level employees who are responsible for
supervising our antibribery compliance committee, our internal
controls steering committee and our compliance efforts in
general; and (5) established a separate position of, and
appointed, a chief compliance officer.
We cannot currently predict what, if any, actions may be taken
by the DOJ, the SEC, the applicable government or other
authorities or our customers or the effect the actions may have
on our results of operations, financial condition or cash flows,
on our consolidated financial statements or on our business in
the countries at issue and other jurisdictions.
For the years ended December 31, 2006, 2005 and 2004, our
operations in Venezuela provided revenues of approximately
$156.9 million, $172.6 million, and
$167.1 million, or approximately 6.3%, 8.5% and 9.8% of our
total consolidated revenues, respectively. Our Venezuela
operations provided earnings (loss) from operations of
approximately $6.9 million, $16.8 million, and
$(6.7) million or approximately 1.3%, 5.2% and (2.7)% of
our total consolidated earnings from operations for 2006, 2005
and 2004, respectively. As of December 31, 2006 and 2005,
we had accounts receivable from Petróleos de
Venezuela, S.A. totaling $27.6 million and
$33.4 million, respectively.
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We provide contract drilling services to major integrated,
government-owned and independent oil and natural gas companies
throughout the world. Our offshore drilling fleet competes on a
global basis, as offshore rigs generally are highly mobile and
may be moved from one region to another in response to demand.
Our land-based fleet generally competes on a regional basis.
While the cost of moving a rig and the availability of
rig-moving vessels may cause the supply and demand balance to
vary somewhat between regions, significant variations between
regions do not tend to persist long-term because of rig
mobility. Pricing is often the primary factor in determining
which qualified contractor is awarded a job. Rig availability
and each contractor’s safety performance record and
reputation for quality also can be key factors in the
determination. Substantially all of our drilling contracts with
major customers are on a dayrate basis, where we charge the
customer a fixed amount per day regardless of the number of days
needed to drill the well. We provide the rigs and drilling crews
and are responsible for the payment of operating and maintenance
expenses. Our customer bears the economic risk relative to the
success of the wells.
The markets for our drilling, workover and related E&P
services are highly cyclical. Our operating results are
significantly impacted by the level of energy industry spending
for the exploration and development of oil and natural gas
reserves. Oil and natural gas companies’ exploration and
development drilling programs drive the demand for drilling and
related services. These drilling programs are affected by oil
and natural gas companies’ expectations about oil and
natural gas prices, anticipated production levels, demand for
crude oil and natural gas products, government regulations and
many other factors. Oil and natural gas prices are volatile,
which has historically led to significant fluctuations in
expenditures by our customers for oil and natural gas drilling
and related services. Variations in market conditions during the
cycle impact us in different ways depending primarily on the
length of drilling contracts in different regions. Contracts in
the U.S. Gulf of Mexico, for example, tend to be
short-term, so a deterioration or improvement in market
conditions tends to impact our operations quickly. Contracts in
international offshore markets tend to be longer term due to rig
availability, mobilization costs and technical requirements.
Accordingly, short-term changes in market conditions in these
markets may have little or no short-term impact on our revenues
and cash flows from those operations unless the market changes
occur during a period when we are attempting to renew a number
of those contracts.
Our revenues depend principally upon the number of our available
rigs, the number of days these rigs are utilized and the
contract day rates received. The number of days our rigs are
utilized and the contract day rates received are largely
dependent upon the balance of supply and demand for drilling and
related services in the different geographic regions in which we
operate. The number of available rigs may increase or decrease
as a result of the acquisition, relocation or disposal of rigs,
the construction of new rigs and the number of rigs being
upgraded or repaired or undergoing periodic surveys or routine
maintenance at any time. In order to improve utilization or
realize higher contract day rates, we may mobilize our rigs from
one geographic region to another for which we may receive a
mobilization fee. Mobilization fees are deferred and recognized
as revenue over the term of the contract.
Changes in earnings from operations are primarily affected by
revenues, cost of labor and utilization of our drilling fleet.
For instance, if a rig is expected to be idle for an extended
period of time, we may reduce the size of the rig’s crew
and take steps to “cold stack” the rig, which reduces
expenses and partially offsets the impact on operating income
associated with the loss of revenues.
Our operations and activities are subject to numerous
environmental laws and regulations, including the U.S. Oil
Pollution Act of 1990, the U.S. Outer Continental Shelf
Lands Act, the Comprehensive Environmental Response,
Compensation and Liability Act and the International Convention
for the Prevention of Pollution from Ships. Additionally, other
countries where we operate have similar laws and regulations
covering the discharge of oil and other contaminants in
connection with drilling operations.
Expectations about future oil prices have historically been a
key driver for drilling demand; however, the availability of
quality drilling prospects, exploration success, relative
production costs, the stage of reservoir development and
political and regulatory environments also affect our
customers’ drilling programs. We expect
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global demand for contract drilling services to continue to
increase, driven by increasing worldwide energy demand and
demand for oil and natural gas and an increased focus by oil and
natural gas companies on offshore prospects.
Our deepwater fleet, which consists of our drillships and our
semisubmersibles operating in water depths greater than
4,500 feet, currently operates in West Africa, Brazil and
Egypt, and is fully contracted through June 2009, with most of
our fleet contracted into 2010. In November 2006, we were
awarded five-year contract extensions beginning in 2008 for the
Pride Brazil and Pride Carlos Walter and a
three-year contract extension for the Pride North America,
each at substantially higher dayrates. We have contracted
the Pride South Pacific under a two-year contract at a
dayrate three times the prior contract rate beginning in March
2007. The balance of our deepwater fleet is contracted through
2007 and our average dayrate is not expected to change
materially, other than as a result of cost escalation
protection, until contract rollovers occur. We believe that
long-term market conditions for deepwater drilling services are
favorable and that demand for deepwater rigs will continue to
exceed supply for the next several years. We believe that
favorable commodity prices for oil, geological successes in
exploratory markets and, in general, more favorable political
conditions will continue to encourage the development of new
projects by exploration and production companies on a number of
major discoveries. In addition, we believe that the need for
deepwater rigs will continue to grow for existing offshore
development projects in West Africa, the Gulf of Mexico and
Brazil.
Prospects for our midwater fleet, which consists of our
semisubmersibles operating in water depths from 1,000 feet
to 4,500 feet and which currently operates in West Africa,
Brazil, the Mediterranean Sea and Mexico, continue to be robust
with approximately 83% of our fleet contracted through the end
of 2007. At present, increasing demand and limited availability
of rigs continues to drive dayrates higher. Contracts for
midwater rigs tend to be shorter in duration than deepwater rigs
with one to three years as the typical length. We believe
increasing demand, a limited ability to increase rig supply in
the short term and excess demand for rigs will result in
favorable market conditions through 2008. We contracted the
Pride South America at a substantially higher dayrate for
a five-year term that began in February 2007. The Pride South
Seas and Pride South Atlantic will rollover to new
contracts at higher dayrates in 2007. We expect our average
dayrates for our midwater fleet to continue to improve due to
repricing of our fleet in 2007 and 2008. During 2007, three of
our rigs are scheduled to be
out-of-service
for scheduled regulatory inspection and maintenance.
We expect the outlook for the international jackup market to
continue to remain strong due to the current jackup rig supply
shortage. Demand for jackup rigs in international markets
continues to be strong and average dayrates remain high with
longer term contracts. However, we continue to monitor the
potential effect of the addition of approximately 65 newbuild
jackups to the global market, which have scheduled delivery
dates from 2007 through 2010. The addition of rig capacity to
the market could have an adverse impact on our utilization and
dayrates, particularly in international markets. The dayrate
environment in the U.S. Gulf of Mexico has been under
pressure from lower demand and uncertain natural gas prices due
to high storage levels. We anticipate that the market may
strengthen in the second half of 2007 as several rigs owned by
our competitors are expected to leave the Gulf of Mexico for
international markets and the demand for additional rigs by
PEMEX and other international clients is expected to increase.
Improvement in dayrates in 2007 will largely depend upon natural
gas prices and any impact of the 2007 hurricane season on our
customers’ drilling programs. The Pride Tennessee
completed its shipyard upgrade in February 2007 and is
contracted through July 2009. We have 12 rigs currently
scheduled for maintenance and upgrade projects in 2007, as
compared to 10 rigs that were out of service for maintenance and
upgrade projects in 2006. Following the completion of these
projects, we expect the number of projects to decline
significantly in 2008. The ability to complete the projects on a
timely basis could have a significant impact on 2007 results.
We experienced high levels of activity for our Latin America
Land and E&P Services operations, which resulted in higher
pricing and utilization. The market outlook for Argentina and
Colombia remains favorable as economic growth has stimulated
demand for oil and natural gas. We currently believe that market
conditions in Venezuela will permit us to recover the additional
cost associated with recently enacted social programs and do not
believe our operations will be materially impacted.
In October 2006, we experienced a
two-day
strike against our Latin America Land operation in northern
Argentina, which temporarily idled approximately 70 of our rigs.
During the fourth quarter 2006, our operations in
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Argentina experienced additional work stoppages on both local
and national levels organized by the unions in protest of
various labor and tax laws. The issues were resolved with the
unions in December 2006. We believe our relationships with the
unions are good and we are not currently aware of any threatened
or pending work stoppages. However, industry conditions and
changes in the political environments in which we operate have,
from time to time, resulted in work stoppages. Such work
stoppages may occur in the future and may have a significant
impact on our future operations or financial position.
We are actively pursuing options for maximizing the value of our
Latin America Land and E&P Services operations. All options
are being considered, including sales to strategic buyers and
capital market alternatives. We may ultimately decide to pursue
a course of action other than a disposition of these operations;
however, if we do pursue a disposition, we may be unable to
complete a transaction on terms we find acceptable or at all.
Increased activity in the oilfield services industry is
increasing competition for experienced oilfield workers
resulting in higher labor costs and training costs. The
increased activity has also increased demand for oilfield
equipment and spare parts and coupled with the consolidation of
equipment suppliers, has resulted in longer order lead times to
obtain critical spares and higher repair and maintenance costs
and increased
out-of-service
time for repair and upgrade projects. A number of our rigs will
be in the shipyard or undergoing repairs during 2007 and may be
subject to repair delays. In addition, as a result of the
significant insurance losses incurred by the drilling industry
during the 2004 and 2005 hurricane seasons, our insurance costs
increased significantly when our policies renewed in July 2006.
Our insurance underwriters have also imposed an aggregate limit
of approximately $85.0 million for damage due to named wind
storms in the U.S. Gulf of Mexico, with a
$10.0 million deductible per named wind storm. However, due
to higher dayrates, we expect our growth in revenues to continue
to outpace our cost increases throughout 2007.
Critical
Accounting Estimates
The preparation of our consolidated financial statements
requires us to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses
and related disclosures about contingent assets and liabilities.
We base these estimates and assumptions on historical experience
and on various other information and assumptions that are
believed to be reasonable under the circumstances. Estimates and
assumptions about future events and their effects cannot be
perceived with certainty and, accordingly, these estimates may
change as additional information is obtained, as more experience
is acquired, as our operating environment changes and as new
events occur.
Our critical accounting estimates are important to the portrayal
of both our financial condition and results of operations and
require us to make difficult, subjective or complex assumptions
or estimates about matters that are uncertain. We would report
different amounts in our consolidated financial statements,
which could be material, if we used different assumptions or
estimates. We have discussed the development and selection of
our critical accounting estimates with the Audit Committee of
our Board of Directors and the Audit Committee has reviewed the
disclosure presented below. During the past three fiscal years,
we have not made any material changes in accounting methodology
used to establish the critical accounting estimates for property
and equipment, income taxes and contingent liabilities discussed
below; however, as previously disclosed, we made a material
change in accounting methodology used to establish the critical
accounting estimates for certain interest rate swap and cap
agreements.
We believe that the following are the critical accounting
estimates used in the preparation of our consolidated financial
statements. In addition, there are other items within our
consolidated financial statements that require estimation.
Property and equipment comprise a significant amount of our
total assets. We determine the carrying value of these assets
based on property and equipment policies that incorporate our
estimates, assumptions and judgments relative to the carrying
value, remaining useful lives and salvage value of our rigs.
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We depreciate our property and equipment over their estimated
useful lives using the straight-line method. The assumptions and
judgments we use in determining the estimated useful lives of
our rigs reflect both historical experience and expectations
regarding future operations, utilization and performance. The
use of different estimates, assumptions and judgments in the
establishment of estimated useful lives, especially those
involving our rigs, would likely result in materially different
net book values of our property and equipment and results of
operations.
Useful lives of rigs and related equipment are difficult to
estimate due to a variety of factors, including technological
advances that impact the methods or cost of oil and natural gas
exploration and development, changes in market or economic
conditions and changes in laws or regulations affecting the
drilling industry. We evaluate the remaining useful lives of our
rigs when certain events occur that directly impact our
assessment of the remaining useful lives of the rig and include
changes in operating condition, functional capability and market
and economic factors. We also consider major capital upgrades
required to perform certain contracts and the long-term impact
of those upgrades on the future marketability when assessing the
useful lives of individual rigs.
We review our property and equipment for impairment whenever
events or changes in circumstances indicate the carrying value
of such assets or asset groups may not be recoverable.
Indicators of possible impairment include extended periods of
idle time
and/or an
inability to contract specific assets or groups of assets, such
as a specific type of drilling rig, or assets in a specific
geographical region. However, the drilling, workover and related
service industries in which we operate are highly cyclical and
it is not unusual to find that assets that were idle,
under-utilized or contracted at
sub-economic
rates for significant periods of time resume activity at
economic rates when market conditions improve. Additionally,
most of our assets are mobile, and we may mobilize rigs from one
market to another to improve utilization or realize higher
dayrates.
Asset impairment evaluations are based on estimated future
undiscounted cash flows of the assets being evaluated to
determine the recoverability of carrying amounts. In general,
analyses are based on expected costs, utilization and dayrates
for the estimated remaining useful lives of the asset or group
of assets being assessed. An impairment loss is recorded in the
period in which it is determined that the aggregate carrying
amount is not recoverable.
Asset impairment evaluations are, by nature, highly subjective.
They involve expectations about future cash flows generated by
our assets, and reflect management’s assumptions and
judgments regarding future industry conditions and their effect
on future utilization levels, dayrates and costs. The use of
different estimates and assumptions could result in materially
different carrying values of our assets and could materially
affect our results of operations.
Our income tax expense is based on our income, statutory tax
rates and tax planning opportunities available to us in the
various jurisdictions in which we operate. We provide for income
taxes based on the tax laws and rates in effect in the countries
in which operations are conducted and income is earned. The
income tax rates and methods of computing taxable income vary
substantially in each jurisdiction. Our income tax expense is
expected to fluctuate from year to year as our operations are
conducted in different taxing jurisdictions and the amount of
pre-tax income fluctuates.
The determination and evaluation of our annual income tax
provision involves the interpretation of tax laws in various
jurisdictions in which we operate and requires significant
judgment and the use of estimates and assumptions regarding
significant future events such as the amount, timing and
character of income, deductions and tax credits. Changes in tax
laws, regulations, agreements, treaties, foreign currency
exchange restrictions or our levels of operations or
profitability in each jurisdiction may impact our tax liability
in any given year. While our annual tax provision is based on
the information available to us at the time, a number of years
may elapse before the ultimate tax liabilities in certain tax
jurisdictions are determined.
Current income tax expense reflects an estimate of our income
tax liability for the current year, withholding taxes, changes
in prior year tax estimates as returns are filed, or from tax
audit adjustments. Our deferred tax expense or benefit
represents the change in the balance of deferred tax assets or
liabilities as reflected on the balance sheet. Valuation
allowances are determined to reduce deferred tax assets when it
is more likely than not that some
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portion or all of the deferred tax assets will not be realized.
To determine the amount of deferred tax assets and liabilities,
as well as of the valuation allowances, we must make estimates
and certain assumptions regarding future taxable income,
including where the rigs are expected to be deployed, as well as
other assumptions related to our future tax position. A change
in such estimates and assumptions, along with any changes in tax
laws, could require us to adjust the deferred tax assets,
liabilities, or valuation allowances as discussed below.
As of December 31, 2006, we have U.S. net operating loss
(“NOL”) carryforwards. Due to our acquisition of
Marine Drilling Companies in September 2001, certain NOL
carryforwards are subject to limitations under Sections 382 and
383 of the U.S. Internal Revenue Code. The U.S. NOL
carryforwards could expire starting in 2020 through 2024. We
have foreign NOL carryforwards and we have recognized a
valuation allowance on substantially all of these foreign NOL
carryforwards. Certain foreign NOL carryforwards do not expire
and some could expire starting in 2007 through 2016.
We have not provided for U.S. deferred taxes on the
unremitted earnings of our foreign controlled subsidiaries that
are permanently reinvested. If a distribution is made to us from
the unremitted earnings of these subsidiaries, we could be
required to record additional taxes. Because we cannot predict
when, if at all, we will make a distribution of these unremitted
earnings, we are unable to make a determination of the amount of
unrecognized deferred tax liability.
As required by law, we file periodic tax returns that are
subject to review and examination by various tax authorities
within the jurisdictions in which we operate. We are currently
contesting several tax assessments and may contest future
assessments where we believe the assessments are in error. We
cannot predict or provide assurance as to the ultimate outcome
of existing or future tax assessments; however, we believe the
ultimate resolution of outstanding tax assessments will not have
a material adverse effect on our consolidated financial
statements.
In July 2006, we received tax assessments from the Mexican
government related to our operations for the tax years 2002 and
2003. These assessments contest our right to claim certain
deductions in our tax returns for those years. We anticipate
that the Mexican government will make additional assessments
contesting similar deductions for other tax years. While we
intend to contest these assessments vigorously, we cannot
predict or provide assurance as to the ultimate outcome, which
may take several years. However, we do not believe that the
ultimate outcome of these assessments will have a material
impact on our consolidated financial statements. As required by
local statutory requirements, we have provided standby letters
of credit, which totaled $41.3 million as of
December 31, 2006, to contest these assessments.
We do not believe that it is possible to reasonably estimate the
potential impact of changes to the assumptions and estimates
identified because the resulting change to our tax liability, if
any, is dependent on numerous factors which cannot be reasonably
estimated. These include, among other things, the amount and
nature of additional taxes potentially asserted by local tax
authorities; the willingness of local tax authorities to
negotiate a fair settlement through an administrative process;
the impartiality of the local courts; and the potential for
changes in the tax paid to one country to either produce, or
fail to produce, an offsetting tax change in other countries.
Our experience has been that the estimates and assumptions we
have used to provide for future tax assessments have been
appropriate; however, past experience is only a guide and the
tax resulting from the resolution of current and potential
future tax controversies may have a material adverse effect on
our consolidated financial statements.
We establish reserves for estimated loss contingencies when we
believe a loss is probable and the amount of the loss can be
reasonably estimated. Our contingent liability reserves relate
primarily to litigation, personal injury claims and potential
tax assessments (see “Income Taxes” above). Revisions
to contingent liability reserves are reflected in income in the
period in which different facts or information become known or
circumstances change that affect our previous assumptions with
respect to the likelihood or amount of loss. Reserves for
contingent liabilities are based upon our assumptions and
estimates regarding the probable outcome of the matter. Should
the outcome differ from our assumptions and estimates or other
events result in a material adjustment to the accrued estimated
reserves, revisions to the estimated reserves for contingent
liabilities would be required and would be recognized in the
period the new information becomes known.
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We currently use derivatives in the normal course of business to
manage our exposure to fluctuations in interest rates. We have
not designated our interest rate swap and cap agreements as
hedging instruments in accordance with Statement of Financial
Accounting Standards (“SFAS”) No. 133,
Accounting for Derivative Instruments and Hedging
Activities. Accordingly, we must determine the fair value of
these agreements and record any changes to the fair value in our
consolidated statements of operations. The determination of the
fair value is complex and requires significant judgments and
estimates, including the methodology of building a forward yield
curve, the basis of discounting projected future cash flows and
varying conventions in contract terms. The use of different
estimates and assumptions could result in materially different
fair values and could materially affect our results of
operations.
Segment
Review
In September 2006, based upon changes within our management
organization, we changed the composition of our segments to
three principal reportable segments: Offshore, which comprises
our offshore drilling activity, currently in Africa, the
Mediterranean Sea, the Middle East, Southeast Asia, South
America and the Gulf of Mexico; Latin America Land, which
comprises our land-based drilling and workover services in Latin
America, currently in Argentina, Venezuela, Colombia, Bolivia,
and Mexico; and E&P Services, which includes exploration and
production services in Latin America. “Other” includes
revenues and cost for land-based drilling and workover
operations outside of Latin America (currently Chad, Kazakhstan
and Pakistan), labor contracts and engineering and management
consulting services.
The following table presents selected consolidated financial
information by reporting segment:
Offshore
We have provided below additional information based on the
service capabilities of our offshore fleet. We consider our
drillships and our semisubmersible rigs operating in water
depths greater than 4,500 feet as deepwater and our
semisubmersible rigs operating in water depths from
1,000 feet to 4,500 feet as midwater. Our jackups
operate in water depths up to 300 feet. As of
February 28, 2007, our Offshore segment comprised two
deepwater drillships, 12 semisubmersible rigs, 28 jackup rigs,
10 platform rigs, three tender-assisted rigs, three barge rigs,
and
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five deepwater rigs managed for other parties. The following
table summarizes our revenue and earnings from operations by
type of offshore rig in our fleet:
The following table summarizes our average daily revenues and
percentage utilization by type of offshore rig in our fleet:
Revenues increased $120.3 million, or 33%, for the year
ended December 31, 2006 over the comparable period in 2005.
The increase is due to a 24% increase in actual days worked in
2006 as compared to 2005 primarily due to a full year of
operations in 2006 and $8.0 million related to the
amortization of deferred contract liabilities for the Pride
Portland and the Pride Rio de Janeiro, increased
dayrates for the Pride North America, and contractual
rate escalations. Average daily revenues for the year ended
December 31, 2006 increased 8% over the comparable period
in 2005 due to contracted dayrate increases for the Pride
North America and moderate contractual dayrate escalations
in 2006 for several of our deepwater rigs. Earnings from
operations increased $26.2 million, or 25%, for the year
ended December 31, 2006 over the comparable period in 2005
due to an increase in revenues partially offset by charges in
2006 for settlement of agency relationships on four of the rigs.
The Pride South Pacific, working offshore West Africa, is
to begin a new contract at substantially higher rates following
the completion of its current contract currently scheduled for
April 2007. After completion of repairs to the subsea control
system, the Pride North America began operating offshore
Egypt in late April 2006 under a contract that expires in
January 2008. In October 2006, the Pride North America
sustained crane damage as a result of new equipment failure;
repairs were completed during the fourth quarter of 2006. The
Pride Carlos Walter was in the shipyard for its special
periodic survey in the fourth quarter of 2006. In November 2006,
the Pride Brazil and Pride Carlos Walter were
awarded contract extensions beginning in mid-2008 through 2013
at dayrates approximately 80% higher than current rates.
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Utilization remains high, as our deepwater fleet is fully
contracted through June 2009. Much of our deepwater fleet is
contracted until mid-2010; as a result, we would benefit from
increasing dayrates for deepwater rigs only when our fleet is
able to rollover to new contract terms.
Revenues increased $43.9 million, or 14%, for the year
ended December 31, 2005 over the comparable period in 2004.
The increase is due to $47.6 million of revenue from the
Pride Portland and the Pride Rio de Janeiro, which
commenced operations in April 2005 and October 2005,
respectively. Revenues and utilization were impacted by special
periodic surveys in 2005 for the Pride Angola and
Pride South Pacific, lower dayrates for the Pride
North America in 2005 and its mobilization in the fourth
quarter of 2005. Average daily revenues for the year ended
December 31, 2005 increased 7% over the comparable period
in 2004 primarily due to contracted dayrate increases for the
Pride South Pacific. Earnings from operations decreased
$16.4 million, or 14%, for the year ended December 31,
2005 over the comparable period in 2004 due to lower revenues
for the Pride North America and a 9% increase in
year-over-year operating costs.
Revenues increased $28.3 million, or 18%, for the year
ended December 31, 2006 over the comparable period in 2005.
The increase is due to higher dayrates for several rigs
partially offset by a 4% decline in actual days worked. Average
daily revenue for the year ended December 31, 2006
increased 23% over 2005 as a result of the Pride Venezuela
rolling over to a market rate contract, contract escalations
and performance bonuses earned. Earnings from operations
increased $20.4 million, or 210%, for the year ended
December 31, 2006 over the comparable period in 2005
primarily due to higher dayrates and lower mobilization and
repairs and maintenance costs for the Pride Venezuela.
The Pride South America began working under a new
contract in February 2007 at substantially higher dayrates. The
Pride South Seas, which was operating offshore South
Africa under a contract that expired in February 2007, is being
mobilized to Namibia for work under a contract with an initial
term expiring in July 2007 at substantially increased dayrates.
After completion of its special periodic survey, the Pride
North Sea began working in April 2006 on a series of
contracts, with options, in the Mediterranean Sea, which are
expected to be completed by
mid-to-late
2007. The Pride Venezuela completed its special periodic
survey and upgrades in September 2006 and was mobilized to West
Africa for an
18-month
contract, with a six month option, at substantially higher
dayrates. The Pride South Atlantic completed its life
enhancement project and is working through February 2008 under
contracts with various customers at substantially higher
dayrates than in 2005.
Revenues increased $28.7 million, or 23%, for the year
ended December 31, 2005 over the comparable period in 2004.
The increase is due primarily to increased utilization of the
Pride Venezuela partially offset by a decrease in
utilization of the Pride South Seas. Average daily
revenues for the year ended December 31, 2005 increased 14%
over the comparable period in 2004 primarily due to the
contracted dayrate increases for the Pride South Seas and
Pride South Atlantic. Earnings from operations increased
$2.9 million, or 43%, for the year ended December 31,
2005 over the comparable period in 2004 due to higher average
daily revenues and utilization.
Revenues increased $233.6 million, or 52%, for the year
ended December 31, 2006 over the comparable period in 2005.
The increase is due to higher dayrates partially offset by a
decline in utilization. Average daily revenue for our jackup
fleet for year ended December 31, 2006 increased 70% over
2005. Earnings from operations increased $184.4 million, or
123%, for the year ended December 31, 2006 over the
comparable period in 2005 due to the increase in average daily
revenue. Our jackup fleet has benefited from escalating dayrates
due to strong worldwide drilling demand. Contracts for our
U.S. Gulf of Mexico fleet tend to be for shorter periods as
compared to international jackup contracts and, in certain
cases, are indexed to market. The Pride Hawaii began
working under a contract with significantly higher dayrates in
November 2006. After completing contracts in Southeast Asia that
expired in January 2007 and its special periodic survey, the rig
is to be mobilized to India to operate under a contract that
expires in April 2010. The Pride California and Pride
Nevada completed their life enhancement projects and began
working under contracts in September 2006 and October 2006,
respectively, at substantially higher rates. In November 2006,
the Pride Oklahoma completed its life enhancement project
and commenced a two well contract with an option for an
additional well. The Pride Arkansas completed its
maintenance projects and began a two-year contract with a
dayrate similar to its previous contract. The Pride New
Mexico entered the shipyard near the end of
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the third quarter, is currently undergoing survey and assessment
and is expected to remain in the shipyard until the second
quarter of 2007. A total of 12 jackups are scheduled for planned
maintenance and regulatory inspection projects in 2007.
Revenues increased $49.1 million, or 12%, for the year
ended December 31, 2005 over the comparable period in 2004.
The increase is due primarily to increased dayrates and
utilization for our fleet in the U.S. Gulf of Mexico,
partially offset by the loss of revenues from rigs sold in 2004
and 2005, principally the Pride West Virginia and
Pride Ohio. Average daily revenues for the
year ended December 31, 2005 increased 16% over the
comparable period in 2004 due to contracted dayrate increases in
the U.S. Gulf of Mexico fleet and the Pride California
and Pride Texas in Mexico; international fleet
dayrates remained flat. Earnings from operations increased
$5.2 million, or 4%, for the year ended December 31,
2005 over the comparable period in 2004 primarily due to higher
average daily revenues and utilization for the U.S. Gulf of
Mexico fleet partially offset by the loss of earnings from rigs
sold in 2005 and 2004.
Revenues decreased $48.3 million, or 16%, for the year
ended December 31, 2006 over the comparable period in 2005.
Revenues decreased due to the termination of management
agreements for GP19 and GP20 in 2006 and the sale of two tender
barges in 2005. Average daily revenue for our tender-assisted
barges and other offshore assets for the year ended
December 31, 2006 increased 5% over 2005. The increase in
average daily revenue is primarily due to the contracting of the
Barracuda. Earnings from operations decreased
$22.9 million, or 68%, due to the sale of the tender barges
in 2005 and lower utilization of the Bintang
Kalimantan. The Alligator, Pride Ivory Coast
and Barracuda are currently working in West Africa
under contracts that expire in June 2007, August 2007 and
December 2007, respectively. The Bintang Kalimantan
completed its contract in March 2006 and is currently stacked.
The Pride I and Pride II lake barges in
Venezuela are operating on a
well-to-well
basis. Platform rigs 1002E, 1003E and 1005E are operating in
Mexico under contracts that expire in mid-2007. Two of our
platform rigs are working in the U.S. Gulf of Mexico under
short-term or
well-to-well
contracts. We also provide drilling management services for five
deepwater platform drilling rigs, consisting of two tension leg
platforms, two spar units and a semisubmersible rig, under
management contracts that expire from 2008 to 2010.
Revenues increased $65.1 million, or 28%, for the year
ended December 31, 2005 over the comparable period in 2004.
The increase is due primarily to $47.8 million in increased
revenues from (1) additional management contract revenues,
including the Kizomba B contract commencing in 2005, the
Holstein and Mad Dog contracts commencing in 2004
and the Thunderhorse contract commencing in 2005, and
(2) higher utilization of the Pride Ivory Coast,
which was idle in 2004. Average daily revenues for the year
ended December 31, 2005 increased 24% over the comparable
period in 2004 primarily due to the 2005 sales of the tender
barges, which had lower than average dayrates. Earnings from
operations increased $12.7 million, or 61%, for the year
ended December 31, 2005 over the comparable period in 2004
due to earnings from the new management contracts, a
$3.8 million gain on asset sales in 2005 and a
$3.5 million impairment charge in 2004.
As of February 28, 2007, our Latin America Land segment
comprised 206 land drilling and workover rigs, of which 94%
were contracted. The following table summarizes our average
daily revenues and the number of days worked by type rig in our
Latin America Land fleet:
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Revenues increased $113.1 million, or 23%, for the year
ended December 31, 2006 over the comparable period in 2005.
Average daily revenues for our Latin America Land drilling fleet
for the year ended December 31, 2006 increased by
approximately 21% over 2005. The increase in revenues and
average daily revenues is due to strong dayrate increases in
Argentina, Colombia and Venezuela and the disposition of the
drilling rigs in Brazil in March 2006, which operated at
substantially lower daily rates. The average daily revenue for
the 2006 period was negatively impacted by three of our drilling
rigs in Bolivia being idled following the government’s
decision to nationalize the country’s oil and natural gas
reserves. We currently anticipate that these rigs will return to
work by the end of the first quarter of 2007. In September 2006,
we completed the mobilization of a land rig in Kazakhstan to
Colombia, where it began a three-year contract in the fourth
quarter 2006. The contract is at a rate substantially above our
current average daily rate in Latin America, and we recovered
the costs of mobilizing the rig in a lump-sum payment from our
customer. Average daily revenue for our Latin America Land
workover fleet for the year ended December 31, 2006
increased by approximately 24% over 2005. The increase is due to
strong daily rate increases in Argentina and Colombia with
moderate daily rate increases in Venezuela. The number of days
worked and the average daily revenue fluctuate for the workover
rigs from period to period based on the location and nature of
the wells being worked.
Earnings from operations for our Latin America Land segment
increased $47.8 million, or 73%, for the year ended
December 31, 2006 over the comparable period in 2005
primarily due to higher dayrates earned in Argentina and
Colombia partially offset by higher operating costs in Venezuela.
Revenues increased $105.4 million, or 27%, for the year
ended December 31, 2005 over the comparable period in 2004.
Average daily revenues for our Latin America Land drilling fleet
for the year ended December 31, 2005 increased by
approximately 27% over 2004. The increase in revenues is due to
increased utilization in Colombia and an increase in dayrates in
Argentina, which resulted in higher average daily revenues.
Average daily revenue for our Latin America Land workover fleet
for the year ended December 31, 2005 increased by
approximately 14% over 2004. The increase is due to higher
dayrates in Argentina and Colombia. The decline in days worked
from 2004 to 2005 is attributable to lower utilization in
Venezuela partially offset by higher utilization in Colombia.
Earnings from operations for our Latin America Land segment
increased $59.3 million for the year ended
December 31, 2005 from $5.8 million over the
comparable period in 2004 primarily due to higher dayrates
earned in Argentina and an overall increase in business activity
in Colombia. In addition, we recorded a $16.8 million
charge in 2004 for the impairment of certain rigs and equipment.
We currently provide E&P services in Argentina, Bolivia,
Brazil, Ecuador, Peru and Venezuela, consisting primarily of
pressure pumping services, integrated services and other
exploration and production services.
Revenue of our E&P Services segment for the year ended
December 31, 2006 increased $7.5 million, or 4%, over
2005 primarily due to increased revenue from pressure pumping
and integrated services in Argentina and directional drilling in
Brazil partially offset by downtime resulting from mobilizing
equipment between markets. In the first quarter 2006, we moved
our E&P Services equipment located in Colombia to Venezuela
and Argentina to concentrate on areas with higher margin
business. Earnings from operations increased $6.2 million,
or 30%, for the year ended December 31, 2006 over the
comparable period in 2005 primarily due to increased revenues in
Argentina.
Revenue of our E&P Services segment for the year ended
December 31, 2005 increased $32.8 million, or 21%,
over 2004 primarily due to increased revenue from pressure
pumping and integrated services in Argentina and directional
drilling in Brazil. Earnings from operations increased
$5.7 million, or 38%, for the year ended December 31,
2005 over the comparable period in 2004 primarily due to
increased revenues in Argentina and Brazil.
Discontinued
Operations
The operations of the Technical Services group were concentrated
on completing the final of four rigs pursuant to fixed-fee
contracts to design, engineer, manage construction of and
commission specialized drilling rigs for two
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of our significant customers. The first rig was completed and
delivered in 2003, and the other three rigs were completed and
delivered in 2004.
We experienced significant cost overruns on these projects, and
the total costs on each of the four projects substantially
exceeded contract revenues. We do not currently intend to enter
into additional business of this nature. Accordingly, we have
reported our fixed-fee rig construction business as discontinued
operations in our results of operations. See Note 12 of our
Notes to Consolidated Financial Statements in Item 8 of
this annual report for additional information regarding
discontinued operations.
Results
of Operations
The discussion below relating to significant line items
represents our analysis of significant changes or events that
impact the comparability of reported amounts. Where appropriate,
we have identified specific events and changes that affect
comparability or trends and, where possible and practical, have
quantified the impact of such items. Except to the extent that
differences between operating segments are material to an
understanding of our business taken as a whole, the discussion
below is based on our consolidated financial results.
The following table presents selected consolidated financial
information:
Revenues. Revenues for 2006 increased
$462.1 million, or 22.7%, compared with 2005. Offshore
revenues increased $333.9 million due to overall higher
average daily revenues, particularly with respect to our
U.S. Gulf of Mexico jackup fleet, higher dayrates for the
Pride North America and $49.7 million of additional
revenues from the Pride Portland and the Pride Rio de
Janeiro, which commenced operations during the third and
second quarter of 2005, respectively. Latin America Land
revenues increased $113.1 million primarily due to price
increases for drilling and workover services in Argentina and
Colombia.
Operating Costs. Operating costs for 2006
increased $190.9 million, or 13.8%, compared with 2005, of
which $49.0 million is due to the operations of the
Pride Portland and the Pride Rio de Janeiro.
Offshore operating costs in 2006 include $15.0 million
related to termination of our agency agreement in Brazil. Labor
costs, rental expenses and amortization of deferred mobilization
costs were the other primary reasons for overall increases in
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operating costs. Operating costs as a percentage of revenues
were 63.3% and 68.3% for 2006 and 2005, respectively. The
decrease as a percentage of revenue was primarily driven by the
increase in dayrates.
Depreciation and Amortization. Depreciation
and amortization expense for 2006 increased $12.7 million,
or 4.9%, compared with 2005 primarily due increased capital
expenditures in 2006.
General and Administrative. General and
administrative expenses for 2006 increased $31.2 million,
or 31.9%, compared with 2005 primarily due to $20.0 million
of expenses related to the ongoing investigation described under
“— FCPA Investigation” above, an increase of
$13.8 million in compensation costs due to increased
corporate staffing and stock compensation, and approximately
$2.7 million of corporate initiatives related to our Latin
America Land and E&P Services businesses. General and
administrative expenses for 2005 include approximately
$10.8 million of severance in connection with the
termination of the employment of various key employees and the
retirement of a director.
Gain on Sale of Assets, Net. We had net gains
on sales of assets of $31.4 million in 2006 primarily due
to the sale of the Pride Rotterdam, resulting in a gain
of $25.3 million, and the sale of four land rigs. We had
net gains on sales of assets of $36.1 million in 2005
primarily due to the sale of one jackup rig, two tender-assisted
barge rigs and six land rigs.
Interest Expense. Interest expense for 2006
decreased by $9.7 million, or 11.0%, compared with 2005
primarily due to lower total debt levels resulting from the
repayment of our senior secured term loan and the conversion and
retirement of our
21/2% convertible
senior notes during 2005 described under
“— Liquidity and Capital Resources” below.
Included in 2005 are charges of $3.6 million related to the
write-off of deferred financing costs as a result of the
prepayment of our senior secured term loan.
Other Income, Net. Other income, net for 2006
decreased from $9.5 million for 2005 to $4.5 million
for 2006. The decrease was primarily due to a $5.3 million
decrease in
mark-to-market
gains and cash settlements on interest rate swap and cap
agreements.
Income Taxes. Our consolidated effective tax
rate for 2006 was 37.1% as compared with 40.5% for 2005. The
lower rate in 2006 was due to higher profitability in
jurisdictions with statutory rates lower than the United States.
Minority Interest. Minority interest in 2006
decreased $15.6 million, or 79.2%, compared with 2005
primarily due to the purchase of an additional 40% interest in
our drillship joint venture in December 2005 described under
“— Liquidity and Capital Resources” below.
Revenues. Revenues for 2005 increased
$321.1 million, or 18.8%, compared with 2004. Our
significant operating segments experienced increased revenues as
demand for drilling and related services continued to increase.
The commencement of the Pride Portland and the Pride
Rio de Janeiro in 2005 resulted in $47.6 million of
additional revenues as compared to 2004. Our jackup fleet in the
U.S. Gulf of Mexico continued to improve its revenues due
to higher revenues from managed rigs and improved dayrates and
utilization. Revenues from our Latin America Land segment
increased due to stronger demand and higher utilization and
increased pricing. Revenues increased in our E&P segment due
to increased activity in Mexico, Brazil and Venezuela and a
higher level of integrated services work in Argentina and Brazil.
Operating Costs. Operating costs for 2005
increased $241.5 million, or 21.1% compared with 2004,
primarily due to increased utilization in our Latin America Land
segment driven by stronger demand and increased activity in our
E&P services segment. Higher labor costs for oilfield
personnel also contributed to the increase in operating costs,
as the competition for experienced oilfield workers continued to
drive up wages and salaries. Operating costs as a percentage of
revenues were 68.3% and 67.0% for 2005 and 2004, respectively.
This increase results primarily from an increase in the amount
of operations performed on managed rigs, as these contracts
typically have lower operating margins.
Operating costs for the offshore fleet increased primarily due
to increased utilization of the semisubmersible fleet and
increased costs from managed platform rigs, including the
Pride Portland and the Pride Rio de Janeiro,
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which commenced operations in 2005. Operating costs for our
jackup fleet increased primarily due to higher levels of
activity.
Depreciation and Amortization. Depreciation
and amortization expense for 2005 decreased $8.1 million,
or 3.1%, compared with 2004 primarily due a decrease in the
number of rigs we own. During 2005, we sold a jackup rig, two
tender-assisted barge rigs and six land rigs.
General and Administrative. General and
administrative expenses for 2005 increased $22.9 million,
or 30.6%, compared with 2004. The increase was primarily due to
charges of $10.8 million related to severance in connection
with the termination of the employment of various key employees
and the retirement of a director, increased audit and
professional fees and increased compensation costs due to
increased staffing.
Gain on Sale of Assets, Net. We had net gains
on sales of assets of $36.1 million in 2005 primarily due
to the sale of one jackup rig, two tender-assisted barge rigs
and six land rigs. We had net gains on sales of assets of
$48.6 million in 2004 primarily due to the sale of three
jackup rigs.
Interest Expense. Interest expense for 2005
decreased by $15.2 million, or 14.7%, compared with 2004
primarily due to lower total debt levels resulting from the
repayment of debt during 2004 and 2005. Included in 2005 are
charges of $3.6 million related to the write-off of
deferred financing costs as a result of the prepayment of our
senior secured term loan.
Other Income, Net. Other income, net for 2005
increased by $9.0 million from $0.5 million for 2004
to $9.5 million for 2005. The increase was primarily due to
a $1.2 million increase in net foreign exchange gains in
2005 compared with 2004, a $4.5 million increase in
mark-to-market
gains and cash settlements on interest rate swap and cap
agreements and a $3.3 million increase in other income.
Income Taxes. Our consolidated effective tax
rate for 2005 was 40.5% as compared with 54.3% for 2004. The
lower rate in 2005 compared with 2004 was primarily due to debt
refinancing charges in 2004 that reduced income without a
proportional reduction to income taxes, and an increase in 2005
taxable income in foreign jurisdictions with low or zero
effective tax rates. These reductions were partially offset by
an increase in 2005 taxable income in high effective tax rate
countries, and an increase in U.S. tax on certain foreign
earnings.
Minority Interest. Minority interest in 2005
decreased $4.8 million, or 19.6%, compared with 2004
primarily due to lower income from our joint venture that owns
the Pride Angola due to it being out of service for
approximately 45 days to undergo its special periodic
survey and increased interest expense on the joint
venture’s debt which was refinanced and increased in 2004,
partially offset by an increase in minority interest related to
the
mark-to-market
gains on interest rate swap and cap agreements.
Our objective in financing our business is to maintain adequate
financial resources and access to additional liquidity. During
2006, cash flows from operations, borrowings under our senior
secured revolving credit facility and proceeds from asset sales
and stock option exercises were the principal sources of
funding. We anticipate that cash on hand and cash flows from
operations will be adequate to fund normal ongoing capital
expenditures, working capital needs and debt service
requirements in 2007. Our $500.0 million senior secured
revolving credit facility provides
back-up
liquidity in the event of an unanticipated significant demand on
cash that would not be funded by operations.
Our capital allocation process is focused on utilizing cash
flows generated from operations in ways that enhance the value
of our company. In 2006, we used cash for a variety of
activities including working capital needs, repayment of
indebtedness and purchases of property and equipment.
Cash and cash equivalents, including restricted cash, totaled
$65.9 million at December 31, 2006 compared with
$46.9 million at December 31, 2005. For 2006, net cash
provided by operating activities was $611.7 million as
compared with $321.9 million for 2005. The increase in net
cash provided from operations was primarily due to the increase
in net income.
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Purchases of property and equipment totaled $356.2 million
and $157.2 million for 2006 and 2005, respectively. The
majority of these expenditures related to capital expenditures
incurred in connection with new contracts and other sustaining
capital projects.
Proceeds from dispositions of property and equipment were
$60.5 million and $121.2 million for 2006 and 2005,
respectively. Included in the proceeds for 2006 was
$51.3 million related to the sale of the Pride Rotterdam
and four land rigs. Included in the proceeds for 2005 was
$40.0 million related to the sale of the Pride Ohio
by one of our foreign subsidiaries, $49.5 million
related to the sale of the Piranha and the Ile de Sein
and $23.0 million related to three land rigs.
In November 2006, we acquired the remaining 70% interest in the
joint venture entity that owns the Pride Portland and the
Pride Rio de Janeiro for $215.0 million in cash,
plus earn-out payments, if any, to be made during the six-year
period (subject to certain extensions for non-operating periods)
following the expiration of the existing drilling contracts for
the rigs. The transaction also resulted in the recording of
approximately $284 million of debt, net of the fair value
discount, of the joint venture companies to our consolidated
balance sheet. In addition, we paid $15 million to an
affiliate of our partner for the cancellation of future
obligations under certain existing agency relationships related
to five offshore rigs we operate in Brazil. We funded the
purchase price and cancellation payment with available cash and
borrowings under our revolving credit facility.
In December 2005, we acquired an additional 40% interest in our
joint venture companies that manage our Angolan operations from
our partner, the national oil company of Angola, for
$170.9 million in cash. In addition, we paid
$4.5 million to an affiliate of our partner for termination
of certain agreements related to the operation of the joint
venture. We funded the purchase price and the termination
payment with borrowings under our senior secured revolving
credit facility.
We received proceeds of $1.4 million and
$124.9 million from the issuance of common stock in 2006
and 2005, respectively. The proceeds for 2005 included
$123.6 million (before offering costs) related to the
public offering of 6.0 million shares of common stock. We
used the net proceeds from the offering to purchase an equal
number of shares of our common stock from three affiliated
investment funds at a price per share equal to the proceeds per
share that we received from the offering. The shares repurchased
from the funds were subsequently retired. We also received
proceeds of $50.3 million and $91.2 million from the
exercise of stock options in 2006 and 2005, respectively.
Debt, including current maturities, totaled
$1,386.6 million at December 31, 2006 compared with
$1,244.8 million at December 31, 2005.
Cash and cash equivalents, including restricted cash, totaled
$46.9 million at December 31, 2005 compared with
$47.0 million at December 31, 2004. For 2005, net cash
provided by operating activities was $321.9 million as
compared with $337.1 million for 2004. The decrease in net
cash provided from operations was primarily due to an
$83.3 million increase in working capital, primarily driven
by an increase in accounts receivable, partially offset by an
increase in net income.
Purchases of property and equipment totaled $157.2 million
and $136.7 million for 2005 and 2004, respectively. The
majority of these expenditures related to capital expenditures
incurred in connection with new contracts and other sustaining
capital projects. In 2004, we purchased the Pride Ivory
Coast tender-assisted drilling rig for $16.0 million.
Proceeds from dispositions of property and equipment were
$121.2 million and $73.5 million for 2005 and 2004,
respectively. Included in the proceeds for 2005 was
$114.5 million related to the sale of one jackup rig, two
tender-assisted rigs and six land rigs. Included in the proceeds
for 2004 was $71.0 million related to the sale of three
jackup rigs.
As described above, in December 2005, we acquired an additional
40% interest in our Angolan joint venture companies for
$170.9 million and paid $4.5 million for termination
of certain agreements related to the operation of the joint
venture.
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We received proceeds of $124.9 million and
$1.5 million from the issuance of common stock in 2005 and
2004, respectively. We also received proceeds of
$91.2 million and $10.1 million from the exercise of
stock options in 2005 and 2004, respectively.
Debt, including current maturities, totaled
$1,244.8 million at December 31, 2005 compared with
$1,725.2 million at December 31, 2004. During 2005, we
engaged in the following financing transactions:
As of December 31, 2006, we had working capital of
$293.1 million compared with $213.8 million as of
December 31, 2005. These amounts included an aggregate of
short-term borrowings and current portion of long-term debt of
$91.9 million and $59.7 million, an aggregate of cash
and cash equivalents and restricted cash of $65.9 million
and $46.9 million, accounts receivable, net of
$505.0 million and $435.5 million and accounts payable
of $189.9 million and $159.8 million. The increase in
working capital was attributable primarily to the increase in
current deferred income taxes relating to reclassification due
to our ability to utilize our NOL carryforwards in 2007 and the
increase in accounts receivable due to higher dayrates,
partially offset by increases in accrued expenses due to the
deferred contract liabilities from our joint venture acquisition
and increases in accounts payable and accrued expenses due to
increased business activity.
Our
73/8% Senior
Notes due 2014 are rated Ba2 by Moody’s Investor Service,
Inc., BB- by both Standard & Poor’s Rating
Services and BB by Fitch Ratings. Moody’s, S&P’s
and Fitch’s ratings outlooks are stable.
We currently have a $500.0 million senior secured revolving
credit facility with a group of banks maturing in July 2009.
Borrowings under the facility are available for general
corporate purposes. We may obtain up to $100.0 million of
letters of credit under the revolving credit facility. As of
December 31, 2006, there were $50.0 million of
borrowings and $19.2 million of letters of credit
outstanding under the facility. Amounts drawn under the facility
bear interest at variable rates based on LIBOR plus a margin or
prime rate plus a margin. The interest rate margin varies based
on our leverage ratio. As of December 31, 2006, the
interest rate on the facility was approximately 5.9% and
availability was approximately $430.8 million.
The facility is secured by first priority liens on certain of
the existing and future rigs, accounts receivable, inventory and
related insurance of our subsidiary Pride Offshore, Inc. (the
borrower under the facility) and its subsidiaries, all of the
equity of Pride Offshore and its domestic subsidiaries and 65%
of the equity of certain of our foreign subsidiaries. We and
certain of our domestic subsidiaries have guaranteed the
obligations of Pride Offshore under the facility. We generally
are required to repay the revolving loans, with a permanent
reduction in availability under the revolving credit facility,
with proceeds from a sale of or a casualty event with respect to
collateral. The facility contains a number of covenants
restricting, among other things, redemption and repurchase of
our indebtedness; distributions, dividends and repurchases of
capital stock and other equity interests; acquisitions and
investments; asset sales; capital expenditures; indebtedness;
liens; and affiliate transactions. The facility also contains
customary events of default, including with respect to a change
of control.
As of December 31, 2006, we had $500.0 million
principal amount of
73/8%
Senior Notes due 2014 outstanding. The notes provide for
semiannual interest payments and contain provisions that limit
our ability and the ability of our subsidiaries to enter into
transactions with affiliates; pay dividends or make other
restricted
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payments; incur debt or issue preferred stock; incur dividend or
other payment restrictions affecting our subsidiaries; sell
assets; engage in sale and leaseback transactions; create liens;
and consolidate, merge or transfer all or substantially all of
our assets. Many of these restrictions will terminate if the
notes are rated investment grade by either S&P or
Moody’s and, in either case, the notes have a specified
minimum rating by the other rating agency. We are required to
offer to repurchase the notes in connection with specified
change in control events that result in a ratings decline.
As of December 31, 2006, we had $300.0 million
principal amount of
31/4%
Convertible Senior Notes due 2033 outstanding. The notes provide
for semiannual interest payments and for the payment of
contingent interest during any six-month interest period
commencing on or after May 1, 2008 for which the trading
price of the notes for each of the five trading days immediately
preceding such period equals or exceeds 120% of the principal
amount of the notes. Beginning May 5, 2008, we may redeem
any of the notes at a redemption price of 100% of the principal
amount redeemed plus accrued and unpaid interest. In addition,
noteholders may require us to repurchase the notes on May 1
of 2008, 2010, 2013, 2018, 2023 and 2028 at a repurchase price
of 100% of the principal amount redeemed plus accrued and unpaid
interest. We may elect to pay all or a portion of the repurchase
price in common stock instead of cash, subject to certain
conditions. The notes are convertible under specified
circumstances into shares of our common stock at a conversion
rate of 38.9045 shares per $1,000 principal amount of notes
(which is equal to a conversion price of $25.704), subject to
adjustment. Upon conversion, we will have the right to deliver,
in lieu of shares of common stock, cash or a combination of cash
and common stock.
As of December 31, 2006, we had $190.5 million
principal amount outstanding under our drillship loan facility
due in 2010. Our drillship loan facility is collateralized by
the two drillships, the Pride Africa and the Pride
Angola, and the proceeds from the related drilling
contracts. The drillship loan facility matures in September 2010
and amortizes quarterly. The drillship loan facility is
non-recourse to us and the joint owner. The drillship loan bears
interest at LIBOR plus 1.50%. As a condition of the loan, we
maintain interest rate swap and cap agreements with the lenders.
In accordance with the debt agreements, certain cash balances
are held in trust to assure that timely interest and principal
payments are made. As of December 31, 2006 and 2005,
$1.8 million of such cash balances, which amount is
included in restricted cash, was held in trust and is not
available for our use.
In February 1999, we completed the sale and leaseback of the
Pride South America semisubmersible drilling rig with an
unaffiliated leasing trust pursuant to which we received
$97.0 million. We consolidate the leasing trust’s
assets and liabilities, which comprise the Pride South
America rig and the associated note payable. As of
December 31, 2006 and 2005, the carrying amount of the note
payable was approximately $64.2 million and
$72.3 million, respectively. The note payable is
collateralized by the Pride South America. The note
payable bears interest at 9.35% and requires quarterly interest
payments. In February 2007, we notified the note holders that we
will exercise our right to prepay the semisubmersible loan in
August 2007.
In November 2006, we completed the purchase of the remaining 70%
interest in the joint venture entity that owns the Pride
Portland and the Pride Rio de Janeiro. This
transaction resulted in the addition of approximately
$284 million of debt, net of fair value discount,
(representing 100% of the joint venture entity’s debt) to
our consolidated balance sheet. The notes representing the debt
were used by the joint venture entity to finance a portion of
the cost of construction of these rigs. Repayment of the notes
is guaranteed by the United States Maritime Administration
(“MARAD”). The notes bear interest at a weighted
average fixed rate of 4.33%, mature in 2016 and are prepayable,
in whole or in part, at any time, subject to a make- whole
premium. The notes are collateralized by the two rigs and the
net proceeds received by subsidiary project companies chartering
the rigs.
Mobilization fees received from customers and the costs incurred
to mobilize a rig from one geographic area to another, as well
as up-front fees to modify a rig to meet a customer’s
specifications, are deferred and amortized over the term of the
related drilling contracts. These up-front fees and costs impact
liquidity in the period in which the fees are received or the
costs incurred, whereas they will impact our statement of
operations in the periods during which the deferred revenues and
costs are amortized. The amount of up-front fees received and
the related costs vary from period to period depending upon the
nature of new contracts entered into and market conditions then
prevailing. Generally, contracts for drilling services in remote
locations or contracts that require specialized
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equipment will provide for higher up-front fees than contracts
for readily available equipment in major markets. Additionally,
we defer costs associated with obtaining in-class certification
from various regulatory bodies in order to operate our offshore
rigs. We amortize these costs over the period of validity of the
related certificate.
We expect our purchases of property and equipment for 2007 to be
approximately $400 million. These purchases are expected to
be used primarily for various rig upgrades in connection with
new contracts as contracts expire during the year and other
sustaining capital projects.
We anticipate making income tax payments of approximately
$145 million to $165 million in 2007.
We may redeploy additional assets to more active regions if we
have the opportunity to do so on attractive terms. We frequently
bid for or negotiate with customers regarding multi-year
contracts that could require significant capital expenditures
and mobilization costs. We expect to fund project opportunities
primarily through a combination of working capital, cash flow
from operations and borrowings under our senior secured
revolving credit facility.
We may review from time to time possible expansion and
acquisition opportunities relating to our business segments,
which may include the construction of rigs for our fleet and
acquisitions of rigs and other business. While we have no
definitive agreements to acquire or construct additional
equipment or to acquire any businesses, suitable opportunities
may arise in the future. Any determination to construct
additional rigs for our fleet will be based on market conditions
and opportunities existing at the time, including the
availability of long-term contracts with sufficient dayrates for
the rigs and the relative costs of building new rigs with
advanced capabilities compared with the costs of retrofitting or
converting existing rigs to provide similar capabilities. The
timing, size or success of any acquisition or construction
effort and the associated potential capital commitments are
unpredictable. We may fund all or part of any such efforts with
proceeds from debt
and/or
equity issuances.
We consider from time to time opportunities to dispose of
certain assets or groups of assets when we believe the capital
could be more effectively deployed. We are actively pursuing
options for maximizing the value of our Latin America Land and
E&P Services operations. All options are being considered,
including sales to strategic buyers and capital market
alternatives. We may ultimately decide to pursue a course of
action other than a disposition of these operations; however, if
we do pursue a disposition, we may be unable to complete a
transaction on terms we find acceptable or at all.
In addition to the matters described in this
“— Liquidity and Capital Resources” section,
please read “— Business Outlook” and
“— Segment Review” for additional matters
that may have a material impact on our liquidity.
In the table below, we set forth our contractual obligations as
of December 31, 2006. Some of the figures we include in
this table are based on our estimates and assumptions about
these obligations, including their duration and other factors.
The contractual obligations we will actually pay in future
periods may vary from those reflected in the table because the
estimates and assumptions are subjective.
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In the normal course of business with customers, vendors and
others, we have entered into letters of credit and surety bonds
as security for certain performance obligations which totaled
approximately $223.0 million at December 31, 2006.
These letters of credit and surety bonds are issued under a
number of facilities provided by several banks and other
financial institutions and are not normally called as we
typically comply with the underlying performance requirement.
In June 2006, the Financial Accounting Standards Board
(“FASB”) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes — an
Interpretation of FASB Statement No. 109 (FIN 48).
This interpretation clarifies the accounting for uncertainty in
income taxes recognized in an enterprise’s financial
statements in accordance with SFAS No. 109,
Accounting for Income Taxes. FIN 48 will require
companies to determine whether it is more-likely-than-not that a
tax position taken or expected to be taken in a tax return will
be sustained upon examination, including resolution of any
related appeals or litigation processes, based on the technical
merits of the position. FIN 48 also provides guidance on
measurement, derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition. FIN 48 is effective for fiscal years beginning
after December 15, 2006. We adopted FIN 48 on
January 1, 2007. We are currently evaluating the potential
impact, if any, to our consolidated financial statements. We
anticipate that the adoption of FIN 48 could introduce
additional volatility into our effective income tax rate in
future periods.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurement, which defines fair value as the
price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date. The standard also responds
to investors’ requests for more information about
(1) the extent to which companies measure assets and
liabilities at fair value, (2) the information used to
measure fair value, and (3) the effect that fair-value
measurements have on earnings. SFAS No. 157 will apply
whenever another standard requires (or permits) assets or
liabilities to be measured at fair value. The standard does not
expand the use of fair value to any new circumstances.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years. We are currently
evaluating the potential impact, if any, to our consolidated
financial statements.
In September 2006, the FASB issued SFAS No. 158,
Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans. This statement requires
employers to recognize on their balance sheets the obligations
associated with single-employer defined benefit pension, retiree
healthcare, and other postretirement plans.
SFAS No. 158 amends SFAS No. 87,
Employers’ Accounting for Pensions,
SFAS No. 88, Employers’ Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans
and for Termination Benefits, SFAS No. 106,
Employers’ Accounting for Postretirement Benefits Other
Than Pensions, and SFAS No. 132R,
Employers’ Disclosures about Pensions and Other
Postretirement Benefits, and will require employers to
recognize on their balance sheets the funded status of pension
and postretirement benefit plans and will require fiscal year
end measurements of plan assets and benefit obligations.
SFAS No. 158 will not impact most of the measurement
and disclosure guidance nor will it change the amounts
recognized in the income statement as net periodic benefit cost.
As of December 31, 2006, we adopted the recognition of the
funded status of plans subject to SFAS No. 158 (see
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Note 11 of our Notes to Consolidated Financial Statements
included in Item 8 of this annual report). The requirement
to measure plan assets and benefit as of fiscal year end is
effective for fiscal years ending after December 15, 2008.
In June 2006, the FASB ratified the consensus reached by the
Emerging Issues Task Force (“EITF”) on Issue
No. 06-3,
How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income
Statement (That is, Gross versus Net Presentation). EITF
Issue
No. 06-3
addresses disclosure requirements for any tax assessed by a
governmental authority that is directly imposed on a
revenue-producing transaction between a seller and a customer
and may include, but is not limited to, sales, use, value added
and some excise taxes. EITF Issue
No. 06-3
concludes that the presentation of taxes on either a gross basis
(included in revenues and costs) or a net basis (excluded from
revenues) is an accounting policy decision that should be
disclosed. In addition, for any such taxes that are reported on
a gross basis, a company should disclose the amounts of those
taxes in interim and annual financial statements for each period
for which an income statement is presented if those amounts are
significant. The provisions of EITF Issue
No. 06-3
should be applied to financial reports for interim and annual
reporting periods beginning after December 15, 2006, with
earlier adoption permitted. We adopted EITF Issue
No. 06-3
effective January 1, 2007. We are currently evaluating the
impact of adopting EITF Issue
No. 06-3
but do not expect its adoption to have a significant impact on
our results of operations and financial condition.
In September 2006, the SEC issued Staff Accounting Bulletin
No. 108, “Considering the Effects of Prior Year
Misstatements when Quantifying Misstatements in Current Year
Financial Statements” (“SAB 108”).
SAB 108 requires a registrant to quantify the impact of
correcting all misstatements on its current year financial
statements using two approaches, the rollover and iron curtain
approaches. A registrant is required to adjust its current year
financial statements if either approach to accumulate and
identify misstatements results in quantifying a misstatement
that is material, after considering all relevant quantitative
and qualitative factors. SAB 108 is required to be
considered for financial statements for fiscal years ending
after November 15, 2006. The adoption of SAB 108 had
no impact on our consolidated results of operations, financial
position or cash flows.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities. SFAS No. 159 permits companies to
choose to measure, on an
instrument-by-instrument
basis, financial instruments and certain other items at fair
value that are not currently required to be measured at fair
value. We are currently evaluating whether to elect the option
provided for in this standard. If elected,
SFAS No. 159 would be effective for us as of
January 1, 2008. We are currently evaluating the potential
impact, if any, to our consolidated financial statements.
This annual report contains forward-looking statements within
the meaning of Section 27A of the Securities Act of 1933
and Section 21E of the Securities Exchange Act of 1934. All
statements, other than statements of historical fact, included
in this annual report that address activities, events or
developments that we expect, project, believe or anticipate will
or may occur in the future are forward-looking statements. These
include such matters as:
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We have based these statements on our assumptions and analyses
in light of our experience and perception of historical trends,
current conditions, expected future developments and other
factors we believe are appropriate in the circumstances.
These statements are subject to a number of assumptions, risks
and uncertainties, including those described in “Risk
Factors” in Item 1A of this annual report and the
following:
Most of these factors are beyond our control. We caution you
that forward-looking statements are not guarantees of future
performance and that actual results or developments may differ
materially from those projected in these statements.
We are exposed to certain market risks arising from the use of
financial instruments in the ordinary course of business. These
risks arise primarily as a result of potential changes in the
fair market value of financial instruments that would result
from adverse fluctuations in interest rates and foreign currency
exchange rates as discussed below. We may enter into derivative
financial instrument transactions to manage or reduce market
risk, but do not enter into derivative financial instrument
transactions for speculative purposes.
Interest Rate Risk. We are exposed to changes
in interest rates through our fixed rate long-term debt.
Typically, the fair market value of fixed rate long-term debt
will increase as prevailing interest rates decrease and will
decrease as prevailing interest rates increase. The fair value
of our long-term debt is estimated based on quoted market prices
where applicable, or based on the present value of expected cash
flows relating to the debt discounted at rates currently
available to us for long-term borrowings with similar terms and
maturities. The estimated fair value of our long-term debt as of
December 31, 2006 and 2005 was $1,486.8 million and
$1,397.1 million, respectively, which was more than its
carrying value as of December 31, 2006 and 2005 of
$1,386.6 million and $1,244.8 million, respectively. A
hypothetical 100 basis point decrease in interest rates
relative to market interest rates at December 31, 2006
would increase the fair market value of our long-term debt at
December 31, 2006 by approximately $33.9 million.
As of December 31, 2006, we held interest rate swap and cap
agreements relating to the drillship loan facility as required
by the lenders. We have not designated these interest rate swap
and cap agreements as hedging
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instruments in accordance with SFAS No. 133.
Accordingly, the interest rate swap and cap agreements are
marked-to-market
with realized and unrealized gains and losses recorded in our
consolidated statements of operations. As of December 31,
2006, the fair value of the interest rate swap and cap
agreements was an asset of $4.0 million.
Foreign Currency Exchange Rate Risk. We
operate in a number of international areas and are involved in
transactions denominated in currencies other than the
U.S. dollar, which expose us to foreign currency exchange
rate risk. We utilize local currency borrowings and the payment
structure of customer contracts to selectively reduce our
exposure to exchange rate fluctuations in connection with
monetary assets, liabilities and cash flows denominated in
certain foreign currencies. We did not enter into any forward
exchange or option contracts in 2006 and 2005, but continue to
monitor our exposure to foreign currency exchange risk. We do
not hold or issue foreign currency forward contracts, option
contracts or other derivative financial instruments for
speculative purposes.
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The Board of Directors and Stockholders
Pride International, Inc.:
We have audited the accompanying consolidated balance sheets of
Pride International, Inc. as of December 31, 2006 and 2005,
and the related consolidated statements of operations,
stockholders’ equity, and cash flows for each of the years
in the two-year period ended December 31, 2006. These
consolidated financial statements are the responsibility of the
Company’s management. Our responsibility is to express an
opinion on these consolidated 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, the consolidated financial statements referred
to above present fairly, in all material respects, the financial
position of Pride International, Inc. as of December 31,
2006 and 2005, and the results of its operations and its cash
flows for each of the years in the two-year period ended
December 31, 2006, in conformity with U.S. generally
accepted accounting principles.
As discussed in note 1 to the financial statements, the
Company adopted Statement of Financial Accounting Standards
No. 158, Employers’ Accounting for Defined Benefit
Pension and Other Postretirement Plans, and Statement of
Financial Accounting Standards No. 123(R), Share-Based
Payment.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
effectiveness of Pride International, Inc.’s internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO), and our report
dated February 28, 2007 expressed an unqualified opinion on
management’s assessment of, and the effective operation of,
internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 28, 2007
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The Board of
Directors and Stockholders
Pride International, Inc.:
We have audited management’s assessment, included in the
accompanying Management’s Report on Internal Control over
Financial Reporting for the year ended December 31, 2006,
that Pride International, Inc. maintained effective internal
control over financial reporting as of December 31, 2006,
based on criteria established in Internal Control —
Integrated Framework issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). Pride
International, Inc.’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. Our responsibility is to express an
opinion on management’s assessment and an opinion on the
effectiveness of 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, evaluating
management’s assessment, testing and evaluating the design
and operating effectiveness of internal control, 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 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 its inherent limitations, internal control over
financial reporting may not prevent or detect misstatements.
Also, projections of any evaluation of effectiveness to future
periods are subject to the risk that 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, management’s assessment that Pride
International, Inc. maintained effective internal control over
financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on criteria established
in Internal Control — Integrated Framework
issued by COSO. Also, in our opinion, Pride International, Inc.
maintained, in all material respects, effective internal control
over financial reporting as of December 31, 2006, based on
criteria established in Internal Control —
Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the
Public Company Accounting Oversight Board (United States), the
consolidated balance sheets of Pride International, Inc. as of
December 31, 2006 and 2005, and the related consolidated
statements of operations, stockholders’ equity, and cash
flows for each of the years in the two-year period ended
December 31, 2006, and our report dated February 28,
2007 expressed an unqualified opinion on those consolidated
financial statements.
/s/ KPMG LLP
Houston, Texas
February 28, 2007
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To the Board of Directors and Shareholders of
Pride International, Inc:
In our opinion, the consolidated statements of operations,
stockholders’ equity, and cash flows for the year ended
December 31, 2004 present fairly, in all material respects,
the results of operations and cash flows of Pride International,
Inc. and its subsidiaries (“the Company”) for the year
ended December 31, 2004, in conformity with accounting
principles generally accepted in the United States of America.
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 audit. We
conducted our audit of these statements 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,
assessing the accounting principles used and significant
estimates made by management, and evaluating the overall
financial statement presentation. We believe that our audit
provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 25, 2005, except for the restatement discussed in the
third and fourth paragraphs of Note 2 to the consolidated
financial statements included in the 2004
Form 10-K/A
(not presented herein) as to which the date is January 24,
2006, and except for the realignment of the Company’s
reportable segments described in the fifth paragraph of
Note 1 to the consolidated financial statements as to which
the date is March 1, 2007.
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Pride
International, Inc.
Consolidated
Balance Sheets
The accompanying notes are an integral part of the consolidated
financial statements.
Table of Contents
Pride
International, Inc.
Consolidated
Statements of Operations
The accompanying notes are an integral part of the consolidated
financial statements.
Table of Contents
Pride
International, Inc.
Consolidated
Statements of Stockholders’ Equity
The accompanying notes are an integral part of the consolidated
financial statements.
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Pride
International, Inc.
Consolidated
Statements of Cash Flows
The accompanying notes are an integral part of the consolidated
financial statements.
Table of Contents
Pride
International, Inc.
Notes to
Consolidated Financial Statements
Pride International, Inc. (“Pride”, “we,”
“our,” or “us”) is a leading international
provider of contract drilling and related services, operating
both offshore and on land. We provide contract drilling services
to oil and natural gas exploration and production companies
through the operation and management of 63 mobile offshore rigs
and 214 land-based drilling and workover rigs.
The consolidated financial statements include the accounts of
Pride and all entities that we control by ownership of a
majority voting interest as well as variable interest entities
for which we are the primary beneficiary. All significant
intercompany transactions and balances have been eliminated in
consolidation. Investments over which we have the ability to
exercise significant influence over operating and financial
policies, but do not hold a controlling interest, are accounted
for using the equity method of accounting. Investments in which
we do not exercise significant influence are accounted for using
the cost method of accounting.
In accordance with Financial Accounting Standards Board
Interpretation (“FIN”) No. 46R, Consolidation
of Variable Interest Entities, an Interpretation of ARB
No. 51 (revised December 2003), we are the primary
beneficiary of the unaffiliated trust with which we completed
the sale and leaseback of the Pride South America
semisubmersible drilling rig in February 1999. Accordingly,
the assets and liabilities and revenues and expenses of the
trust have been included in the accompanying consolidated
financial statements.
The preparation of financial statements in conformity with
accounting principles generally accepted in the United States
requires management to make estimates and assumptions that
affect the reported amounts of assets and liabilities,
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.
In September 2006, we reorganized our operations into three
principal reportable segments: Offshore, Latin America Land, and
E&P Services. The realignment of our reportable segments was
attributable to recent organizational changes, including the
hiring of a Chief Operating Officer responsible for all of our
offshore drilling fleet. Our Offshore segment includes all of
our offshore drilling fleet and operations. Our Latin America
Land segment includes our all of our land-based drilling and
workover services in Latin America. Our E&P Services segment
includes our exploration and production services business in
Latin America. “Other” includes revenues and cost for
land-based drilling and workover operations outside of Latin
America (currently Chad, Kazakhstan and Pakistan), labor
contracts and engineering and management consulting services.
All prior period information has been reclassified to conform to
the current period presentation. See Note 14.
Our current business and operations are substantially dependent
upon conditions in the oil and natural gas industry and,
specifically, the exploration and production expenditures of oil
and natural gas companies. The demand for contract drilling and
related services is influenced by, among other things, oil and
natural gas prices, expectations about future prices, the cost
of producing and delivering oil and natural gas, government
regulations and local and international political and economic
conditions. There can be no assurance that current levels of
exploration and production expenditures of oil and natural gas
companies will be maintained or that demand for our services
will reflect the level of such activities.
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
All dollar amounts (except per unit amounts) presented in the
tabulations within the notes to our financial statements are
stated in million of dollars, unless otherwise indicated.
We recognize revenue as services are performed based upon
contracted dayrates and the number of operating days during the
period. Revenue from turnkey contracts is based on percentage of
completion. Mobilization fees received and costs incurred in
connection with a customer contract to mobilize a rig from one
geographic area to another are deferred and recognized on a
straight-line basis over the term of such contract, excluding
any option periods. Costs incurred to mobilize a rig without a
contract are expensed as incurred. Fees received for capital
improvements to rigs are deferred and recognized on a
straight-line basis over the period of the related drilling
contract. The costs of such capital improvements are capitalized
and depreciated over the useful lives of the assets.
We have historically constructed drilling rigs only for our own
use. However, in 2001, at the request of some of our significant
customers, we entered into fixed-fee contracts to design,
construct and mobilize specialized drilling rigs through our
technical services group. We also entered into separate
contracts to operate the rigs on behalf of the customers.
Construction contract revenues and related costs were recognized
under the
percentage-of-completion
method of accounting using measurements of progress toward
completion appropriate for the work performed, such as man
hours, costs incurred or physical progress. Accordingly, we
reviewed contract price and cost estimates periodically as the
work progressed and reflected adjustments in income to recognize
income proportionate to the percentage of completion in the case
of projects showing an estimated profit at completion and to
recognize the entire amount of the loss in the case of projects
showing an estimated loss at completion. To the extent these
adjustments resulted in an increase in previously reported
losses or a reduction in or an elimination of previously
reported profits with respect to a project, we recognized a
charge against current earnings. We have discontinued our
fixed-fee rig construction business. See Note 12.
We consider all highly liquid debt instruments having maturities
of three months or less at the date of purchase to be cash
equivalents.
Parts and supplies consist of spare rig parts and supplies held
in warehouses for use in operations and are valued at weighted
average cost.
Property and equipment are carried at original cost or adjusted
net realizable value, as applicable. Major renewals and
improvements are capitalized and depreciated over the respective
asset’s remaining useful life. Maintenance and repair costs
are charged to expense as incurred. When assets are sold or
retired, the remaining costs and related accumulated
depreciation are removed from the accounts and any resulting
gain or loss is included in results of operations.
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
For financial reporting purposes, depreciation of property and
equipment is provided using the straight-line method based upon
expected useful lives of each class of assets. Expected useful
lives of the assets for financial reporting purposes are as
follows:
Rigs and rig equipment have salvage values not exceeding 20% of
the cost of the rig or rig equipment.
Interest is capitalized on
construction-in-progress
at the weighted average cost of debt outstanding during the
period of construction or at the interest rate on debt incurred
for construction.
We assess the recoverability of the carrying amount of property
and equipment if certain events or changes occur, such as
significant decrease in market value of the assets or a
significant change in the business conditions in a particular
market. In 2006, we recognized an impairment charge of
$3.9 million related to two platform rigs and three land
workover rigs. In 2005, we recognized an impairment charge of
$1.0 million related to damage a platform rig sustained in
2004. In 2004, we recognized an impairment charge of
$24.9 million related to retiring 16 stacked land rigs and
nine shallow water platform rigs and a loss on impairment of an
inactive land rig and other equipment.
We periodically assess the recoverability of our investments in
affiliates. If an identified event or change in circumstances
requires an impairment evaluation, we assess fair value based on
valuation methods as appropriate, including discounted cash
flows, estimates of sales proceeds and external appraisals, as
appropriate.
Goodwill is not amortized. All goodwill is assigned to reporting
units, which we have determined are the same as our reporting
segments. In accordance with Statement of Financial Accounting
Standards (“SFAS”) No. 142, Goodwill and Other
Intangible Assets, we perform an annual impairment test of
goodwill in each of our reporting units as of December 31,
or more frequently if circumstances indicate that impairment may
exist. Such tests include comparing the fair value of a
reporting unit with its carrying value, including goodwill.
Impairment assessments are performed using a variety of
methodologies, including cash flows analysis and estimates of
market value. There were no impairments in 2006, 2005 or 2004 at
our reporting units related to the annual impairment test.
We are required to obtain certifications from various regulatory
bodies in order to operate our offshore drilling rigs and must
maintain such certifications through periodic inspections and
surveys. The costs associated with obtaining and maintaining
such certifications, including inspections and surveys, and
drydock costs to the rigs are deferred and amortized over the
corresponding certification periods.
We expended $22.1 million, $17.2 million and
$17.4 million during 2006, 2005 and 2004, respectively, in
obtaining and maintaining such certifications. As of
December 31, 2006 and 2005, the deferred and unamortized
portion of such costs on our balance sheet was
$43.8 million and $40.0 million, respectively. The
portion of the costs that are expected to be amortized in the
12 month periods following each balance sheet date are
included in other current assets on the balance sheet and the
costs expected to be amortized after more than 12 months
from each balance sheet date are included in other assets. The
costs are amortized on a straight-line basis over the period of
validity of the certifications obtained. These certifications
are typically for five years, but in some cases are for shorter
periods. Accordingly, the remaining useful lives for these
deferred costs are up to five years.
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
We have entered into derivative financial instruments to
economically limit our exposure to changes in interest rates.
Our policies do not permit the use of derivative financial
instruments for speculative purposes. As of December 31,
2006, we had not designated any of our derivative financial
instruments as hedging instruments as defined by
SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities (as amended). Accordingly, the
changes in fair value of the derivative financial instruments
are recorded in “Other income, net” in our
consolidated statement of operations.
We recognize deferred tax liabilities and assets for the
expected future tax consequences of events that have been
included in the financial statements or tax returns. Deferred
tax liabilities and assets are determined based on the
difference between the financial statement and the tax basis of
assets and liabilities using enacted tax rates in effect for the
year in which the asset is recovered or the liability is
settled. A valuation allowance for deferred tax assets is
established when it is more likely than not that some portion or
all of the deferred tax assets will not be realized.
Because of tax jurisdictions in which we operate, some of which
are revenue based tax regimes, changes in earnings before taxes
and minority interest do not directly correlate to changes in
our provision for income tax.
We have designated the U.S. dollar as the functional
currency for most of our operations in international locations
because we contract with customers, purchase equipment and
finance capital using the U.S. dollar. In those countries
where we have designated the U.S. dollar as the functional
currency, certain assets and liabilities of foreign operations
are translated at historical exchange rates, revenues and
expenses in these countries are translated at the average rate
of exchange for the period, and all translation gains or losses
are reflected in the period’s results of operations. In
those countries where the U.S. dollar is not designated as
the functional currency, revenues and expenses are translated at
the average rate of exchange for the period, assets and
liabilities are translated at end of period exchange rates and
all translation gains and losses are included in accumulated
other comprehensive income (loss) within stockholders’
equity.
Financial instruments that potentially subject us to
concentrations of credit risk consist principally of cash and
cash equivalents and trade receivables. We place our cash and
cash equivalents in other high quality financial instruments. We
limit the amount of credit exposure to any one financial
institution or issuer. Our customer base consists primarily of
major integrated and government-owned international oil
companies, as well as smaller independent oil and gas producers.
Management believes the credit quality of our customers is
generally high. We provide allowances for potential credit
losses when necessary.
On January 1, 2006, we adopted the revised
SFAS No. 123(R), Share-Based Payment, using the
modified prospective method. SFAS No. 123(R) is a
revision of SFAS No. 123, Accounting for
Stock-Based Compensation, and supersedes Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees (“APB No. 25”).
SFAS No. 123(R) requires that companies recognize
compensation expense for awards of equity instruments to
employees based on the grant-date fair value of those awards.
That cost is to be recognized over the period during which an
employee is required to provide service in exchange for the
award. The fair value is to be estimated using an option pricing
model. SFAS No. 123(R) also requires that companies
measure the cost of liability-classified awards based on current
fair value. The fair value of these awards will be remeasured at
each
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
reporting date through the settlement date. Changes in fair
value during the requisite service period will be recognized as
compensation cost over that period. With respect to the
determination of the pool of windfall tax benefits, we elected
to use the transition election of SFAS No. 123(R)-3
(the “short-cut method”) as of the adoption of
SFAS No. 123(R). Under the “short-cut
method” the windfall tax benefits recognized for fully
vested awards, as defined in SFAS No. 123(R)-3, are
recognized as an addition to paid-in capital and are required to
be reported as a financing cash flow and an operating cash
outflow within the statement of cash flows. Windfall tax
benefits for partially vested awards should be recognized as if
we had always followed the fair-value method of recognizing
compensation cost in our financial statements and would be
included as a financing cash flow and an operating cash outflow
within the statement of cash flows. See Note 10 for the
impact of the adoption of SFAS No. 123(R).
Prior to January 1, 2006, we accounted for stock-based
compensation under APB No. 25 and provided pro forma
disclosure amounts in accordance with SFAS No. 148,
Accounting for Stock-Based Compensation —
Transition and Disclosure, as if the fair value method
defined by SFAS No. 123 had been applied to our
stock-based compensation. Under APB No. 25, no compensation
expense was recognized for stock options or for our employee
stock purchase plan (“ESPP”). Compensation expense
was, however, recognized for our restricted stock awards. Under
APB No. 25, we established an accounting policy to use the
tax ordering rules for the excess tax benefits of stock-based
compensation and we continue to use this accounting policy under
SFAS No. 123(R).
In 2006, we reevaluated our assumptions used in estimating the
fair value of stock options granted. As part of this assessment,
we determined that implied volatility calculated based on
actively traded options on our common stock is a better
indicator of expected volatility and future stock price trends
than one year historical volatility we used in 2005. As a
result, expected volatility for the year ended December 31,
2006 was based on a market-based implied volatility. We used the
Black-Scholes option pricing model to value the stock options.
The expected life computation is based on historical exercise
patterns and post-vesting termination behavior over the past
12 years. The risk-free interest rate is based on the
implied yield currently available on U.S. Treasury zero
coupon issues with a remaining term equal to the expected life.
Expected dividend yield is based on historical dividend payments.
In June 2006, the Financial Accounting Standards Board
(“FASB”) issued Interpretation No. 48,
Accounting for Uncertainty in Income Taxes — an
Interpretation of FASB Statement No. 109 (FIN 48).
This interpretation clarifies the accounting for uncertainty in
income taxes recognized in an enterprise’s financial
statements in accordance with SFAS No. 109,
Accounting for Income Taxes. FIN 48 will require
companies to determine whether it is more-likely-than-not that a
tax position taken or expected to be taken in a tax return will
be sustained upon examination, including resolution of any
related appeals or litigation processes, based on the technical
merits of the position. FIN 48 also provides guidance on
measurement, derecognition, classification, interest and
penalties, accounting in interim periods, disclosure and
transition. FIN 48 is effective for fiscal years beginning
after December 15, 2006. We adopted FIN 48 on
January 1, 2007. We are currently evaluating the potential
impact, if any, to our consolidated financial statements. We
anticipate that the adoption of FIN 48 could introduce
additional volatility into our effective income tax rate in
future periods.
In September 2006, the FASB issued SFAS No. 157,
Fair Value Measurement, which defines fair value as the
price that would be received to sell an asset or paid to
transfer a liability in an orderly transaction between market
participants at the measurement date. The standard also responds
to investors’ requests for more information about
(1) the extent to which companies measure assets and
liabilities at fair value, (2) the information used to
measure fair value, and (3) the effect that fair-value
measurements have on earnings. SFAS No. 157 will apply
whenever another standard requires (or permits) assets or
liabilities to be measured at fair value. The standard does not
expand the use of fair value to any new circumstances.
SFAS No. 157 is effective for financial statements
issued for fiscal years beginning after November 15, 2007,
and interim periods within those fiscal years. We are currently
evaluating the potential impact, if any, to our consolidated
financial statements.
In September 2006, the FASB issued SFAS No. 158,
Employers’ Accounting for Defined Benefit Pension and
Other Postretirement Plans. This statement requires
employers to recognize on their balance sheets the obligations
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
associated with single-employer defined benefit pension, retiree
healthcare, and other postretirement plans.
SFAS No. 158 amends SFAS No. 87,
Employers’ Accounting for Pensions,
SFAS No. 88, Employers’ Accounting for
Settlements and Curtailments of Defined Benefit Pension Plans
and for Termination Benefits, SFAS No. 106,
Employers’ Accounting for Postretirement Benefits Other
Than Pensions, and SFAS No. 132R,
Employers’ Disclosures about Pensions and Other
Postretirement Benefits, and will require employers to
recognize on their balance sheets the funded status of pension
and postretirement benefit plans and will require fiscal year
end measurements of plan assets and benefit obligations.
SFAS No. 158 will not impact most of the measurement
and disclosure guidance nor will it change the amounts
recognized in the income statement as net periodic benefit cost.
As of December 31, 2006, we adopted the recognition of the
funded status of plans subject to SFAS No. 158 (see
Note 11). The requirement to measure plan assets and
benefit as of fiscal year end is effective for fiscal years
ending after December 15, 2008.
In June 2006, the FASB ratified the consensus reached by the
Emerging Issues Task Force (“EITF”) on Issue
No. 06-3,
How Taxes Collected from Customers and Remitted to
Governmental Authorities Should Be Presented in the Income
Statement (That is, Gross versus Net Presentation). EITF
Issue
No. 06-3
addresses disclosure requirements for any tax assessed by a
governmental authority that is directly imposed on a
revenue-producing transaction between a seller and a customer
and may include, but is not limited to, sales, use, value added
and some excise taxes. EITF Issue
No. 06-3
concludes that the presentation of taxes on either a gross basis
(included in revenues and costs) or a net basis (excluded from
revenues) is an accounting policy decision that should be
disclosed. In addition, for any such taxes that are reported on
a gross basis, a company should disclose the amounts of those
taxes in interim and annual financial statements for each period
for which an income statement is presented if those amounts are
significant. The provisions of EITF Issue
No. 06-3
should be applied to financial reports for interim and annual
reporting periods beginning after December 15, 2006, with
earlier adoption permitted. We adopted EITF Issue
No. 06-3
effective January 1, 2007. We are currently evaluating the
impact of adopting EITF Issue
No. 06-3
but do not expect its adoption to have a significant impact on
our results of operations and financial condition.
In September 2006, the United States Securities and Exchange
Commission issued Staff Accounting Bulletin No. 108,
“Considering the Effects of Prior Year Misstatements when
Quantifying Misstatements in Current Year Financial
Statements” (“SAB 108”). SAB 108
requires a registrant to quantify the impact of correcting all
misstatements on its current year financial statements using two
approaches, the rollover and iron curtain approaches. A
registrant is required to adjust its current year financial
statements if either approach to accumulate and identify
misstatements results in quantifying a misstatement that is
material, after considering all relevant quantitative and
qualitative factors. SAB 108 is required to be considered
for financial statements for fiscal years ending after
November 15, 2006. The adoption of SAB 108 had no
impact on our consolidated results of operations, financial
position or cash flows.
In February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial
Liabilities. SFAS No. 159 permits companies to
choose to measure, on an
instrument-by-instrument
basis, financial instruments and certain other items at fair
value that are not currently required to be measured at fair
value. We are currently evaluating whether to elect the option
provided for in this standard. If elected,
SFAS No. 159 would be effective for us as of
January 1, 2008. We are currently evaluating the potential
impact, if any, to our consolidated financial statements.
Certain reclassifications have been made to the prior
years’ consolidated financial statements to conform with
the current year presentation.
In December 2005, we acquired an additional 40% interest in the
joint venture companies that manage our Angolan operations from
our partner Sonangol, the national oil company of Angola, for
$170.9 million in cash,
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
bringing our total ownership interest to 91%. Prior to the
acquisition, we owned a 51% interest in the joint venture
companies and fully consolidated the balance sheet and results
of operations of the joint venture companies, with a provision
for the minority interest for the 49% owned by Sonangol. The
principal assets of the joint venture companies include the two
ultra-deepwater drillships Pride Africa and Pride
Angola, the jackup rig Pride Cabinda and management
agreements for the deepwater platform rigs Kizomba A and
Kizomba B. In addition, we paid $4.5 million to an
affiliate of Sonangol for termination of certain agreements
related to the operation of the joint venture.
The purchase price was allocated based on the fair value of the
assets acquired and liabilities assumed. As the acquisition cost
was less than the fair value of the assets acquired and
liabilities assumed, we recorded no goodwill related to the
acquisition. We recorded $3.6 million as a contract-based
intangible asset related to the management agreements for the
Kizomba A and Kizomba B. This intangible asset
will be amortized over the lives of the contracts. Additionally,
as the current operating contracts for the Pride Africa
and Pride Angola were unfavorable compared with
current market rates, we recorded a deferred contract liability
of $18.7 million which will be amortized to revenues over
the remaining lives of the contracts. We increased the carrying
values of the drillships and the jackup rig by
$77.4 million to the fair values and we decreased our
minority interest in the joint venture companies by
$108.6 million.
In November 2006, we acquired from our joint venture partner its
70% interest in a joint venture company the principal assets of
which are two deepwater semi-submersible drilling rigs, the
Pride Portland and the Pride Rio de Janeiro. The
acquisition increased our ownership interest in the joint
venture entity and the rigs from 30% to 100%. Consideration
consisted of $215.0 million in cash, plus earn-out
payments, if any, to be made during the six-year period (subject
to certain extensions for non-operating periods) following the
expiration of the existing drilling contracts for the rigs. Such
earn-out payments will equal 30% of the amount, if any, by which
the standard operating dayrate, excluding bonuses, for a rig
(less adjustments to reflect certain capital additions and
certain increases in operating costs) exceeds $294,975 (or, in
the case of Petrobras, which currently contracts with a 15%
bonus opportunity, $256,500). As a result of the transaction,
the joint venture company, which was accounted for as an equity
investment, is consolidated in our financial statements,
resulting in the addition of approximately $284 million of
debt, net of the fair value discount of $3.9 million, of
the joint venture company to our consolidated balance sheet. Due
to the termination of lease agreements between us and the joint
venture company and because the related operating contracts for
the Pride Portland and the Pride Rio de Janeiro at
the time of acquisition were unfavorable compared with current
market rates, we recorded a non-cash deferred contract liability
of $191.6 million to record the difference between stated
values of the non-cancelable contracts and the current fair
value of contracts with similar terms. The deferred contract
liability will be amortized to revenues over the remaining lives
of the contracts of approximately four years. The allocation to
assets acquired and liabilities assumed based upon preliminary
fair values is as follows:
Table of Contents
Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
In a related transaction, we cancelled future obligations under
certain existing agency relationships related to five offshore
rigs we operates in Brazil, including the Pride Portland
and the Pride Rio de Janeiro. For this cancellation,
we paid $15 million in cash, which we expensed during the
fourth quarter 2006.
Property and equipment consisted of the following at
December 31:
During 2006, we sold the Pride Rotterdam for
$53.2 million, resulting in a pre-tax gain on the sale of
$25.3 million. The proceeds from this sale were used to
repay debt.
During 2005, one of our foreign subsidiaries sold the jackup rig
Pride Ohio and received $37.9 million in net
proceeds, resulting in a pre-tax gain on the sale of
$11.2 million. We also sold two tender-assisted barge rigs,
the Piranha and the Ile de Sein, for total net
proceeds of $45.6 million, resulting in a net pre-tax gain
of $3.8 million. In addition, we sold six land rigs for net
proceeds of $31.0 million and recognized a pre-tax gain of
$18.8 million. The proceeds from these sales were used to
repay debt.
During 2004, we sold a jackup rig, the Pride West
Virginia, for $60.0 million. Additionally, we sold two
stacked jackup rigs, the Pride Illinois and the Pride
Kentucky, for $11.0 million. Proceeds from these
transactions were used to repay debt.
Depreciation and amortization expense of property and equipment
for 2006, 2005 and 2004 was $268.7 million,
$257.1 million and $265.2 million, respectively.
We capitalize interest applicable to the construction of
significant additions to property and equipment. For 2006, 2005
and 2004, we capitalized interest of $2.4 million,
$0.5 million and $1.2 million, respectively.
During 2006, 2005 and 2004, maintenance and repair costs
included in operating costs on the accompanying consolidated
statements of operations were $156.2 million,
$140.8 million and $115.7 million, respectively.
We have a 30% interest in United Gulf Energy Resource Co.
SAOC-Sultanate of Oman (“UGER”), which owns 99.9% of
National Drilling and Services Co. LLC (“NDSC”), an
Omani company. NDSC owns and operates four land drilling rigs.
As of December 31, 2006, our investment in UGER was
$2.4 million. In addition we had $2.4 million in
receivables due from NDSC at December 31, 2006.
In 2005, investment in affiliates included our 30% interest in a
joint venture entity that owned the Pride Portland and
the Pride Rio de Janeiro. We operated the rigs under
lease agreements with the joint venture companies that required
all revenues from the operations of the rigs, less operating
costs and a management fee of $5,000 per day for each rig,
to be paid to the joint venture companies in the form of lease
payments. The lease
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
agreements also required the joint venture companies to provide
us with working capital necessary to operate the rigs, to fund
capital improvements to the rigs and to fund any cash deficits
incurred. In November 2006, we acquired our partner’s
interest in the joint venture companies, increasing our
ownership to 100% (see Note 2). Effective with the
acquisition, we eliminated our investment in affiliate as part
our purchase accounting.
As of December 31, 2006, we had agreements with several
banks for uncollateralized short-term lines of credit totaling
$28.6 million (substantially all of which are uncommitted),
primarily denominated in U.S. dollars. These facilities
renew periodically and bear interest at variable rates based on
LIBOR. As of December 31, 2006, no borrowings were
outstanding under these facilities and $28.6 million was
available for borrowings.
Long-term debt consisted of the following at December 31:
In July 2004, we entered into senior secured credit facilities
consisting of a $300.0 million term loan and a
$500.0 million revolving credit facility. Proceeds from the
term loan and initial borrowings of approximately
$95.0 million under the revolving credit facility were used
to refinance amounts outstanding under our other credit
facilities.
Amounts drawn under the revolving credit facility bear interest
at variable rates based on LIBOR plus a margin or prime rate
plus a margin. The interest rate margin varies based on our
leverage ratio. The revolving credit facility expires in July
2009.
The facility is secured by first priority liens on certain of
the existing and future rigs, accounts receivable, inventory and
related insurance of our subsidiary, Pride Offshore, Inc.
(“Pride Offshore”) (the borrower under the facility)
and its subsidiaries, all of the equity of Pride Offshore and
its domestic subsidiaries and 65% of the equity of certain of
our foreign subsidiaries. We and certain of our domestic
subsidiaries have guaranteed the obligations of Pride Offshore
under the facility. We generally are required to repay the
revolving loans, with a permanent reduction in availability
under the revolving credit facility, with proceeds from a sale
of or a casualty event with respect to collateral. The facility
contains a number of covenants restricting, among other things,
redemption and repurchase of our indebtedness; distributions,
dividends and repurchases of capital stock and other equity
interests; acquisitions
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Pride
International, Inc.
Notes to
Consolidated Financial
Statements — (Continued)
and investments; asset sales; capital expenditures;
indebtedness; liens and affiliate transactions. The facility
also contains customary events of default, including with
respect to a change of control.
During 2005, we repaid the senior secured term loan in full and
recognized charges of $3.6 million to write off the
unamortized portion of the deferred finance costs at the time of
the early repayment.
Borrowings under the revolving credit facility are available for
general corporate purposes. We may obtain up to
$100.0 million of letters of credit under the facility. As
of December 31, 2006, there were $50.0 million of
borrowings and $19.2 million of letters of credit
outstanding under the facility. As of December 31, 2006,
the interest rate on the senior secured revolving credit
facility was 5.9%, and availability was $430.8 million.
In July 2004, we completed an offering of $500.0 million
principal amount of
73/8% Senior
Notes due 2014. The notes bear interest at 7.375% per
annum. The notes contain provisions that limit our ability to
enter into transactions with affiliates; pay dividends or make
other restricted payments; incur debt or issue preferred stock;
incur dividend or other payment restrictions affecting our
subsidiaries; sell assets; engage in sale and leaseback
transactions; create liens; and consolidate, merge or transfer
all or substantially all of our assets. Many of these
restrictions will terminate if the notes are rated investment
grade by either Standard & Poor’s Ratings Services
or Moody’s Investors Service, Inc. and, in either case, the
notes have a specified minimum rating by the other rating
agency. We are required to offer to repurchase the notes in
connection with specified change in control events that result
in a ratings decline. The notes are subject to redemption, in
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