Document/ExhibitDescriptionPagesSize 1: 10-K Transocean 10-K 12-31-2006 HTML 1.80M
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(Exact
name of registrant as specified in its charter)
_________________
Cayman
Islands
66-0582307
(State
or other jurisdiction of incorporation or
organization)
(I.R.S.
Employer Identification No.)
4
Greenway Plaza
77046
Houston,
Texas
(Zip
Code)
(Address
of principal executive offices)
Registrant’s
telephone number, including area code: (713) 232-7500
Securities
registered pursuant to Section 12(b) of the Act:
Title
of class
Exchange
on which registered
Ordinary
Shares, par value $0.01 per share
New
York Stock Exchange, Inc.
Securities
registered pursuant to Section 12(g) of the Act: None
Indicate
by check mark whether the registrant is a well-known seasoned issuer, as defined
in Rule 405 of the Securities Act.
Yes
x
No
o
Indicate
by check mark if the registrant is not required to file reports pursuant to
Section 13 or Section 15(d) of the Exchange Act.
Yes
o
No
x
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 x
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.
Large
accelerated filer x
Accelerated
filer o
Non-accelerated
filer o
Indicate
by check mark whether the registrant is a shell company (as defined by Rule
12b-2 of the Exchange Act). Yes o
No
x
As
of
June 30, 2006, 319,904,208 ordinary shares were outstanding and the aggregate
market value of such shares held by non-affiliates was approximately $25.7
billion (based on the reported closing market price of the ordinary shares
on
such date of $80.32 and assuming that all directors and executive officers
of
the Company are “affiliates,” although the Company does not acknowledge that any
such person is actually an “affiliate” within the meaning of the federal
securities laws). As of February 23, 2007, 292,967,692 ordinary shares were
outstanding.
Portions
of the registrant's definitive Proxy Statement to be filed with the Securities
and Exchange Commission within 120 days of December 31, 2006, for its 2007
annual general meeting of shareholders, are incorporated by reference into
Part
III of this Form 10-K.
The
statements included in this annual report regarding future financial performance
and results of operations and other statements that are not historical facts
are
forward-looking statements within the meaning of Section 27A of the Securities
Act of 1933 and Section 21E of the Securities Exchange Act of 1934.
Forward-looking statements in this annual report include, but are not limited
to, statements about the following subjects:
the
effect and results of litigation, audits and contingencies,
and
·
other
factors discussed in this annual report and in the Company’s other filings
with the SEC, which are available free of charge on the SEC’s website at
www.sec.gov.
Should
one or more of these risks or uncertainties materialize, or should underlying
assumptions prove incorrect, actual results may vary materially from those
indicated.
All
subsequent written and oral forward-looking statements attributable to the
Company or to persons acting on our behalf are expressly qualified in their
entirety by reference to these risks and uncertainties. You should not place
undue reliance on forward-looking statements. Each forward-looking statement
speaks only as of the date of the particular statement, and we undertake no
obligation to publicly update or revise any forward-looking
statements.
Transocean
Inc. (together with its subsidiaries and predecessors, unless the context
requires otherwise, “Transocean,” the “Company,”“we,”“us” or “our”) is a
leading international provider of offshore contract drilling services for oil
and gas wells. As of February 2, 2007, we owned, had partial ownership interests
in or operated 82 mobile offshore drilling units. As of this date, our fleet
included 33 High-Specification semisubmersibles and drillships
(“High-Specification Floaters”), 20 Other Floaters, 25 Jackups and four Other
Rigs. We also have three High-Specification Floaters under
construction.
Our
mobile offshore drilling fleet is considered one of the most modern and
versatile fleets in the world. Our primary business is to contract these
drilling rigs, related equipment and work crews primarily on a dayrate basis
to
drill oil and gas wells. We specialize in technically demanding segments of
the
offshore drilling business with a particular focus on deepwater and harsh
environment drilling services. We also provide additional services, including
integrated services. Our ordinary shares are listed on the New York Stock
Exchange under the symbol “RIG.”
Transocean
Inc. is a Cayman Islands exempted company with principal executive offices
in
the U.S. located at 4 Greenway Plaza, Houston, Texas77046. Our telephone number
at that address is (713) 232-7500.
On
January 31, 2001, we completed our merger transaction (the “R&B Falcon
merger”) with R&B Falcon Corporation (“R&B Falcon”). At the time of the
R&B Falcon merger, R&B Falcon operated a diverse global drilling rig
fleet, consisting of drillships, semisubmersibles, jackup rigs and other units
in addition to the Gulf of Mexico Shallow and Inland Water segment fleet.
R&B Falcon and the Gulf of Mexico Shallow and Inland Water segment later
became known as TODCO (together with its subsidiaries and predecessors, unless
the context requires otherwise, “TODCO”). In preparation for the initial public
offering of TODCO, we transferred all assets and subsidiaries out of TODCO
that
were unrelated to the Gulf of Mexico Shallow and Inland Water business.
In
February 2004, we completed an initial public offering (the “TODCO IPO”) of
approximately 23 percent of TODCO’s outstanding shares of its common stock. In
September 2004, December 2004 and May 2005, respectively, we completed
additional public offerings of TODCO common stock. In June 2005, we completed
a
sale of our remaining TODCO common stock pursuant to Rule 144 under the
Securities Act of 1933, as amended.
For
information about the revenues, operating income, assets and other information
relating to our business and the geographic areas in which we operate, see
“Item
7. Management’s Discussion and Analysis of Financial Condition and Results of
Operations” and Note 21—Segments, Geographical Analysis and Major Customers to
our consolidated financial statements included in Item 8 of this report.
We
principally operate three types of drilling rigs:
·
drillships;
·
semisubmersibles;
and
·
jackups.
Also
included in our fleet are barge drilling rigs and a mobile offshore production
unit.
Most
of
our drilling equipment is suitable for both exploration and development
drilling, and we normally engage in both types of drilling activity. Likewise,
most of our drilling rigs are mobile and can be moved to new locations in
response to client demand. All of our mobile offshore drilling units are
designed for operations away from port for extended periods of time and most
have living quarters for the crews, a helicopter landing deck and storage space
for pipe and drilling supplies.
As
of
February 2, 2007, our fleet of 82 rigs, which excludes assets held for sale
and
rigs under construction, included:
·
33
High-Specification Floaters, which are comprised of:
-
13
Fifth-Generation Deepwater Floaters;
-
16
Other Deepwater Floaters; and
-
four
Other High-Specification Floaters;
·
20
Other Floaters;
·
25
Jackups; and
·
four
Other Rigs, which are comprised of:
-
two
barge drilling rigs;
-
one
mobile offshore production unit; and
-
one
coring drillship.
As
of
February 2, 2007, our fleet was located in the Far East (14 units), India (12
units), U.S. Gulf of Mexico (11 units), United Kingdom (10 units), Nigeria
(eight units), the Mediterranean and Middle East (seven units), Brazil (six
units), Norway (five units), other West African countries (five units),
Australia (one unit), Canada (one unit), the Caspian Sea (one unit) and
Venezuela (one unit).
We
categorize our fleet as follows: (i) “High-Specification Floaters,” consisting
of our “Fifth-Generation Deepwater Floaters,”“Other Deepwater Floaters” and
“Other High-Specification Floaters,” (ii) “Other Floaters,” (iii) “Jackups” and
(iv) “Other Rigs.” Within our High-Specification Floaters category, we consider
our Fifth-Generation Deepwater Floaters to be the semisubmersibles
Deepwater
Horizon,
Cajun
Express,
Deepwater
Nautilus,
Sedco
Energy
and
Sedco
Express
and
the
drillships Deepwater
Discovery,
Deepwater
Expedition,
Deepwater
Frontier,
Deepwater
Millennium,
Deepwater
Pathfinder,
Discoverer
Deep Seas,
Discoverer
Enterprise
and
Discoverer
Spirit.
These
rigs were built in the construction cycle that occurred from approximately
1996
to 2001 and have high-pressure mud pumps and a water depth capability of 7,500
feet or greater. The Other Deepwater Floaters are generally those other
semisubmersible
rigs and drillships that have a water depth capacity of at least 4,500 feet.
The
Other High-Specification Floaters, built as fourth-generation rigs in the mid
to
late 1980s, are capable of drilling in harsh environments and have greater
displacement than previously constructed rigs resulting in larger variable
load
capacity, more useable deck space and better motion characteristics. The Other
Floaters category is generally comprised of those non-high-specification
floaters with a water depth capacity of less than 4,500 feet. The Jackups
category consists of our jackup fleet, and the Other Rigs category consists
of
other rigs that are of a different type or use. These categories reflect how
we
view, and how we believe our investors and the industry generally view our
fleet.
Drillships
are generally self-propelled, shaped like conventional ships and are the most
mobile of the major rig types. All of our drillships are dynamically positioned,
which allows them to maintain position without anchors through the use of their
onboard propulsion and station-keeping systems. Drillships typically have
greater load capacity than early generation semisubmersible rigs. This enables
them to carry more supplies on board, which often makes them better suited
for
drilling in remote locations where resupply is more difficult. However,
drillships are typically limited to calmer water conditions than those in which
semisubmersibles can operate. Our three existing Enterprise-class drillships
include our patented dual-activity technology. Dual-activity technology includes
structures and techniques for using two drilling stations within a single
derrick to perform drilling tasks. Dual-activity technology allows our rigs
to
perform simultaneous drilling tasks in a parallel rather than sequential manner.
Dual-activity technology reduces critical path activity and improves efficiency
in both exploration and development drilling.
During
2006, we were awarded drilling contracts requiring the construction of three
enhanced Enterprise-class drillships. The newbuilds are expected to be placed
in
service and commence operations during the second quarter of 2009, mid-2009
and
the first quarter of 2010. Newbuilds are included in our drilling fleet upon
testing and acceptance of the rig. See “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations -
Outlook.”
Semisubmersibles
are floating vessels that can be submerged by means of a water ballast system
such that the lower hulls are below the water surface during drilling
operations. These rigs are capable of maintaining their position over the well
through the use of an anchoring system or a computer controlled dynamic
positioning thruster system. Some semisubmersible rigs are self-propelled and
move between locations under their own power when afloat on pontoons although
most are relocated with the assistance of tugs. Typically, semisubmersibles
are
better suited for operations in rougher water conditions than drillships. Our
three Express-class semisubmersibles are designed for mild environments and
are
equipped with the unique tri-act derrick, which was designed to reduce overall
well construction costs.
Jackup
rigs are mobile self-elevating drilling platforms equipped with legs that can
be
lowered to the ocean floor until a foundation is established to support the
drilling platform. Once a foundation is established, the drilling platform
is
then jacked further up the legs so that the platform is above the highest
expected waves. These rigs are generally suited for water depths of 300 feet
or
less.
Depending
on market conditions, we may “warm stack” or “cold stack” non-contracted rigs.
“Warm stacked” rigs are not under contract and may require the hiring of
additional crew, but are generally ready for service with little or no capital
expenditures and are being actively marketed. “Cold stacked” rigs are not
actively marketed on short or near term contracts, generally cannot be
reactivated upon short notice and normally require the hiring of most of the
crew, a maintenance review and possibly significant refurbishment before they
can be reactivated. Cold stacked rigs and some warm stacked rigs would require
additional costs to return to service. The actual cost, which could fluctuate
over time, is dependent upon various factors, including the availability and
cost of shipyard facilities, cost of equipment and materials and the extent
of
repairs and maintenance that may ultimately be required. For some of these
rigs,
the cost could be significant. We would take these factors into consideration
together with market conditions, length of contract and dayrate and other
contract terms in deciding whether to return a particular idle rig to service.
We may consider marketing cold stacked rigs for alternative uses, including
as
accommodation units, from time to time until drilling activity increases and
we
obtain drilling contracts for these units.
High-Specification
Floaters
(33)
The
following tables provide certain information regarding our High-Specification
Floaters as of February 2, 2007:
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
(b)
Dynamically
positioned.
(c)
Enterprise-class
rig.
(d)
Express-class
rig.
(e)
The
Deepwater
Nautilus was
previously leased from its owner, an unrelated third party, pursuant
to a
fully defeased lease arrangement. We terminated the lease and purchased
the rig in December 2006.
(f)
In
the fourth quarter of 2005, we entered into agreements with clients
to
upgrade two of our Sedco
700-series
semisubmersible rigs in our Other Floaters fleet, the Sedco
702 and
Sedco 706,at
a cost expected to be approximately $300 million for each rig. A
rig is
counted within the upgraded rig class and removed from the prior
rig class
when it enters the shipyard to begin upgrade work. The Sedco
702
entered the shipyard for the upgrade in early
2006.
Other
Floaters
(20)
The
following table provides certain information regarding our Other Floaters as
of
February 2, 2007:
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
(b)
In
the fourth quarter of 2005, we entered into agreements with clients
to
upgrade two of our Sedco
700-series
semisubmersible rigs in our Other Floaters fleet, the Sedco
702 and
Sedco706,
at a cost expected to be approximately $300 million for each rig.
A rig is
counted within the upgraded rig class and removed from the prior
rig class
when it enters the shipyard to begin upgrade work. The Sedco
706
upgrade is scheduled to commence in the third quarter of 2007.
Jackups
(25)
The
following table provides certain information regarding our Jackups fleet as
of
February 2, 2007:
Water
Drilling
Year
Entered
Depth
Depth
Service/
Capacity
Capacity
Name
Upgraded(a)
(in
feet)
(in
feet)
Location
Trident
IX
1982
400
21,000
Vietnam
Trident
17
1983
355
25,000
Vietnam
Trident
20
2000
350
25,000
Caspian
Sea
Harvey
H. Ward
1981
300
25,000
Malaysia
J.
T. Angel
1982
300
25,000
Singapore
Roger
W. Mowell
1982
300
25,000
Malaysia
Ron
Tappmeyer
1978
300
25,000
India
D.
R. Stewart
1980
300
25,000
Italy
Randolph
Yost
1979
300
25,000
India
C.
E. Thornton
1974
300
25,000
India
F.
G. McClintock
1975
300
25,000
India
Shelf
Explorer
1982
300
25,000
Malaysia
Transocean
III
1978/1993
300
20,000
Egypt
Transocean
Nordic
1984
300
25,000
India
Trident
II
1977/1985
300
25,000
India
Trident
IV
1980/1999
300
25,000
Nigeria
Trident
VIII
1981
300
21,000
Nigeria
Trident
XII
1982/1992
300
25,000
India
Trident
XIV
1982/1994
300
20,000
Cameroon
Trident
15
1982
300
25,000
Thailand
Trident
16
1982
300
25,000
Thailand
George
H. Galloway
1984
300
25,000
Italy
Transocean
Comet
1980
250
20,000
Egypt
Transocean
Mercury
1969/1998
250
20,000
Egypt
Trident
VI
1981
220
21,000
Vietnam
______________________________
(a)
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
Other
Rigs
In
addition to our floaters and jackups, we also own or operate several other
types
of rigs. These rigs include two drilling barges, a mobile offshore production
unit and a coring drillship.
Our
operations are geographically dispersed in oil and gas exploration and
development areas throughout the world. Rigs can be moved from one region to
another, but 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.
However, significant variations between regions do not tend to exist long-term
because of rig mobility. Consequently, we operate in a single, global offshore
drilling market. Because our drilling rigs are mobile assets and are able to
be
moved according to prevailing market conditions, we cannot predict the
percentage of our revenues that will be derived from particular geographic
or
political areas in future periods.
In
recent
years, there has been increased emphasis by oil companies on exploring for
hydrocarbons in deeper waters. This is, in part, because of technological
developments that have made such exploration more feasible and cost-effective.
For this reason, water-depth capability is a key component in determining rig
suitability for a particular drilling project. Another distinguishing feature
in
some drilling market sectors is a rig’s ability to operate in harsh
environments, including extreme marine and climatic conditions and temperatures.
The
deepwater and mid-water market sectors are serviced by our semisubmersibles
and
drillships. While the use of the term “deepwater” as used in the drilling
industry to denote a particular sector of the market can vary and continues
to
evolve with technological improvements, we generally view the deepwater market
sector as that which begins in water depths of approximately 4,500 feet and
extends to the maximum water depths in which rigs are capable of drilling,
which
is currently approximately 10,000 feet. We view the mid-water market sector
as
that which covers water depths of about 300 feet to approximately 4,500 feet.
The
global jackup market sector begins at the outer limit of the transition zone
and
extends to water depths of about 300 feet. This sector has been developed to
a
significantly greater degree than the deepwater market sector because the
shallower water depths have made it much more accessible than the deeper water
market sectors.
The
“transition zone” market sector is characterized by marshes, rivers, lakes,
shallow bay and coastal water areas. We operate in this sector using our
drilling barges located in Southeast Asia.
Operating
Revenues and Long-Lived Assets by
Country
Operating
revenues and long-lived assets by country are as follows (in
millions):
Other
Countries represents countries in which we operate that individually
had
operating revenues or long-lived assets representing less than 10
percent
of total operating revenues earned or total long-lived assets for
any of
the periods presented.
From
time
to time, we provide well and logistics services in addition to our normal
drilling services through third party contractors and our employees. We refer
to
these other services as integrated services. The work generally consists of
individual contractual agreements to meet specific client needs and may be
provided on either a dayrate, cost plus or fixed price basis depending on the
daily activity. As of February 28, 2007, we were performing such services in
India. These integrated service revenues did not represent a material portion
of
our revenues for any period presented.
Our
contracts to provide offshore drilling services are individually negotiated
and
vary in their terms and provisions. We obtain most of our contracts through
competitive bidding against other contractors. Drilling contracts generally
provide for payment on a dayrate basis, with higher rates while the drilling
unit is operating and lower rates for periods of mobilization or when drilling
operations are interrupted or restricted by equipment breakdowns, adverse
environmental conditions or other conditions beyond our control.
A
dayrate
drilling contract generally extends over a period of time covering either the
drilling of a single well or group of wells or covering a stated term. These
contracts typically can be terminated by the client under various circumstances
such as the loss or destruction of the drilling unit or the suspension of
drilling operations for a specified period of time as a result of a breakdown
of
major equipment. Many of these events are beyond our control. The contract
term
in some instances may be extended by the client exercising options for the
drilling of additional wells or for an additional term. Our contracts also
typically include a provision that allows the client to extend the contract
to
finish drilling a well-in-progress. In reaction to depressed market conditions,
our clients may seek renegotiation of firm drilling contracts to reduce their
obligations or may seek to suspend or terminate their contracts. Some drilling
contracts permit the customer to terminate the contract at the customer's option
without paying a termination fee. Suspension of drilling contracts results
in
the reduction in or loss of dayrate 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 results of
operations.
We
engage
in offshore drilling for most of the leading international oil companies (or
their affiliates), as well as for many government-controlled and independent
oil
companies. Our most significant clients in 2006 were Chevron, BP and Shell
accounting for 14 percent, 11 percent and 11 percent, respectively, of our
2006
operating revenues. No other client accounted for 10 percent or more of our
2006
operating revenues. The loss of any of these significant clients could, at
least
in the short term, have a material adverse effect on our results of
operations.
Our
operations are affected from time to time in varying degrees by governmental
laws and regulations. The drilling industry is dependent on demand for services
from the oil and gas exploration industry and, accordingly, is affected by
changing tax and other laws generally relating to the energy
business.
International
contract drilling operations are subject to various laws and regulations in
countries in which we operate, including laws and regulations relating to the
equipping and operation of drilling units, currency conversions and
repatriation, oil and gas exploration and development, taxation of offshore
earnings and earnings of expatriate personnel and use of local employees and
suppliers by foreign contractors. Governments in some foreign countries are
active in regulating and controlling the ownership of concessions and companies
holding concessions, the exportation of oil and gas and other aspects of the
oil
and gas industries in their countries. In addition, government action, including
initiatives by the Organization of Petroleum Exporting Countries (“OPEC”), may
continue to cause oil price volatility. In some areas of the world, this
governmental activity has adversely affected the amount of exploration and
development work done by major oil companies and may continue to do so.
In
the
U.S., regulations applicable to our operations include certain regulations
controlling the discharge of materials into the environment and requiring the
removal and cleanup of materials that may harm the environment or otherwise
relating to the protection of the environment.
The
U.S.
Oil Pollution Act of 1990 (“OPA”) and related regulations impose a variety of
requirements on “responsible parties” related to the prevention of oil spills
and liability for damages resulting from such spills. Few defenses exist to
the
liability imposed by OPA, and such liability could be substantial. Failure
to
comply with ongoing requirements or inadequate cooperation in a spill event
could subject a responsible party to civil or criminal enforcement action.
The
U.S.
Outer Continental Shelf Lands Act (“OCSLA”) authorizes regulations relating to
safety and environmental protection applicable to lessees and permittees
operating on the outer continental shelf. Included among these are regulations
that require the preparation of spill contingency plans and establish air
quality standards for certain pollutants, including particulate matter, volatile
organic compounds, sulfur dioxide, carbon monoxide and nitrogen oxides. Specific
design and operational standards may apply to outer continental shelf vessels,
rigs, platforms, vehicles and structures. Violations of environmental related
lease conditions or regulations issued pursuant to OCSLA can result in
substantial civil and criminal penalties, as well as potential court injunctions
curtailing operations and canceling leases. Such enforcement liabilities can
result from either governmental or citizen prosecution.
The
U.S.
Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”),
also known as the “Superfund” law, imposes liability without regard to fault or
the legality of the original conduct on some classes of persons that are
considered to have contributed to the release of a “hazardous substance” into
the environment. These persons include the owner or operator of a facility
where
a release occurred and companies that disposed or arranged for the disposal
of
the hazardous substances found at a particular site. Persons who are or were
responsible for releases of hazardous substances under CERCLA may be subject
to
joint and several liability for the costs of cleaning up the hazardous
substances that have been released into the environment and for damages to
natural resources. It is not uncommon for third parties to file claims for
personal injury and property damage allegedly caused by the hazardous substances
released into the environment.
Many
of
the other countries in whose waters we are presently operating or may operate
in
the future have regulations covering the discharge of oil and other contaminants
in connection with drilling operations.
Governmental
authorities in the U.S. are also reviewing various regulations relating to
rig
mooring requirements, particularly in the aftermath of the hurricane activity
in
2005 in the Gulf of Mexico. We and the drilling industry are working with the
pertinent authorities as part of this process.
Although
significant capital expenditures may be required to comply with various
governmental laws and regulations, such compliance to date has not materially
adversely affected our earnings or competitive position.
We
require highly skilled personnel to operate our drilling units. As a result,
we
conduct extensive personnel recruiting, training and safety programs. At January31, 2007, we had approximately 10,700 employees and we also utilized
approximately 1,800 persons through contract labor providers. As of such date,
approximately 15 percent of our employees and contract labor worldwide worked
under collective bargaining agreements, most of whom worked in the U.K., Nigeria
and Norway. Of these represented individuals, 60 percent are working under
agreements that are subject to salary negotiation in 2007. These negotiations
could result in higher personnel expenses, other increased costs or increased
operating restrictions.
Our
website address iswww.deepwater.com.
We
make
our website content available for information purposes only. It should not
be
relied upon for investment purposes, nor is it incorporated by reference in
this
Form 10-K.We
make
available on this website under “Investor Relations-SEC Filings,” free of
charge, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and amendments to those reports as soon as reasonably
practicable after we electronically file those materials with, or furnish those
materials to, the Securities and Exchange Commission (“SEC”). The SEC also
maintains a website at www.sec.gov
that
contains reports, proxy statements and other information regarding SEC
registrants, including us.
You
may
also find information related to our corporate governance, board committees
and
company code of ethics at our website. Among the information you can find there
is the following:
·
Corporate
Governance Guidelines;
·
Audit
Committee Charter;
·
Corporate
Governance Committee Charter;
·
Executive
Compensation Committee Charter;
·
Finance
and Benefits Committee Charter; and
·
Code
of Ethics.
We
intend
to satisfy the requirement under Item 5.05 of Form 8-K to disclose any
amendments to our Code of Ethics and any waiver from a provision of our Code
of
Ethics by posting such information in the Corporate Governance section of our
website at www.deepwater.com.
Our
business depends on the level of activity in the offshore oil and gas industry,
which is significantly affected by volatile oil and gas prices and other
factors.
Our
business depends on the level of activity in oil and gas exploration,
development and production in market sectors worldwide, with the U.S. and
international offshore areas being our primary market sectors. Oil and gas
prices and market expectations of 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'
expectations of future commodity prices typically drive demand for our rigs.
Also, increased competition for our customers’ drilling budgets could come from,
among other areas, land-based energy markets in Africa, Russia, other former
Soviet Union States, the Middle East and Alaska. 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 campaigns. Worldwide military, political and economic events
have contributed to oil and gas price volatility and are likely to do so in
the
future. Oil and gas prices are extremely volatile and are affected by numerous
factors, including the following:
·
worldwide
demand for oil and gas,
·
the
ability of OPEC to set and maintain production levels and
pricing,
·
the
level of production in non-OPEC
countries,
·
the
policies of various governments regarding exploration and development
of
their oil and gas reserves,
·
advances
in exploration and development technology, and
·
the
worldwide military and political environment, including uncertainty
or
instability resulting from an escalation or additional outbreak of
armed
hostilities or other crises in the Middle East or other geographic
areas
or further acts of terrorism in the United States, or elsewhere.
Our
industry is highly competitive and cyclical, with intense price
competition.
The
offshore contract drilling industry is highly competitive with numerous industry
participants, none of which has a dominant market share. Drilling contracts
are
traditionally awarded on a competitive bid basis. Intense price competition
is
often the primary factor in determining which qualified contractor is awarded
a
job, although rig availability and the quality and technical capability of
service and equipment may also be considered. Mergers among oil and natural
gas
exploration and production companies have reduced the number of available
customers.
Our
industry has historically been cyclical and is impacted by oil and gas price
levels and volatility. There have been periods of high demand, short rig supply
and high dayrates, followed by periods of low demand, excess rig supply and
low
dayrates. Changes in commodity prices can have a dramatic effect on rig demand,
and periods of excess rig supply intensify the competition in the industry
and
often result in rigs being idle for long periods of time. We may be required
to
idle rigs or enter into lower rate contracts in response to market conditions
in
the future.
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
typically resulted in an oversupply of drilling units and has caused a
subsequent decline in utilization and dayrates, sometimes for extended periods
of time. There are numerous high-specification rigs and jackups under contract
for construction and mid-water semisubmersibles that are being upgraded to
enhance their operating capability. The entry into service of these new and
upgraded units will increase supply and could curtail a further strengthening
of
dayrates, or reduce them, in the affected markets or result in a softening
of
the affected markets as rigs are absorbed into the active fleet. Any further
increase in construction of new drilling units would likely exacerbate the
negative impact on utilization and dayrates. Lower utilization and dayrates
in
one or more of the regions in which we operate could adversely affect our
revenues and profitability. Prolonged periods of low utilization and dayrates
could also result in the recognition of impairment charges on certain classes
of
our drilling rigs or our goodwill balance if future cash flow estimates, based
upon information available to management at the time, indicate that the carrying
value of these rigs, or the goodwill balance, may not be
recoverable.
Our
operations are subject to the usual hazards inherent in the drilling of oil
and
gas wells, such as blowouts, reservoir damage, loss of production, loss of
well
control, punch-throughs, craterings, fires and natural disasters such as
hurricanes and tropical storms. The occurrence of these events could result
in
the suspension of drilling operations, damage to or destruction of the equipment
involved and injury or death to rig personnel. We may also be subject to
personal injury and other claims of rig personnel as a result of our drilling
operations. Operations also may be suspended because of machinery breakdowns,
abnormal drilling conditions, and failure of subcontractors to perform or supply
goods or services or personnel shortages. In addition, offshore drilling
operations are subject to perils peculiar to marine operations, including
capsizing, grounding, collision and loss or damage from severe weather. Damage
to the environment could also result from our operations, particularly through
oil spillage or extensive uncontrolled fires. We may also be subject to
property, environmental and other damage claims by oil and gas companies. Our
insurance policies and contractual rights to indemnity may not adequately cover
losses, and we do not have insurance coverage or rights to indemnity for all
risks.
Consistent
with standard industry practice, our clients generally assume, and indemnify
us
against, well control and subsurface risks under dayrate contracts. These risks
are those associated with the loss of control of a well, such as blowout or
cratering, the cost to regain control or redrill the well and associated
pollution. However, there can be no assurance that these clients will
necessarily be financially able to indemnify us against all these risks. Also,
we may be effectively prevented from enforcing these indemnities because of
the
nature of our relationship with some of our larger clients.
We
have
historically maintained broad insurance coverages, including coverages for
property damage, occupational injury and illness, and general and marine
third-party liabilities. Property damage insurance covers against marine and
other perils, including losses due to capsizing, grounding, collision, fire,
lightning, hurricanes, wind, storms, action of waves, punch-throughs, cratering,
blowouts, explosion and war risks. We currently insure all of our offshore
drilling equipment for general and third party liabilities, occupational and
illness risks, and property damage. We also generally insure all of our offshore
drilling rigs against property damage but the amount of such insurance may
be
less than the fair market value, replacement cost and net carrying value for
financial reporting purposes.
In
accordance with industry practices, we believe we are adequately insured for
normal risks in our operations; however, such insurance coverage would not
in
all situations provide sufficient funds to protect us from all liabilities
that
could result from our drilling operations. Our coverage includes annual
aggregate limits on losses due to hurricanes. As a result, we retain the risk
through self-insurance for any losses in excess of these limits. We do not
carry
insurance for loss of revenue and certain other claims may not be reimbursed
by
insurance carriers. Such lack of reimbursement may cause us to incur substantial
costs. In addition, we could decide to retain substantially more risk through
self-insurance.
Failure
to retain key personnel could hurt our operations.
We
require highly skilled personnel to operate and provide technical services
and
support for our drilling units. As demand for drilling services and the size
of
the worldwide industry fleet increases, we have begun to see shortages of
qualified personnel in the industry, creating upward pressure on wages and
possibly higher turnover. If turnover increases, we could see a reduction
in the
experience level of our personnel, which could lead to higher downtime and
more
operating incidents, which in turn could decrease revenues and increase costs.
We are increasing efforts in our recruitment, training, development and
retention programs as required to meet our anticipated personnel
needs.
Our
labor costs and the operating restrictions under which we operate could
increase
as a result of collective bargaining negotiations and changes in labor
laws and
regulations.
On
January 31, 2007, approximately 15 percent of our employees and contracted
labor
worldwide worked under collective bargaining agreements, most of whom worked
in
the U.K., Nigeria and Norway. Of these represented individuals, approximately
60
percent are working under agreements that are subject to salary negotiation
in
2007. These negotiations could result in higher personnel expenses, other
increased costs or increased operating restrictions. Additionally, the
unions in the U.K. are seeking an interpretation of the Offshore Working
Directive, which was recently extended to include U.K. offshore workers,
that
could result in higher labor costs and undermine our ability to obtain
a
sufficient number of skilled workers in the U.K.
Our
shipyard projects are subject to delays and cost
overruns.
We
have
committed to three deepwater newbuild rig projects and two Sedco
700-series
rig upgrades, and we are discussing other potential newbuild
opportunities with several clients. We also have a variety of other more
limited
shipyard projects at any given time. Our shipyard projects are subject to
the
risks of delay or cost overruns inherent in any such construction project
resulting from numerous factors, including the following:
·
shipyard
unavailability;
·
shortages
of equipment, materials or skilled
labor;
·
unscheduled
delays in the delivery of ordered materials and
equipment;
·
engineering
problems, including those relating to the commissioning of newly
designed
equipment;
·
work
stoppages;
·
client
acceptance delays;
·
weather
interference or storm damage;
·
unanticipated
cost increases; and
·
difficulty
in obtaining necessary permits or
approvals.
These
factors may contribute to cost variations and delays in the delivery of
our
upgraded and newbuild units and other rigs undergoing shipyard projects.
Delays
in the delivery of these units would result in delay in contract commencement,
resulting in a loss of revenue to us, and may also cause our customer to
terminate or shorten the term of the drilling contract for the rig pursuant
to
applicable late delivery clauses. In the event of termination of one of
these
contracts, we may not be able to secure a replacement contract on as favorable
terms.
A
loss of a major tax dispute or a successful tax challenge to our structure
could
result in a significant loss or in a higher tax rate on our worldwide earnings
or both.
We
are a
Cayman Islands company and also operate through various subsidiaries around
the
world. Our income tax returns are subject to review and examination in the
various jurisdictions in which we operate. We accrue for income tax
contingencies that we believe are probable exposures and our income taxes are
based upon how we are structured in countries around the world. If any country,
including the U.S. and Norway, successfully challenges our income tax filings
based on our operational structure there, or if we otherwise lose a material
dispute, our effective tax rate on our worldwide earnings could increase
substantially and our financial results could be materially adversely affected.
See “Item 7. Management’s Discussion and Analysis of Financial Condition and
Results of Operations—Outlook-Tax Matters” and “—Critical Accounting
Estimates-Income Taxes.”
A
change in tax laws, or their interpretation, of any country in which we operate
could result in a higher tax rate on our worldwide
earnings.
We
operate worldwide through our various subsidiaries. Consequently, we are
subject
to changing tax laws and policies in the jurisdictions in which we operate,
which could include laws or policies directed toward companies organized
in
jurisdictions with low tax rates. A material change in the tax laws or policies,
or their interpretation, of any country in which we have significant operations
could result in a higher effective tax rate on our worldwide earnings. In
addition, our income tax returns are subject to review and examination in
various jurisdictions in which we operate. See “Item 7. Management’s Discussion
and Analysis of Financial Condition and Results of Operations—Outlook-Tax
Matters” and “—Critical Accounting Estimates-Income Taxes.”
Our
non-U.S. operations involve additional risks not associated with our U.S.
operations.
We
operate in various regions throughout the world that may expose us to political
and other uncertainties, including risks of:
·
terrorist
acts, war and civil disturbances;
·
expropriation
or nationalization of equipment;
and
·
the
inability to repatriate income or
capital.
We
are
protected to a substantial extent against loss of capital assets, but generally
not loss of revenue, from most of these risks through insurance, indemnity
provisions in our drilling contracts, or both. The necessity of insurance
coverage for risks associated with political unrest, expropriation and
environmental remediation for operating areas not covered under our existing
insurance policies is evaluated on an individual contract basis. Although
we
maintain insurance in the areas in which we operate, pollution and environmental
risks generally are not totally insurable. If a significant accident or
other
event occurs and is not fully covered by insurance or an enforceable or
recoverable indemnity from a client, it could adversely affect our consolidated
financial position, results of operations or cash flows. Moreover, no assurance
can be made that we will be able to maintain adequate insurance in the
future at
rates we consider reasonable or be able to obtain insurance against certain
risks, particularly in light of the instability and developments in the
insurance markets following the terrorist attacks of September 11, 2001.
As of
February 28, 2007, all areas in which we were operating were covered by
existing
insurance policies.
Many
governments favor or effectively require the awarding of drilling contracts
to
local contractors or require foreign contractors to employ citizens of,
or
purchase supplies from, a particular jurisdiction. These practices may
adversely
affect our ability to compete.
Our
non-U.S. contract drilling operations are subject to various laws and
regulations in countries in which we operate, including laws and regulations
relating to the equipment and operation of drilling units, currency conversions
and repatriation, oil and gas exploration and development and taxation
of
offshore earnings and earnings of expatriate personnel. Governments in
some
foreign countries have become increasingly active in regulating and controlling
the ownership of concessions and companies holding concessions, the exploration
for oil and gas and other aspects of the oil and gas industries in their
countries. In addition, government action, including initiatives by OPEC,
may
continue to cause oil or gas price volatility. In some areas of the world,
this
governmental activity has adversely affected the amount of exploration
and
development work done by major oil companies and may continue to do
so.
Another
risk inherent in our operations is the possibility of currency exchange
losses
where revenues are received and expenses are paid in nonconvertible currencies.
We may also incur losses as a result of an inability to collect revenues
because
of a shortage of convertible currency available in the country of operation.
Our
operating and maintenance costs do not necessarily fluctuate in proportion
to
changes in operating revenues.
We
do not
expect operating and maintenance costs to necessarily fluctuate in proportion
to
changes in operating revenues. Operating revenues may fluctuate as a function
of
changes in dayrate. However, costs for operating a rig are generally fixed
or
only semi-variable regardless of the dayrate being earned. In addition, should
our rigs incur idle time between contracts, we typically do not de-man those
rigs because we will use the crew to prepare the rig for its next contract.
During times of reduced activity, reductions in costs may not be immediate
as
portions of the crew may be required to prepare our rigs for stacking, after
which time the crew members are assigned to active rigs or dismissed. In
addition, as our rigs are mobilized from one geographic location to another,
the
labor and other operating and maintenance costs can vary significantly. In
general, labor costs increase primarily due to higher salary levels and
inflation. Equipment maintenance expenses fluctuate depending upon the type
of
activity the unit is performing and the age and condition of the equipment.
Contract preparation expenses vary based on the scope and length of contract
preparation required and the duration of the firm contractual period over which
such expenditures are amortized.
Our
drilling contracts may be terminated due to a number of
events.
Our
customers may terminate or suspend some of our term drilling contracts without
paying a termination fee under various circumstances such as the loss or
destruction of the drilling unit, downtime or impaired performance caused
by
equipment or operational issues, some of which are beyond our control, or
sustained periods of downtime due to force majeure events. Suspension of
drilling contracts results in loss of the dayrate 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, it could
adversely affect our results of operations. In reaction to depressed market
conditions, our customers may also seek renegotiation of firm drilling contracts
to reduce their obligations.
Public
health threats could have a material adverse effect on our operations and our
financial results.
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.
Compliance
with or breach of environmental laws can be costly and could limit our
operations.
Our
operations are subject to regulations controlling the discharge of materials
into the environment, requiring removal and cleanup of materials that may harm
the environment or otherwise relating to the protection of the environment.
For
example, as an operator of mobile offshore drilling units in navigable U.S.
waters and some offshore areas, we may be liable for damages and costs incurred
in connection with oil spills related to those operations. Laws and regulations
protecting the environment have become more stringent in recent years, and
may
in some cases impose strict liability, rendering a person liable for
environmental damage without regard to negligence. 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 they
were
performed. The application of these requirements or the adoption of new
requirements could have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
We
have
generally been able to obtain some degree of contractual indemnification
pursuant to which our clients agree to protect and indemnify us against
liability for pollution, well and environmental damages; however, there is
no
assurance that we can obtain such indemnities in all of our contracts or that,
in the event of extensive pollution and environmental damages, our clients
will
have the financial capability to fulfill their contractual obligations to us.
Also, these indemnities may not be enforceable in all instances. In addition,
we
may be effectively prevented from enforcing these indemnities because of the
nature of our relationship with some of our larger clients.
World
political events could affect the markets for drilling
services.
World
political events have resulted in military action in Afghanistan and Iraq and
terrorist attacks and related unrest. Military action by the U.S. or other
nations could escalate and further acts of terrorism may occur in the U.S.
or
elsewhere. Such acts of terrorism could be directed against companies such
as
ours. Such developments have caused instability in the world's financial and
insurance markets in the past. In addition, these developments could lead to
increased volatility in prices for crude oil and natural gas and could affect
the markets for drilling services. Insurance premiums have increased and could
rise further and coverages may be unavailable in the future.
U.S.
government regulations may effectively preclude us from actively engaging in
business activities in certain countries. These regulations could be amended
to
cover countries where we currently operate or where we may wish to operate
in
the future.
The
description of our property included under “Item 1. Business” is incorporated by
reference herein.
We
maintain offices, land bases and other facilities worldwide, including our
principal executive offices in Houston, Texas and regional operational offices
in the U.S., France and Singapore. Our remaining offices and bases are located
in various countries in North America, South America, the Caribbean, Europe,
Africa, Russia, the Middle East, India, the Far East and Australia. We lease
most of these facilities.
Several
of our subsidiaries have been named, along with numerous unaffiliated
defendants, in several complaints that have been filed in the Circuit Courts
of
the State of Mississippi involving over 700 persons that allege personal injury
arising out of asbestos exposure in the course of their employment by some
of
these defendants between 1965 and 1986. The complaints also name as defendants
certain of TODCO's subsidiaries to whom we may owe indemnity. Further, the
complaints name other unaffiliated defendant companies, including companies
that
allegedly manufactured drilling related products containing asbestos. The
complaints allege that the defendant drilling contractors used those
asbestos-containing products in offshore drilling operations, land based
drilling operations and in drilling structures, drilling rigs, vessels and
other
equipment and assert claims based on, among other things, negligence and strict
liability, and claims authorized under the Jones Act. The plaintiffs generally
seek awards of unspecified compensatory and punitive damages. We have not yet
been able to conduct extensive discovery nor determine the number of plaintiffs
that were employed by our subsidiaries or otherwise have any connection with
our
drilling operations. We intend to defend ourselves vigorously and, based on
the
limited information available to us at this time, we do not expect the
liability, if any, resulting from these matters to have a material adverse
effect on our consolidated financial position, results of operations or cash
flows.
In
1990
and 1991, two of our subsidiaries were served with various assessments
collectively valued at approximately $10 million from the municipality of Rio
de
Janeiro, Brazil to collect a municipal tax on services. We believe that neither
subsidiary is liable for the taxes and have contested the assessments in the
Brazilian administrative and court systems. We have received several adverse
rulings by various courts with respect to a June 1991 assessment, which is
valued at approximately $9 million. We are continuing to challenge the
assessment and filed a writ of mandamus to stay execution of a related tax
foreclosure proceeding. The government is currently attempting to enforce the
judgment on this assessment and the amount claimed is approximately $24 million,
which exceeds the amount we believe is at issue. We received a favorable ruling
in connection with a disputed August 1990 assessment, and the government has
lost what is expected to be its final appeal with respect to that ruling. We
also are awaiting a ruling from the Taxpayer's Council in connection with an
October 1990 assessment. If our defenses are ultimately unsuccessful, we believe
that the Brazilian government-controlled oil company, Petrobras, has a
contractual obligation to reimburse us for municipal tax payments. We do not
expect the liability, if any, resulting from these assessments to have a
material adverse effect on our consolidated financial position, results of
operations or cash flows.
The
Indian Customs Department, Mumbai alleged in July 1999 that the initial entry
into India in 1988 and other subsequent movements of the Trident
II
jackup
rig operated by the subsidiary constituted imports and exports for which proper
customs procedures were not followed and sought payment of customs duties of
approximately $31 million based on an alleged 1998 rig value of $49 million,
plus interest and penalties, and confiscation of the rig. In January 2000,
the
Customs Department found that we had imported the rig improperly and
intentionally concealed the import from the authorities, and directed us to
pay
certain other fees and penalties, in addition to the amount of customs duties
owed. We appealed the Customs Department ruling and an appellate tribunal
granted our request that the confiscation be stayed pending the appeal. The
appellate tribunal also found that the rig was originally imported without
proper documentation or payment of duties and sustained our valuation of the
rig
at the time of import as $13 million and ruled that subsequent movements of
the
rig were not liable to import documentation or duties, thus limiting our
exposure as to custom duties to approximately $6 million. The Supreme Court
of
India has affirmed the appellate ruling but the Customs Department has not
agreed with our interpretation of that order. We are contesting their
interpretation. We and our customer agreed to pursue and obtained the issuance
of the required importation documentation from the Ministry of Petroleum that,
if accepted by the Customs Department, would reduce the duty to nil. The Customs
Department did not accept the documentation or agree to refund the duties
already paid. We are pursuing our remedies against the Customs Department and
our customer. We do not expect the liability, if any, resulting from this matter
to have a material adverse effect on our consolidated financial position,
results of operations or cash flows.
One
of
our subsidiaries is involved in an action with respect to customs penalties
relating to the Sedco
710
semisubmersible drilling rig. Prior to our merger with Sedco Forex, this
drilling rig, which was working for Petrobras in Brazil at the time, had been
admitted into the country on a temporary basis under authority granted to a
Schlumberger entity. Prior to the Sedco Forex merger, the drilling contract
was
moved to an entity that would become one of our subsidiaries. In early 2000,
the
drilling contract was extended for another year. On January 10, 2000, the
temporary import permit granted to the Schlumberger entity expired, and renewal
filings were not made until later that January. In April 2000, the Brazilian
customs authorities cancelled the import permit. The Schlumberger entity filed
an action in the Brazilian federal court of Campos for the purpose of extending
the temporary admission. Other proceedings were also initiated in order to
secure the transfer of the temporary admission to our subsidiary. Ultimately,
the court permitted the transfer to our entity but has not ruled that the
temporary admission could be extended without the payment of a financial
penalty. During the first quarter of 2004, the customs office renewed its
efforts to collect a penalty and issued a second assessment for this penalty
but
has now done so against our subsidiary. The assessment is for approximately
$71
million. We believe that the amount of the assessment, even if it were
appropriate, should only be approximately $7 million and should in any event
be
assessed against the Schlumberger entity. We and Schlumberger are contesting
our
respective assessments. We have put Schlumberger on notice that we consider
any
assessment to be the responsibility of Schlumberger. We do not expect the
liability, if any, resulting from this matter to have a material adverse effect
on our consolidated financial position, results of operations or cash
flows.
We
had a
dispute with TODCO concerning payment to us under the tax sharing agreement
that
we entered into with TODCO for the tax benefit that TODCO derives from exercises
of options to purchase our ordinary shares held by employees of TODCO. During
the fourth quarter of 2006, an arbitration proceeding that was initiated in
January 2006 concluded. We were seeking payment of the amount of tax benefits
derived from exercises of options to purchase our ordinary shares by employees
of TODCO who were not on the payroll of TODCO at the time of exercise and a
declaration that TODCO pay us for the benefit derived from such exercises in
the
future. In November 2006, we reached a negotiated settlement with TODCO. As
a
result of the settlement, we entered into an amended and restated tax sharing
agreement with TODCO. Under the terms of the amended and restated agreement,
TODCO will pay us for 55 percent of the value of the tax deductions arising
from
the exercise of options to purchase our ordinary shares by current and former
employees and directors of TODCO. This payment rate applies retroactively to
amounts previously accrued by TODCO and to future payments. Under the terms
of
the amended and restated agreement, TODCO will also receive a $3 million
federal tax benefit for use of certain state and foreign tax assets. The amended
and restated agreement also provides that the change of control provision
contained in the agreement no longer applies to option deductions. However,
if
TODCO uses the option deductions after a change of control, it would be required
to pay us for 55 percent of the value of those deductions. As a result of the
settlement, we recognized other income of $51 million, net of tax, in the
fourth quarter of 2006 that had previously been deferred pending resolution
of
the dispute.
In
the
third quarter of 2006, we received tax assessments of approximately $100 million
from the state tax authorities of Rio de Janeiro in Brazil against one of our
Brazilian subsidiaries for customs taxes on equipment imported into the state
in
connection with our operations. The assessments resulted from a preliminary
finding by these authorities that our subsidiary’s record keeping practices were
deficient. We continue to review documents related to the assessments, and
while
our review is not complete, we currently believe that the substantial majority
of these assessments are without merit. We filed an initial response with the
Rio de Janeiro tax authorities on September 9, 2006 refuting these
additional tax assessments. While we cannot predict or provide assurance as
to
the final outcome of these proceedings, we do not expect it to have a material
adverse effect on our consolidated financial position, results of operations
or
cash flows.
We
are
involved in various tax matters as described in "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations—Outlook—Tax
Matters." We are also involved in a number of other lawsuits, including a labor
dispute involving Hull Blyth workers in Angola previously reported that is
not
material to us, all of which have arisen in the ordinary course of our business.
We do not expect the liability, if any, resulting from these other matters
to
have a material adverse effect on our consolidated financial position, results
of operations or cash flows. We cannot predict with certainty the outcome or
effect of any of the litigation matters specifically described above or of
any
such other pending or threatened litigation. There can be no assurance that
our
beliefs or expectations as to the outcome or effect of any lawsuit or other
litigation matter will prove correct and the eventual outcome of these matters
could materially differ from management's current estimates.
Executive
Vice President and Chief Operating Officer
42
Eric
B. Brown
Senior
Vice President, General Counsel and Corporate Secretary
55
Gregory
L. Cauthen
Senior
Vice President and Chief Financial Officer
49
David
J. Mullen
Senior
Vice President, Marketing and Planning
49
David
A. Tonnel
Vice
President and Controller
37
The
officers of the Company are elected annually by the board of directors. There
is
no family relationship between any of the above-named executive officers.
Robert
L.
Long is Chief Executive Officer and a member of the board of directors of the
Company. Mr. Long served as President and Chief Executive Officer of the Company
and a member of the board of directors from October 2002 to October 2006, at
which time he relinquished the position of President. Mr. Long served as
President of the Company from December 2001 to October 2002. Mr. Long served
as
Chief Financial Officer of the Company from August 1996 until December 2001.
Mr.
Long served as Senior Vice President of the Company from May 1990 until the
time
of the Sedco Forex merger, at which time he assumed the position of Executive
Vice President. Mr. Long also served as Treasurer of the Company from September
1997 until March 2001. Mr. Long has been employed by the Company since 1976
and
was elected Vice President in 1987.
Jean
P.
Cahuzac is President of the Company. Mr. Cahuzac served as Executive Vice
President and Chief Operating Officer of the Company from October 2002 to
October 2006, at which time he assumed his current position. Mr. Cahuzac served
as Executive Vice President, Operations of the Company from February 2001 until
October 2002. Mr. Cahuzac served as President of Sedco Forex from January 1999
until the time of the Sedco Forex merger, at which time he assumed the positions
of Executive Vice President and President, Europe, Middle East and Africa with
the Company. Mr. Cahuzac served as Vice President-Operations Manager of Sedco
Forex from May 1998 to January 1999, Region Manager-Europe, Africa and CIS
of
Sedco Forex from September 1994 to May 1998 and Vice President/General
Manager-North Sea Region of Sedco Forex from February 1994 to September 1994.
He
had been employed by Schlumberger Limited since 1979.
Steven
L.
Newman is Executive Vice President and Chief Operating Officer of the Company.
Mr. Newman served as Senior Vice President of Human Resources and Information
Process Solutions from May 2006 to October 2006, at which time he assumed his
current position. He served as Senior Vice President of Human Resources,
Information Process Solutions and Treasury from March 2005 to May 2006. Mr.
Newman served as Vice President of Performance and Technology of the Company
from August 2003 until March 2005. Mr. Newman served as Region Manager, Asia
Australia from May 2001 until August 2003. From December 2000 to May 2001,
Mr.
Newman served as Region Operations Manager of the Africa-Mediterranean Region
of
the Company. From April 1999 to December 2000, Mr. Newman served in various
operational and marketing roles in the Africa-Mediterranean and U.K. region
offices. Mr. Newman has been employed by the Company since
1994.
Eric
B.
Brown is Senior Vice President, General Counsel and Corporate Secretary of
the
Company. Mr. Brown served as Vice President and General Counsel of the Company
since February 1995 and Corporate Secretary of the Company since
September 1995. He assumed the position of Senior Vice President in
February 2001. Prior to assuming his duties with the Company, Mr. Brown served
as General Counsel of Coastal Gas Marketing Company.
Gregory
L. Cauthen is Senior Vice President and Chief Financial Officer of the Company.
He was also Treasurer of the Company until July 2003. Mr. Cauthen served as
Vice
President, Chief Financial Officer and Treasurer from December 2001 until he
was
elected in July 2002 as Senior Vice President. Mr. Cauthen served as Vice
President, Finance from March 2001 to December 2001. Prior to joining the
Company, he served as President and Chief Executive Officer of WebCaskets.com,
Inc., a provider of death care services, from June 2000 until February 2001.
Prior to June 2000, he was employed at Service Corporation International, a
provider of death care services, where he served as Senior Vice President,
Financial Services from July 1998 to August 1999, Vice President, Treasurer
from
July 1995 to July 1998, was assigned to various special projects from August
1999 to May 2000 and had been employed in various other positions since February
1991.
David
J.
Mullen is Senior Vice President, Marketing and Planning of the Company. Mr.
Mullen served as Vice President of the Company's North and South America Unit
from January 2005 to October 2006, when he assumed his present position.
From May 2001 to January 2005, Mr. Mullen was President of Schlumberger Oilfield
Services for North and South America, and Mr. Mullen served as the Company’s
Vice President of Human Resources from January 2000 to May 2001. Prior to
joining the Company at the time of our merger with Sedco Forex, Mr. Mullen
served in a variety of roles with Schlumberger Limited, where he had been
employed since 1983.
David
A.
Tonnel is Vice President and Controller of the Company. Mr. Tonnel served as
Assistant Controller of the Company from May 2003 to February 2005, at which
time he assumed his current position. Mr. Tonnel served as Finance Manager,
Asia
Australia Region from October 2000 to May 2003 and as Controller, Nigeria from
April 1999 to October 2000. Mr. Tonnel joined the Company in 1996 after working
for Ernst & Young in France as Senior Auditor.
Market
for Registrant's Common Equity, Related Shareholder
Matters
and Issuer Purchases of Equity
Securities
Our
ordinary shares are listed on the New York Stock Exchange (the “NYSE”) under the
symbol “RIG.” The following table sets forth the high and low sales prices of
our ordinary shares for the periods indicated as reported on the NYSE Composite
Tape.
Price
High
Low
2005
First
Quarter
$
51.97
$
39.79
Second
Quarter
58.19
43.16
Third
Quarter
63.11
53.52
Fourth
Quarter
70.93
52.34
2006
First
Quarter
$
84.29
$
70.05
Second
Quarter
90.16
70.75
Third
Quarter
81.63
64.52
Fourth
Quarter
84.23
65.57
On
February 23, 2007, the last reported sales price of our ordinary shares on
the
NYSE Composite Tape was $78.75 per share. On such date, there were 12,434
holders of record of our ordinary shares and 292,967,692 ordinary shares
outstanding.
We
did
not declare or pay a cash dividend in either of the two most recent fiscal
years. Any future declaration and payment of any cash dividends will
(i) depend on our results of operations, financial condition, cash
requirements and other relevant factors, (ii) be subject to the discretion
of the board of directors, (iii) be subject to restrictions contained in
our revolving credit agreement and other debt covenants and (iv) be payable
only out of our profits or share premium account in accordance with Cayman
Islands law.
There
is
currently no reciprocal tax treaty between the Cayman Islands and the United
States. Under current Cayman Islands law, there is no withholding tax on
dividends.
We
are a
Cayman Islands exempted company. Our authorized share capital is $13,000,000,
divided into 800,000,000 ordinary shares, par value $0.01, and 50,000,000
preference shares, par value $0.10, of which shares may be designated and
created as shares of any other classes or series of shares with the respective
rights and restrictions determined by action of our board of directors. On
February 28, 2007, no preference shares were outstanding.
The
holders of ordinary shares are entitled to one vote per share other than on
the
election of directors.
With
respect to the election of directors, each holder of ordinary shares entitled
to
vote at the election has the right to vote, in person or by proxy, the number
of
shares held by him for as many persons as there are directors to be elected
and
for whose election that holder has a right to vote. The directors are divided
into three classes, with only one class being up for election each year.
Although our articles of association contemplate that directors are elected
by a
plurality of the votes cast in the election, we have adopted a majority vote
policy in the election of directors as part of our Corporate Governance
Guidelines. This policy provides that the board may nominate only those
candidates for director who has submitted an irrevocable letter of resignation
which would be effective upon and only in the event that (1) such nominee fails
to receive a sufficient number of votes from shareholders in an uncontested
election and (2) the board accepts the resignation. If a nominee who has
submitted such a letter of resignation does not receive more votes cast for
than
against the nominee’s election, the Corporate Governance Committee must promptly
review the letter of resignation and recommend to the board whether to accept
the tendered resignation or reject it. The board must then act on the Corporate
Governance Committee’s recommendation within 90 days following the certification
of the shareholder vote. The board must promptly disclose its decision regarding
whether or not to accept the nominee’s resignation letter in a Form 8-K
furnished to the SEC or other broadly disseminated means of communication.
Cumulative voting for the election of directors is prohibited by our articles
of
association.
There
are
no limitations imposed by Cayman Islands law or our articles of association
on
the right of nonresident shareholders to hold or vote their ordinary
shares.
The
rights attached to any separate class or series of shares, unless otherwise
provided by the terms of the shares of that class or series, may be varied
only
with the consent in writing of the holders of all of the issued shares of that
class or series or by a special resolution passed at a separate general meeting
of holders of the shares of that class or series. The necessary quorum for
that
meeting is the presence of holders of at least a majority of the shares of
that
class or series. Each holder of shares of the class or series present, in person
or by proxy, will have one vote for each share of the class or series of which
he is the holder. Outstanding shares will not be deemed to be varied by the
creation or issuance of additional shares that rank in any respect prior to
or
equivalent with those shares.
Under
Cayman Islands law, some matters, like altering the memorandum or articles
of
association, changing the name of a company, voluntarily winding up a company
or
resolving to be registered by way of continuation in a jurisdiction outside
the
Cayman Islands, require approval of shareholders by a special resolution. A
special resolution is a resolution (i) passed by the holders of two-thirds
of
the shares voted at a general meeting or (ii) approved in writing by all
shareholders entitled to vote at a general meeting of the company.
The
presence of shareholders, in person or by proxy, holding at least a majority
of
the issued shares generally entitled to vote at a meeting, is a quorum for
the
transaction of most business. However, different quorums are required in some
cases to approve a change in our articles of association.
Our
board
of directors is authorized, without obtaining any vote or consent of the holders
of any class or series of shares unless expressly provided by the terms of
issue
of that class or series, to provide from time to time for the issuance of
classes or series of preference shares and to establish the characteristics
of
each class or series, including the number of shares, designations, relative
voting rights, dividend rights, liquidation and other rights, redemption,
repurchase or exchange rights and any other preferences and relative,
participating, optional or other rights and limitations not inconsistent with
applicable law.
Our
articles of association contain provisions that could prevent or delay an
acquisition of our Company by means of a tender offer, proxy contest or
otherwise.
The
foregoing description is a summary. This summary is not complete and is subject
to the complete text of our memorandum and articles of association. For more
information regarding our ordinary shares and our preference shares, see our
Current Report on Form 8-K dated May 14, 1999 and our memorandum and articles
of
association. Our memorandum and articles of association are filed as exhibits
to
this annual report.
Issuer
Purchases of Equity Securities
Period
Total
Number of Shares Purchased (1)
Average
Price Paid Per Share
Total
Number of Shares Purchased as Part of Publicly Announced Plans or
Programs
(2)
Maximum
Number (or Approximate Dollar Value) of Shares that May Yet Be Purchased
Under the Plans or Programs (2)
(in
millions)
October 2006
3,482,442
$
71.81
3,482,313
$
1,000
November 2006
—
—
—
1,000
December 2006
1,375
80.72
—
1,000
Total
3,483,817
$
71.82
3,482,313
$
1,000
_________________
(1)
Total
number of shares purchased in the fourth quarter of 2006 includes
1,504
shares withheld by us in satisfaction of withholding taxes due upon
the
vesting of restricted shares granted to our employees under our Long-Term
Incentive Plan to pay withholding taxes due upon vesting of a restricted
share award.
(2)
In
May 2006, our board of directors authorized an increase in the amount
of
ordinary shares which may be repurchased pursuant to our share repurchase
program from $2.0 billion, which was previously authorized and announced
in October 2005, to $4.0 billion. The shares may be repurchased from
time
to time in open market or private transactions. The repurchase program
does not have an established expiration date and may be suspended
or
discontinued at any time. Under the program, repurchased shares are
retired and returned to unissued status. From inception through December31, 2006, we have repurchased a total of 41.7
million of
our ordinary shares at a total cost of $3.0 billion.
The
selected financial data as of December 31, 2006 and 2005 and for each of the
three years in the period ended December 31, 2006 has been derived from the
audited consolidated financial statements included elsewhere herein. The
selected financial data as of December 31, 2004, 2003 and 2002, and for the
years ended December 31, 2003 and 2002 has been derived from audited
consolidated financial statements not included herein. The following data should
be read in conjunction with “Item 7. Management's Discussion and Analysis of
Financial Condition and Results of Operations” and the audited consolidated
financial statements and the notes thereto included under “Item 8. Financial
Statements and Supplementary Data.”
We
consolidated TODCO in our financial statements as a business segment through
December 16, 2004 and that portion of TODCO that we did not own was reported
as
minority interest in our consolidated statements of operations and balance
sheet. Our ownership and voting interest in TODCO declined to approximately
22
percent on that date and we no longer consolidated TODCO in our financial
statements but accounted for our remaining investment using the equity method
of
accounting.
In
May
2005 and June 2005, respectively, we completed a public offering and a sale
of
TODCO common stock pursuant to Rule 144 under the Securities Act of 1933, as
amended (respectively referred to as the “May Offering” and the “June Sale”).
After the May Offering, we accounted for our remaining investment using the
cost
method of accounting. As a result of the June Sale, we no longer own any shares
of TODCO’s common stock.
Management's
Discussion and Analysis of Financial Condition and Results of
Operations
The
following information should be read in conjunction with the information
contained in “Item 1. Business,”“Item 1A. Risk Factors” and the audited
consolidated financial statements and the notes thereto included under “Item 8.
Financial Statements and Supplementary Data”elsewhere
in this annual report.
Overview
Transocean
Inc. (together with its subsidiaries and predecessors, unless the context
requires otherwise, “Transocean,” the “Company,”“we,”“us” or “our”) is a
leading international provider of offshore contract drilling services for oil
and gas wells. As of February 2, 2007, we owned, had partial ownership interests
in or operated 82 mobile offshore drilling units. As of this date, our fleet
included 33 High-Specification semisubmersibles and drillships
(“High-Specification Floaters”), 20 Other Floaters, 25 Jackups and four Other
Rigs. We also have three High-Specification Floaters under
construction.
Our
mobile offshore drilling fleet is considered one of the most modern and
versatile fleets in the world. Our primary business is to contract these
drilling rigs, related equipment and work crews primarily on a dayrate basis
to
drill oil and gas wells. We specialize in technically demanding segments of
the
offshore drilling business with a particular focus on deepwater and harsh
environment drilling services. We also provide additional services, including
integrated services.
Key
measures of our total company results of operations and financial condition
are
as follows:
(In
millions, except average daily revenue and
percentages)
Average
daily revenue(a)(b)
$
142,100
$
105,100
$
37,000
Utilization(b)(c)
84
%
79
%
N/A
Statement
of Operations
Operating
revenue
$
3,882
$
2,892
$
990
Operating
and maintenance expense
2,155
1,720
435
Operating
income
1,641
720
921
Net
income
1,385
716
669
Balance
Sheet Data (at end of period)
Cash
and Cash Equivalents
467
445
22
Total
Assets
11,476
10,457
1,019
Total
Debt
3,295
1,597
1,698
______________________
“N/A”
means not applicable.
(a)
Average
daily revenue is defined as contract drilling revenue earned per
revenue
earning day. A revenue earning day is defined as a day for which
a rig
earns dayrate after commencement of
operations.
(b)
Excludes
a drillship engaged in scientific geological coring activities, the
Joides
Resolution,
that is owned by a joint venture in which we have a 50 percent interest
and is accounted for under the equity method of accounting.
(c)
Utilization
is the total actual number of revenue earning days as a percentage
of the
total number of calendar days in the
period.
We
continue to experience strong demand for all of our asset classes, which has
resulted in high utilization and historically high dayrates. We are seeing
leading dayrates at or near record levels for most rig classes and customer
interest for multi-year contracts. Interest in high-specification floaters
remains particularly strong.
A
shortage of qualified personnel in our industry is driving up compensation
costs
and suppliers are increasing prices as their backlogs grow. These labor and
vendor cost increases, while meaningful, are not expected to be significant
in
comparison with our expected increase in revenue for 2007 and beyond.
Our
revenues for the year ended December 31, 2006 increased from the prior year
period as a result of increased activity and higher dayrates. Our operating
and
maintenance expenses for the year increased primarily as a result of higher
labor and rig maintenance costs in connection with such increased activity
as
well as inflationary cost increases (see “—Outlook”). In addition, our financial
results for the year ended December 31, 2006 included the recognition of gains
from the sales of eight rigs and other income recognized under the TODCO tax
sharing agreement. Total debt increased from the end of the prior year period
as
a result of our issuance of the Floating Rate Notes and borrowings under the
Term Credit Facility. See “—Liquidity and Capital Resources-Sources and Uses of
Liquidity.”
We
operate in one business segment which consists of floaters, jackups and other
rigs used in support of offshore drilling activities and offshore support
services on a worldwide basis. Our fleet operates in a single, global market
for
the provision of contract drilling services. The location of our rigs and the
allocation of resources to build or upgrade rigs are determined by the
activities and needs of our customers.
Significant
Events
Contract
Backlog—We
have
been successful in building contract backlog in 2006 within all of our asset
classes. Our contract backlog at December 31, 2006 was approximately $20.2
billion, an 85 percent increase compared to our contract backlog at December31,2005. See “—Outlook−Drilling Market” and “—Performance and Other Key
Indicators.”
Construction
and Upgrade Programs—During
2006, we were awarded drilling contracts requiring the construction of three
enhanced Enterprise-class drillships. The newbuilds are expected to commence
operations during the second quarter of 2009, mid-2009 and the first quarter
of
2010. See “—Outlook−Drilling Market.”
During
2005, we entered into agreements with clients to upgrade two of our Sedco
700-series
semisubmersible rigs in our Other Floaters fleet, the Sedco
702
and the
Sedco
706,
at a
cost expected to be approximately $300 million for each rig. The upgraded rigs
will be dynamically positioned and have a water depth drilling capacity of
up to
6,000 to 6,500 feet. The Sedco
702
entered
the shipyard for the upgrade in early 2006. We expect the upgrade to be
completed in approximately the fourth quarter of 2007. The Sedco
706
upgrade
is scheduled to commence in the third quarter of 2007. We expect the upgrade
to
be completed in approximately the fourth quarter of 2008.
Hurricane
Damage—In
the
third quarter of 2005, two of our semisubmersible rigs, the Deepwater
Nautilus and
the
Transocean
Marianas,
sustained damage during hurricanes Katrina and Rita. During hurricane Katrina,
the Deepwater
Nautilus
sustained damage to its mooring system and lost approximately 3,200 feet of
marine riser and a portion of its subsea well control system. The rig was
undergoing repairs during hurricane Rita and was set adrift following the
failure of a tow line utilized by a towing vessel. Also during hurricane Rita,
the Transocean
Marianas
sustained damage to its mooring system, was forced off its drilling location
and
was grounded in shallow water. The Deepwater
Nautilus
was out
of service for 24 days in 2005 and 70 days in 2006. The Transocean
Marianas
was out
of service for 95 days in 2005 and 72 days in 2006. Both rigs returned to
service in the third quarter of 2006. Operating income in 2006 was negatively
impacted by approximately $50 million due to lost revenue and higher operating
and maintenance costs on the Deepwater
Nautilus
and the
Transocean
Marianas.
In
addition, we spent approximately $25 million on capital expenditures in 2006
to
replace damaged equipment.
Asset
Dispositions—During
2006, we sold three of our Other Floaters (Peregrine
III, Transocean Explorer and
Transocean
Wildcat),
three
of our tender rigs (W.D.
Kent, Searex IX
and
Searex X),
a
swamp barge (Searex
XII)
and a
platform rig. We received net proceeds from these sales of $464 million and
recognized gains on the sales of $411 million. See “—Liquidity
and Capital Resources-Capital Expenditures and Dispositions.”
In
January 2007, we completed the sale of our membership interest in Transocean
CGR
LLC (owner of the tender rig Charley
Graves)
for net
proceeds of $33 million and we expect to recognize a gain on the sale of $23
million in the first quarter of 2007.
Term
Credit Facility—In
August 2006, we entered into a two-year, $1.0 billion term credit facility
under
the Term Credit Agreement dated August 30, 2006 (“Term Credit Facility”). See
“—Liquidity and Capital Resources-Sources and Uses of Cash.”
Floating
Rate Notes—In
September 2006, we issued $1.0 billion aggregate principal amount of floating
rate notes, due September 2008 (“Floating Rate Notes”). See “—Liquidity and
Capital Resources-Sources and Uses of Liquidity.”
Repurchase
of Ordinary Shares—During
2006, we repurchased and retired 35.7 million of our ordinary shares at a total
cost of $2.6 billion. See “—Liquidity
and Capital Resources-Sources and Uses of Liquidity.”
In 2007,
we repurchased approximately 5.2 million of our ordinary shares at a
total cost of approximately $400 million. See “—Liquidity
and Capital Resources-Sources and Uses of Liquidity.”
Tax
Matters—In
April
2006, we received notice from the Norwegian tax authorities regarding their
intent to propose adjustments to taxable income for the tax years 1999, 2001
and
2002. These proposed assessments could result in an increase in tax of
approximately $260 million plus interest, and the authorities further indicated
they intend to impose penalties, which could range from 15 to 60 percent of
the
assessments. The anticipated assessments relate to restructuring transactions
undertaken in 2001 and 2002. See “—Outlook−Tax Matters.”
TODCO
Settlement—In
November 2006, we reached a negotiated settlement with TODCO, our former
subsidiary, arising out of the tax sharing agreement that we entered into with
TODCO in connection with TODCO’s initial public offering in 2004. As a result of
the settlement, we entered into an amended and restated tax sharing agreement
with TODCO. Under the terms of the amended and restated agreement, TODCO will
pay us for 55 percent of the value of the tax deductions arising from the
exercise of options to purchase our ordinary shares by current and former
employees and directors of TODCO. This payment rate applies retroactively to
amounts previously accrued by TODCO and to future payments. Under the terms
of
the amended and restated agreement, TODCO will also receive a $3 million
federal tax benefit for use of certain state and foreign tax assets. The amended
and restated agreement also provides that the change of control provision
contained in the agreement no longer applies to option deductions. However,
if
TODCO uses the option deductions after a change of control, it would be required
to pay us for 55 percent of the value of those deductions. As a result of the
settlement, we recognized income of $51 million, net of tax, in the fourth
quarter of 2006 that had previously been deferred pending resolution of the
dispute.
Outlook
Drilling
Market—Demand
for offshore drilling capacity continues to outpace supply. Our
High-Specification Floater fleet is fully committed in 2007 and has very little
time available in 2008. We have only four rigs remaining in our Other Floater
fleet that have any available uncommitted time left in 2007 and only seven
rigs
remaining in this fleet that have any available uncommitted time left in
2008. We have four jackup rigs that have uncommitted time left in 2007, but
19
rigs (68 percent of our Jackup fleet) have uncommitted time left in 2008.
Dayrates for new contracts for both floaters and jackups continue to be strong.
Our contract backlog at January 31, 2007 was approximately $20.8 billion, up
from approximately $20.2 billion at October 31, 2006.
During
2006, we were awarded drilling contracts with durations ranging from three
to
five years for three newbuild deepwater rigs, and we continue to pursue other
potential newbuild opportunities with multi-year contract durations. In March
2006, we were awarded a five-year drilling contract for an enhanced
Enterprise-class drillship, to be named the Discoverer
Clear Leader.
We
estimate total capital expenditure for the construction of this rig to be
approximately $630 million, excluding capitalized interest, but including
approximately $30 million for additional equipment requested by the client
for
which the client has agreed to an increased dayrate. We currently expect this
rig to begin operations in the U.S. Gulf of Mexico in the second quarter of
2009, after construction in South Korea followed by sea trials, mobilization
to
the U.S. Gulf of Mexico and customer acceptance.
In
June
2006, we were awarded a four-year drilling contract for another enhanced
Enterprise-class drillship. We estimate total capital expenditure for the
construction of this rig to be approximately $630 million, excluding capitalized
interest, but including approximately $11 million for additional equipment
requested by the client for which the client has agreed to an increased dayrate.
We currently expect this rig to begin operations in the U.S. Gulf of Mexico
in
mid-2009, after construction in South Korea followed by sea trials, mobilization
to the U.S. Gulf of Mexico and customer acceptance.
In
August
2006, we were awarded a drilling contract for a third enhanced Enterprise-class
drillship, to be named the Discoverer
Inspiration.
We
estimate total capital expenditure for the construction of this rig to be
approximately $670 million, excluding capitalized interest, but including
approximately $40 million for equipment that was not included in the original
costs of the other two enhanced Enterprise-class drillships. The client may
elect by September 2007 to shorten the term of the contract from five years
to
three years. We currently expect this rig to begin operations in the U.S. Gulf
of Mexico in the first quarter of 2010, after construction in South Korea
followed by sea trials, mobilization to the U.S. Gulf of Mexico and customer
acceptance.
We
have
been successful in building contract backlog within our High-Specification
Floaters fleet with 25 of our 37 current and future High-Specification Floaters,
including the three newbuilds and the two Sedco
700-series
rig upgrades, contracted into or beyond 2010 as of February 2, 2007. These
25
units also include 9 of our 13 current Fifth-Generation Deepwater Floaters.
Our
total contract backlog of approximately $20.8 billion as of January 31, 2007
includes an estimated $14.9 billion of backlog represented by our
High-Specification Floaters. We continue to believe that the long-term outlook
for deepwater capable rigs is favorable. In 2006 we saw successful drilling
efforts in the lower tertiary trend of the U.S. Gulf of Mexico; the discovery
of
light oil and non-associated gas in the deepwaters of Brazil; continued
exploration success in the deepwaters offshore India; a discovery in the
deepwaters of the South China Sea; and the drilling of the first well in the
ultra deepwaters of the Orphan Basin in Canada. These events, coupled with
continued exploration success in the deepwaters of West Africa, the opening
of
additional deepwater acreage in the U.S. Gulf of Mexico and the announced plans
of Pemex for its first tender for ultra deepwater drilling in Mexican waters
support our optimistic outlook for the deepwater drilling market sector. As
of
February 2, 2007, none of our High-Specification Floater fleet contract days
are
uncommitted for the remainder of 2007, while approximately three percent, 17
percent and 55 percent are uncommitted in 2008, 2009 and 2010,
respectively.
Our
Other
Floaters fleet, comprised of 19 semisubmersible rigs, excluding the Sedco
706,
is
largely committed to contracts that extend through 2007, and we continue to
see
customer demand for multi-year contracts for these units. We completed the
reactivations of the previously idle Transocean
Winner and
Transocean
Prospect
in
August 2006 and September 2006, respectively, both of which are supported by
multi-year contracts. We also completed the reactivation of the C.
Kirk Rhein,
Jr.,
which
has been awarded a two-year contract in India at a $340,000 dayrate and
commenced operations in February 2007. The sale of the Transocean
Explorer
was
completed in the second quarter of 2006, and the sale of the Transocean
Wildcat
was
completed in the fourth quarter of 2006. As of February 2, 2007, nine percent
of
our Other Floater fleet contract days are uncommitted for the remainder of
2007,
while approximately 35 percent, 69 percent and 85 percent are uncommitted in
2008, 2009 and 2010, respectively.
Our
outlook for activity for the Jackup market sector also remains strong. We were
recently awarded a three year contract for the Trident
17
at a
dayrate of $185,000. We expect to remain at or near full utilization for our
Jackup fleet in 2007. We believe that Asia, India, the Middle East and West
Africa will remain sources of strong demand for jackup rigs in the near to
intermediate term. As of February 2, 2007, five percent of our Jackup fleet
contract days are uncommitted for the remainder of 2007, while approximately
36
percent, 64 percent and 87 percent are uncommitted in 2008, 2009 and 2010,
respectively.
The
aggregate amount of out-of-service time we incur in 2007 is expected to decrease
substantially compared to the amount we incurred in 2006, primarily because
we
completed the reactivations of the Transocean
Winner
and
Transocean
Prospect
in the
third quarter of 2006 and the C.
Kirk Rhein, Jr.
in
February 2007. However, the reduction in out-of-service time resulting from
the
completed reactivations is expected to be at least partially offset by an
increase in out-of-service time that we expect to incur in connection with
the
continued upgrades of the Sedco
702
and
Sedco
706
to
deepwater capabilities. Excluding reactivations and upgrades, we expect the
amount of out-of-service time we incur in 2007 because of shipyard and
mobilization will be generally in line with the amount of out-of-service time
we
incurred in 2006 because of shipyard and mobilization.
We
expect
our revenues to continue to increase in 2007 due largely to commencement of
new
contracts with higher dayrates. The reactivation of the C.
Kirk Rhein, Jr.
and the
scheduled commencement of the Sedco
702contract
at the end of the rig’s deepwater upgrade shipyard project are also expected to
increase our revenues in 2007. We also expect the anticipated commencement
of
six integrated services contracts in the early part of 2007 to increase our
integrated services revenue for 2007.
We
expect
industry inflation in 2007 to continue to increase our operating and maintenance
costs including our shipyard and major maintenance program expenditures. We
expect our operating and maintenance costs in 2007 to further increase as a
result of the six integrated services contracts discussed above. These increases
are expected to be at least partially offset by lower shipyard and mobilization
expenses, as we expect our 2007 out-of-service time to decrease by approximately
15 percent compared to 2006, chiefly due to the completed reactivations of
the
Transocean
Prospect,
Transocean
Winner
and
C.
Kirk Rhein, Jr.
Finally,
we plan to invest in a number of recruitment, retention and personnel
development initiatives in connection with the manning of the crews of the
two
deepwater upgrades and three newbuild rigs and our efforts to mitigate expected
personnel attrition.
We
expect
that a number of fixed-price contract options will be exercised by our customers
in 2007, which would preclude us from taking full advantage of any increased
market rates for rigs subject to these contract options. We have five existing
contracts with fixed-priced or capped options for dayrates that we believe
are
less than current market dayrates. Well-in-progress or similar provisions in
our
existing contracts may delay the start of higher dayrates in subsequent
contracts, and some of the delays have been and could be
significant.
Our
operations are geographically dispersed in oil and gas exploration and
development areas throughout the world. Rigs can be moved from one region to
another, but 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.
However, significant variations between regions do not tend to persist long-term
because of rig mobility. Consequently, we operate in a single, global offshore
drilling market.
Insurance
Matters—We
renewed our insurance coverages for 12 months effective May 1, 2006. We
currently maintain a $10 million per occurrence insurance deductible on hull
and
machinery, a $10 million per occurrence deductible on personal injury liability
and a $5 million per occurrence deductible on third party property damage.
In
addition to the per occurrence deductibles described above, we also have
aggregate deductibles that are applied to any occurrence in excess of the per
occurrence deductible until the aggregate deductible is exhausted. Such
aggregate deductibles are $20 million in the case of our hull and machinery
coverage and $25 million in the case of our personal injury liability and third
party property damage coverage. Additionally, for our personal injury and
third-party damage liabilities, we have retained $20 million of the risk that
exceeds our deductible amount. Our coverage includes an annual aggregate limit
on losses due to hurricanes in the U.S Gulf of Mexico of $250 million, except
in
the case of a total loss of a rig, where the annual limit is approximately
$300
million in aggregate. At present, the insured value of our drilling rig fleet
is
$13.0 billion in aggregate. We also carry $930 million of third-party liability
coverage inclusive of the personal injury liability and third party property
liability deductibles and retention amounts described above. We do not carry
insurance for loss of revenue. As a result of these limits, we retain the risk
through self-insurance for any losses in excess of these amounts. Most of our
insurance programs are up for renewal in the second quarter of 2007. We could
decide to retain substantially more risk through self-insurance.
Tax
Matters—We
are a
Cayman Islands company. We operate through our various subsidiaries in a number
of countries throughout the world. Consequently, we are subject to changes
in
tax laws, treaties and regulations in and between the countries in which we
operate. A material change in these tax laws, treaties or regulations in any
of
the countries in which we operate could result in a higher or lower effective
tax rate on our worldwide earnings.
Our
income tax returns are subject to review and examination in the various
jurisdictions in which we operate. We are currently contesting various tax
assessments. We accrue for income tax contingencies that we believe are probable
exposures.
In
February 2007, we entered into a settlement agreement with the U.S. Internal
Revenue Service (“IRS”) regarding our U.S. federal income tax returns for 2001
through 2003. The IRS agreed to settle all issues for this period. This
settlement resulted in no cash tax payment. During 2006, we settled disputes
with tax authorities in several jurisdictions and the statute of limitations
for
income tax contingencies for certain issues expired. As a result of the
resolution of these matters, we recognized a current tax benefit of
approximately $30 million.
Our
2004
and 2005 U.S. federal income tax returns are currently under examination by
the
IRS. We believe our returns are materially correct as filed, and we intend
to
vigorously defend against any proposed changes. While we cannot predict or
provide assurance as to the final outcome, we do not expect the ultimate
settlement of any liability resulting from any examination to have a material
adverse effect on our consolidated financial position, results of operations
or
cash flows.
In
April
2006, we received notice from the Norwegian tax authorities regarding their
intent to propose adjustments to taxable income for the tax years 1999, 2001
and
2002. These proposed assessments could result in an increase in tax of
approximately $260 million, plus interest and the authorities further indicated
they intend to impose penalties, which could range from 15 to 60 percent of
the
assessments. The anticipated assessments relate to restructuring transactions
undertaken in 2001 and 2002. The Norwegian tax authorities initiated inquiries
in September 2004 related to the restructuring transactions and a separate
dividend payment made during 2001. In February 2005, we filed a response to
these inquiries. In March 2005, pursuant to court orders, the Norwegian tax
authorities took action to obtain additional information regarding these
transactions. We have continued to respond to information requests from the
Norwegian authorities and filed a formal protest to the proposed assessment
in
June 2006. We also believe the Norwegian authorities are contemplating a tax
assessment of approximately $104 million on the dividend, plus interest and
a
penalty, which could range from 15 to 60 percent of the assessment. Norwegian
civil tax and criminal authorities continue to investigate the restructuring
transactions and dividend. We plan to vigorously contest any assertions by
the
Norwegian authorities in connection with the restructuring transactions or
dividend. While we cannot predict or provide assurance as to the final outcome
of these proceedings, we do not expect it to have a material adverse effect
on
our consolidated financial position, results of operations or cash
flows.
In
addition, other tax authorities are examining our tax returns in various
jurisdictions. While we cannot predict or provide assurance as to the final
outcome of these other existing or future assessments, we do not expect the
ultimate settlement of any liability resulting from these existing or future
assessments to have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
GlobalSantaFe
Patent Infringement—In
February 2007, we reached an agreement with a competitor, GlobalSantaFe
Corporation (“GlobalSantaFe”), relating to their infringement of our offshore
dual activity drilling technology patents. We had commenced a patent
infringement action in U.S. federal court against GlobalSantaFe, and in August
2006, the jury found in our favor. Through the court action, the validity and
enforceability of the dual activity patents were upheld and we were awarded
royalty damages and granted a permanent injunction against further infringement
by GlobalSantaFe. GlobalSantaFe had two infringing drilling rigs operating
in
the Gulf of Mexico, the semisubmersible rigs Development Driller I and
Development Driller II.
The
agreement now reached with GlobalSantaFe will permit them to utilize our dual
activity drilling technology on those two rigs currently working in the Gulf
of
Mexico and also on their Development Driller III rig after delivery from the
shipyard in Singapore. In exchange for this right, GlobalSantaFe has agreed
to
discontinue any further proceedings disputing our dual activity patents and
has
agreed to pay $4 million for each of these three rigs as a building fee and
approximately $3 million in royalties in aggregate for use to date by its two
operating rigs, for a combined payment of approximately $15 million.
GlobalSantaFe has further agreed to pay a license fee going forward of three
percent of revenues received on the three Development Driller rigs when
operating in an area where we have dual activity patent rights and five percent
of revenues on any other rigs which GlobalSantaFe may acquire which incorporate
the dual activity technology when operating in an area where we have patent
rights. We have not granted any rights to build any additional rigs
incorporating the dual activity technology and any such construction would
be
subject to further negotiation or litigation.
Performance
and Other Key Indicators
Contract
Backlog—The
following table reflects our contract backlog and associated average contractual
dayrates at the periods ended December 31, 2006 and 2005 and reflects firm
commitments only, typically represented by signed drilling
contracts. Backlog
is indicative of the full contractual dayrate. The amount of actual revenue
earned and the actual periods during which revenues are earned will be different
than the amounts and periods shown in the tables below due to various factors
including shipyard and maintenance projects, other downtime and other factors
that result in lower applicable dayrates than the full contractual operating
dayrate, as well as the ability of our customers to terminate contracts under
certain circumstances. Our contract backlog is calculated by multiplying the
contracted operating dayrate by the number of days remaining in the firm
contract period, excluding revenues for mobilization, demobilization and
contract preparation and such amounts are not expected to be significant to
our
contract drilling revenues. The contract backlog average dayrate is defined
as
the contracted operating dayrate to be earned per revenue earning day in the
period. A revenue earning day is defined as a day for which a rig earns dayrate
after commencement of operations and over the firm contract period.
Fleet
Utilization and Average Daily Revenue—The
following table shows our average daily revenue and utilization for each of
the
three months ended December 31, 2006, September 30, 2006 and December 31, 2005.
Average daily revenue is defined as contract drilling revenue earned per revenue
earning day in the period. A revenue earning day is defined as a day for which
a
rig earns dayrate after commencement of operations. Utilization in the table
below is defined as the total actual number of revenue earning days in the
period as a percentage of the total number of calendar days in the period for
all drilling rigs in our fleet.
Our
primary sources of cash in 2006 were our cash flows from operations, proceeds
from asset sales, proceeds from the issuance of the Floating Rate Notes,
borrowings under our credit facilities, cash received under our tax sharing
agreement with TODCO and proceeds from issuance of ordinary shares upon the
exercise of stock options. Our primary uses of cash were repurchases of our
ordinary shares, capital expenditures and repayments of borrowings under our
credit facilities. At December 31, 2006, we had $467 million in cash and cash
equivalents.
Net
cash
provided by operating activities increased by $373 million due to more cash
generated from net income ($324 million) and less cash used for working capital
items ($49 million).
Net
cash
used by investing activities increased by $584 million over the previous year.
The increase is primarily due to higher capital expenditures related to the
construction of three enhanced Enterprise-class drillships, the two Sedco
700-series
deepwater upgrades and other equipment replaced and upgraded on our existing
rigs. The increase in capital expenditures was partially offset by higher
proceeds from disposal of assets of $387 million. In addition, in 2005 we
received proceeds from TODCO stock sales of $272 million, with no comparable
activity for the corresponding period in 2006.
Net
cash
used in financing activities decreased by $239 million in 2006 compared to
2005.
In 2006, we received proceeds of $2.0 billion from the issuance of our Floating
Rate Notes and borrowings under on our Term Credit Facility, with no comparable
activity in 2005. In addition, we used less cash to repay debt in 2006 as
compared to 2005. Partially offsetting these decreases, we used more cash to
repurchase our ordinary shares under our share repurchase program in 2006 than
in 2005, and we received less cash from the issuance of our ordinary shares
under our share-based compensation program.
Capital
Expenditures and Dispositions
From
time
to time, we review possible acquisitions of businesses and drilling rigs and
may
in the future make significant capital commitments for such purposes. We may
also consider investments related to major rig upgrades or new rig construction
if generally supported by firm contracts. Any such acquisition, upgrade or
new
rig construction could involve the payment by us of a substantial amount of
cash
or the issuance of a substantial number of additional ordinary shares or other
securities. We have been awarded drilling contracts for three newbuild deepwater
drilling rigs and are currently in discussions with various clients for
potential other deepwater drilling contracts related to new deepwater drilling
rigs. In addition, from time to time, we review possible dispositions of
drilling units.
Capital
Expenditures—Capital
expenditures, including capitalized interest of $16 million, totaled $876
million during the year ended December 31, 2006, which included approximately
$220 million on the construction of the drillship Discoverer
Clear Leader,
approximately $110 million on the construction of the second deepwater
drillship, approximately $130 million on the construction of the drillship
Discoverer
Inspiration,
approximately $150 million for the upgrade of two of our Sedco
700-series
rigs, approximately $25 million to replace and upgrade equipment damaged during
hurricanes Katrina and Rita on the Deepwater
Nautilus
and the
Transocean
Marianas and
approximately $40 million to reactivate three of our Other
Floaters.
During
2007, we expect capital expenditures to be approximately $1.4 billion, including
approximately $800 million for the construction of the three deepwater
drillships and approximately $300 million for the continued upgrade of two
of
our Sedco
700-series
rigs. The level of our capital expenditures is partly dependent upon the actual
level of operational and contracting activity. These expected capital
expenditures do not include amounts that would be incurred as a result of any
of
the other possible newbuild opportunities.
As
with
any major shipyard project that takes place over an extended period of time,
the
actual costs, the timing of expenditures and the project completion date may
vary from estimates based on numerous factors, including actual contract terms,
weather, exchange rates, shipyard labor conditions and the market demand for
components and resources required for drilling unit construction. See “Item 1A.
Risk Factors.”
We
intend
to fund the cash requirements relating to our capital expenditures through
available cash balances, cash generated from operations and asset sales. We
also
have available credit under our Revolving Credit Facility (see “—Sources and
Uses of Liquidity”) and may utilize other commercial bank or capital market
financings.
Dispositions—During
2006, we sold three of our Other Floaters (Peregrine
III, Transocean Explorer and
Transocean
Wildcat),
three
of our tender rigs (W.D.
Kent, Searex IX
and
Searex X),
a
swamp barge (Searex
XII)
and a
platform rig. We received net proceeds from these sales of $464 million and
recognized gains on the sales of $411 million.
In
January 2007, we completed the sale of our membership interest in Transocean
CGR
LLC (owner of the tender rig Charley
Graves)
for net
proceeds of $33 million and expect to recognize a gain on the sale of $23
million in the first quarter of 2007.
Sources
and Uses of Liquidity
We
expect
to use existing cash balances, internally generated cash flows, proceeds from
the issuance of new debt and proceeds from asset sales to fulfill anticipated
obligations such as scheduled debt maturities, capital expenditures and working
capital needs. From time to time, we may also use bank lines of credit to
maintain liquidity for short-term cash needs.
When
cash
on hand, cash flows from operations and proceeds from asset sales exceed our
expected liquidity needs, including major upgrades, new rig construction and/or
drilling rig acquisitions, we may use a portion of such cash to repurchase
our
ordinary shares. We may also use our Revolving Credit Facility or proceeds
from
the issuance of new debt to repurchase our ordinary shares. We will continue
to
consider allowing our cash balances to increase and will continue to consider
the reduction of debt prior to scheduled maturities.
Our
internally generated cash flow is directly related to our business and the
market sectors in which we operate. Should the drilling market deteriorate,
or
should we experience poor results in our operations, cash flow from operations
may be reduced. We have, however, continued to generate positive cash flow
from
operating activities over recent years and expect that cash flow will continue
to be positive over the next year.
In
May
2006, our board of directors authorized an increase in the amount of ordinary
shares which may be repurchased pursuant to our share repurchase program from
$2.0 billion, which was previously authorized and announced in October 2005,
to
$4.0 billion. The ordinary shares may be repurchased from time to time in open
market or private transactions. Decisions to repurchase shares are based upon
our ongoing capital requirements, the price of our shares, regulatory
considerations, cash flow generation, general market conditions and other
factors. We plan to fund any future share repurchases under the program from
current and future cash balances and we could also use debt to fund those share
repurchases. The repurchase program does not have an established expiration
date
and may be suspended or discontinued at any time. There can be no assurance
regarding the number of shares that will be repurchased under the program.
Under
the program, repurchased shares are retired and returned to unissued status.
During
2006, we repurchased and retired $2.6 billion of our ordinary shares, which
amounted to approximately 35.7 million ordinary shares at an average purchase
price of $72.78 per share. Total consideration paid to repurchase the shares
was
recorded in shareholders’ equity as a reduction in ordinary shares and
additional paid-in capital. Such consideration was funded with existing cash
balances, borrowings under our Revolving Credit Facility and our Term Credit
Facility and proceeds from the issuance of our Floating Rate Notes. In 2007,
we
repurchased approximately $400 million of our ordinary shares, which amounted
to
approximately 5.2 million ordinary shares. At February 28, 2007, after prior
repurchases, we had authority to repurchase an additional $600 million of our
ordinary shares under the program.
Under
the
terms of the Term Credit Facility, we were able to request borrowings up to
$1.0
billion over the first six months of the term. After six months, any unused
capacity is cancelled. Once repaid, the funds cannot be reborrowed. At our
election, borrowings may be made under the Term Credit Facility at either (i)
the base rate, determined as the greater of (a) the prime loan rate and
(b) the sum of the weighted average overnight federal funds rate plus 0.50
percent, or (ii) the London Interbank Offered Rate (“LIBOR”) plus 0.30
percent, based on current credit ratings. We paid a fee of 0.065 percent per
annum on the daily amount of the unused commitments under the Term Credit
Facility through October 3, 2006. In October 2006, we borrowed the full $1.0
billion in capacity. We subsequently repaid $300 million in December 2006.
At
February 28, 2007, $700 million was outstanding under this facility at a
weighted-average interest rate of 5.65 percent.
In
September 2006, we issued $1.0 billion aggregate principal amount of the
Floating Rate Notes. We are required to pay interest on the Floating Rate Notes
on March 5, June 5, September 5 and December 5 of each year, beginning on
December 5, 2006. The per annum interest rate on the Floating Rate Notes is
equal to the three month LIBOR, reset on each payment date, plus 0.20 percent.
We may redeem some or all of the notes at any time after September 2007 at
a
price equal to 100 percent of the principal amount plus accrued and unpaid
interest, if any. At February 28, 2007, $1.0 billion principal amount of these
notes was outstanding at an interest rate of 5.57 percent.
We
have
access to a bank line of credit under a $1.0 billion, five-year revolving credit
agreement expiring July 2011 (“Revolving Credit Facility”). At February 28,2007, $110 million was outstanding under this facility.
The
Revolving Credit Facility and Term Credit Facility require compliance with
various covenants and provisions customary for agreements of this nature,
including a debt to total tangible capitalization ratio, as defined by the
credit agreements, not greater than 60 percent. Other provisions of the credit
agreements include limitations on creating liens, incurring subsidiary debt,
transactions with affiliates, sale/leaseback transactions and mergers and sale
of substantially all assets. Should we fail to comply with these covenants,
we
would be in default and may lose access to these facilities. We are also subject
to various covenants under the indentures pursuant to which our public debt
was
issued, including restrictions on creating liens, engaging in sale/leaseback
transactions and engaging in certain merger, consolidation or reorganization
transactions. A default under our public debt could trigger a default under
our
credit agreements and, if not waived by the lenders, could cause us to lose
access to these facilities.
In
April
2001, the Securities and Exchange Commission (“SEC”) declared effective our
shelf registration statement on Form S-3 for the proposed offering from time
to
time of up to $2.0 billion in gross proceeds of senior or subordinated debt
securities, preference shares, ordinary shares and warrants to purchase debt
securities, preference shares, ordinary shares or other securities. At February28, 2007, $600 million in gross proceeds of securities remained unissued under
the shelf registration statement.
Our
access to debt and equity markets may be reduced or closed to us due to a
variety of events, including, among others, credit rating agency downgrades
of
our debt, industry conditions, general economic conditions, market conditions
and market perceptions of us and our industry.
As
is
customary in the contract drilling business, we also have various surety bonds
in place that secure customs obligations relating to the importation of our
rigs
and certain performance and other obligations.
Our
contractual obligations included in the table below are at face value (in
millions).
For
the years ending December 31,
Total
2007
2008-2009
2010-2011
Thereafter
Contractual
Obligations
Debt
$
3,288
$
100
$
1,719
$
565
$
904
Operating
Leases
76
22
21
11
22
Purchase
Obligations
1,551
619
926
6
-
Defined
Benefit Pension Plans
7
7
-
-
-
Total
Obligations
$
4,922
$
748
$
2,666
$
582
$
926
Bondholders
may, at their option, require us to repurchase the 7.45% Notes due 2027, the
Zero Coupon Convertible Debentures due 2020 and the 1.5% Convertible Debentures
due 2021 in April 2007, May 2008 and May 2011, respectively. With regard to
both
series of the Convertible Debentures, we have the option to pay the repurchase
price in cash, ordinary shares or any combination of cash and ordinary shares.
The chart above assumes that the holders of these convertible debentures and
notes exercise the options at the first available date. We are also required
to
repurchase the convertible debentures at the option of the holders at other
later dates.
We
may
elect to call the Zero Coupon Convertible Debentures due 2020 or the 1.5%
Convertible Debentures due 2021 for redemption at any time. If we call the
1.5%
Convertible Debentures for redemption or if other specified conditions are
met,
the holders will have the right to convert the debentures into our ordinary
shares. The holders of the Zero Coupon Convertible Debentures may convert the
debentures into our ordinary shares at any time.
We
have
an obligation to make contributions in 2007 to our funded U.S. and Norway
defined benefit pension plans. See “—Retirement Plans and Other Postemployment
Benefits” for a discussion of expected contributions for pension funding
requirements and expected benefit payments for our unfunded defined benefit
pension plans.
At
December 31, 2006, we had other commitments that we are contractually obligated
to fulfill with cash should the obligations be called. These obligations include
standby letters of credit and surety bonds that guarantee our performance as
it
relates to our drilling contracts, insurance, customs, tax and other obligations
in various jurisdictions. Letters of credit are issued under a number of
facilities provided by several banks. The obligations that are the subject
of
these surety bonds and letters of credit are geographically concentrated in
Nigeria and India. These letters of credit and surety bond obligations are
not
normally called as we typically comply with the underlying performance
requirement. The table below provides a list of these obligations in U.S. dollar
equivalents and their time to expiration.
For
the years ending December 31,
Total
2007
2008-2009
2010-2011
Thereafter
(In
millions)
Other
Commercial Commitments
Standby
Letters of Credit
$
405
$
299
$
49
$
57
$
-
Surety
Bonds
6
6
-
-
-
Total
$
411
$
305
$
49
$
57
$
-
Derivative
Instruments
We
have
established policies and procedures for derivative instruments that have been
approved by our board of directors. These policies and procedures provide for
the prior approval of derivative instruments by our Chief Financial Officer.
From time to time, we may enter into a variety of derivative financial
instruments in connection with the management of our exposure to fluctuations
in
foreign exchange rates and interest rates. We do not enter into derivative
transactions for speculative purposes; however, for accounting purposes, certain
transactions may not meet the criteria for hedge accounting. At December 31,2006, we had no outstanding foreign exchange derivative
instruments.
In
June
2001, we entered into interest rate swaps of $700 million aggregate notional
amount as a fair value hedge against our 6.625% Notes due April 2011. The swaps
effectively converted the fixed interest rate on the note into a floating rate.
The market value of the swaps was carried as an asset or a liability in our
consolidated balance sheet and the carrying value of the hedged debt was
adjusted accordingly.
In
2003,
we terminated all our outstanding interest rate swaps, which were designated
as
fair value hedges, and recorded $174 million as a fair value adjustment to
long-term debt in our consolidated balance sheet. We amortize this amount as
a
reduction to interest expense over the life of the underlying debt. During
the
year ended December 31, 2006, such reduction amounted to $3 million. The
remaining balance to be amortized at December 31, 2006 of $15 million relates
to
the 6.625% Notes due April 2011.
Results
of Operations
Historical
2006 compared to 2005
Following
is an analysis of our operating results. See “—Overview” for a definition of
revenue earning days, utilization and average daily revenue.
The
increase in contract drilling revenues was primarily due to higher average
daily
revenue in all asset classes and to the reactivation of four Other Floaters
and
one High-Specification Floater in 2005 and 2006. Partially offsetting this
increase were lower revenues on four rigs that were out of service in 2006
for
shipyard or maintenance projects and lower revenues from one rig which was
sold
in 2006.
Other
revenues for the year ended December 31, 2006 increased $2 million due to a
$23
million increase in client reimbursable revenue partially offset by decreased
integrated services revenue of $21 million.
Operating
and maintenance expenses increased by $435 million primarily from shipyard
projects, rig reactivations, higher labor costs and vendor price increases
resulting in higher labor and rig maintenance costs. This increase
included $76
million for reactivation costs associated with the Transocean
Prospect,
Transocean
Winner
and
C.
Kirk Rhein, Jr.
and $19
million of costs incurred to repair damages sustained during hurricanes Katrina
and Rita on the Transocean
Marianas
and the
Deepwater
Nautilus.
The
increase in general and administrative expenses of $15 million was due primarily
to $12 million higher personnel related expenses and $4 million higher legal
fees, including costs related to the TODCO dispute and patent litigation with
GlobalSantaFe Corporation.
During
2006, we recognized net gains of $405 million related to rig sales and disposal
of other assets. During 2005, we recognized net gains of $29 million related
to
rig sales and disposal of other assets.
The
increase in interest expense was primarily attributable to $39 million resulting
from higher debt levels arising from the issuance of debt and borrowings under
credit facilities in 2006, with no comparable activity in 2005. Partially
offsetting this increase were reductions of $19 million associated with debt
that was redeemed, retired or repurchased in 2005 and $16 million related to
capitalized interest in 2006.
During
2005, we recognized gains of $165 million from the disposition of our then
remaining investment in TODCO with no comparable activity in 2006.
During
2005, we recognized a $7 million loss related to the early redemption and
repurchase of $782 million aggregate principal amount of our debt, with no
comparable activity in 2006.
The
increase in other, net was primarily due to $40 million more income recognized
in 2006 as compared to 2005 related to the tax sharing agreement with TODCO
and
$6 million related to extension fees on the sale of the Transocean
Wildcat
in
2006.
We
operate internationally and provide for income taxes based on the tax laws
and
rates in the countries in which we operate and earn income. There is no expected
relationship between the provision for income taxes and income before income
taxes. The effective tax rate for 2006 and 2005 was 18.5 percent and 16.8
percent, respectively, based on 2006 and 2005 income before income taxes and
minority interest after adjusting for certain items such as a portion of net
gains on sales of assets, items related to the disposition of TODCO and losses
on retirements of debt. The tax effect, if any, of the excluded items as well
as
settlements of prior year tax liabilities and changes in prior year tax
estimates are all treated as discrete period tax expenses or benefits. The
impact of the various discrete period tax items, which related to the net gains
on rig sales and changes in prior year tax estimates, was a net expense of
$10
million in 2006, resulting in a tax rate of 13.8 percent on earnings before
income taxes and minority interest. The impact of the various discrete items
was
a net benefit of $14 million in 2005, resulting in a tax rate of 10.8 percent
on
earnings before income taxes and minority interest. The discrete items in 2005
included a benefit of $17 million for the reduction in a valuation allowance
related to U.K. net operating losses and a benefit related to the resolution
of
various tax audits, partially offset by expenses related to asset dispositions,
a deferred tax charge attributable to the restructuring of certain non-U.S.
operations and items related to the disposition of TODCO.
Historical
2005 compared to 2004
Through
December 16, 2004, our operations were aggregated into two reportable segments:
(i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists
of floaters, jackups and other rigs used in support of offshore drilling
activities and offshore support services on a worldwide basis. The TODCO segment
consisted of our interest in TODCO, which conducts jackup, drilling barge,
land
rig, submersible and other operations in the U.S. Gulf of Mexico and inland
waters, Mexico, Trinidad and Venezuela. The organization and aggregation of
our
business into the two segments were based on differences in economic
characteristics, customer base, asset class, contract structure and management
structure. In addition, the TODCO segment fleet was highly dependent upon the
U.S. natural gas industry while the Transocean Drilling segment’s operations are
more dependent upon the worldwide oil industry. As a result of the
deconsolidation of TODCO, we now operate in one business segment, the Transocean
Drilling segment.
Operating
income before general and administrative expense
$
795
$
428
$
367
86
%
_________________
“N/A”
means not applicable
“N/M”
means not meaningful
The
$623
million increase in contract drilling revenues was primarily related to
increased activity and utilization combined with lower revenues in 2004 of
approximately $38 million resulting from the labor strike in Norway, a fire
on
the Trident
20
and the
Jim
Cunningham
well
control incident with no comparable incidents in 2005. Partially offsetting
these increases was a decrease in revenue of approximately $14 million resulting
from the 2004 favorable settlement of the 2003 Discoverer
Enterprise
riser
separation incident with no comparable activity in 2005. Contract drilling
revenues were also negatively impacted in 2005 by approximately $21 million
due
to lost revenue on the Transocean
Marianas
and the
Deepwater
Nautilus
as a
result of the rigs undergoing repairs due to damages sustained during hurricanes
Katrina and Rita.
Other
revenues for the year ended December 31, 2005 decreased $11 million due to
a $23
million decrease in integrated services revenue, partially offset by an $11
million increase in client reimbursable revenue and compensation received in
2005 relating to the 2004 labor strike in Norway of $5 million.
Operating
and maintenance expenses increased by $287 million primarily
from increased activity, pay increases to employees and vendor price increases
resulting in higher labor and rig maintenance costs. Operating and maintenance
expenses also increased by $39 million as a result of the favorable settlement
in 2004 of an insurance claim and a turnkey dispute with no comparable activity
in 2005, increased costs in 2005 on the Transocean
Marianas
and the
Deepwater
Nautilus
to
repair damages sustained during hurricanes Katrina and Rita and increased local
personnel taxes in 2005 related to stock option exercises and restricted shares
vestings with no comparable activity in 2004. Partially offsetting these
increases were expenses of $35 million incurred related to a fire on the
Trident
20
in 2004
with no comparable activity in 2005, a favorable settlement of a vendor dispute
and lower property damage, personal injury and medical/dental insurance claim
expenses in 2005.
The
decrease in depreciation expense was due primarily to extending the useful
lives
to 35 years in the fourth quarter of 2004 for four rigs with original useful
lives ranging from 30 to 32 years and the reduction in depreciation on two
rigs
and certain other equipment that were substantially depreciated during
2004.
During
2005, we recognized net gains of $29 million related to the sale of the
semisubmersible rig Sedco
600,
the
jackup rig Transocean
Jupiter,
a land
rig and the sales and disposal of other assets. During 2004, we recognized
net
gains of $13 million related to the sale of the semisubmersible rig Sedco
602
and the
sales and disposal of other assets.
The
increase in general and administrative expense was primarily attributable to
increases of approximately $6 million in accounting, legal and professional
fees
as well as $4 million in increased personnel cost, rent expense, computer
equipment and pension and other post-employment retirement plan expense,
partially offset by decreased stock compensation expense of $3
million.
The
increase in interest income was primarily due to an increase in average cash
balances for 2005 compared to 2004 and an increase in interest rates on cash
investments, the combination of which resulted in an increase in interest income
of $8 million.
Approximately
$56 million of the decrease in interest expense was attributable to debt that
was redeemed, retired or repurchased during or subsequent to 2004. An additional
decrease of approximately $4 million related to interest expense in 2004 on
TODCO’s debt as a result of the TODCO deconsolidation in December 2004.
Gains
from TODCO stock sales decreased $144 million during 2005 compared to
2004.
During
2004, we recognized a $167 million non-cash charge related to contingent amounts
due from TODCO under a tax sharing agreement between us and TODCO.
During
2005, we recognized losses of $7 million related to the early redemption and
repurchase of $782 million aggregate principal amount of our debt. During 2004,
we recognized losses of $76 million related to the early retirements of $775
million aggregate principal amount of our debt.
The
$8
million favorable change in other, net primarily relates to $11 million of
income recognized under the tax sharing agreement with TODCO, partially offset
by the effect of foreign currency exchange rate changes on our monetary assets
and liabilities denominated in currencies other than the U.S.
dollar.
We
operate internationally and provide for income taxes based on the tax laws
and
rates in the countries in which we operate and earn income. There is no expected
relationship between the provision for income taxes and income before income
taxes. The effective tax rate for 2005 and 2004 was 16.8 percent and 49.7
percent, respectively, based on 2005 and 2004 income before income taxes and
minority interest after adjusting for certain items such as a portion of net
gains on sales of assets, items related to the disposition of TODCO and losses
on retirements of debt. The tax effect of the excluded items as well as
settlements of prior year tax liabilities and changes in estimates of prior
year
tax are all treated as discrete period tax expenses or benefits. The impact
of
the various discrete period tax items was a net benefit of $14 million in 2005,
resulting in a tax rate of 10.8 percent on earnings before income taxes and
minority interest. The discrete items included a benefit of $17 million for
the
reduction in a valuation allowance related to U.K. net operating losses and
a
benefit related to the resolution of various tax audits partially offset by
expenses related to asset dispositions, a deferred tax charge attributable
to
the restructuring of certain non-U.S. operations and changes related to the
disposition of TODCO. For 2004, the impact of the various discrete items was
a
net expense of $12 million, including a provision for a valuation allowance
of
approximately $32 million related to the TODCO IPO.
Operating
loss before general and administrative expense
−
$
(33
)
$
33
N/M
________________
“N/A”
means not applicable
“N/M”
means not meaningful
Critical
Accounting Estimates
Our
discussion and analysis of our financial condition and results of operations
are
based upon our consolidated financial statements. This discussion should be
read
in conjunction with disclosures included in the notes to our consolidated
financial statements related to estimates, contingencies and new accounting
pronouncements. Significant accounting policies are discussed in Note 2 to
our
consolidated financial statements. The preparation of our financial statements
requires us to make estimates and judgments that affect the reported amounts
of
assets, liabilities, revenues, expenses and related disclosure of contingent
assets and liabilities. On an on-going basis, we evaluate our estimates,
including those related to bad debts, materials and supplies obsolescence,
investments, property and equipment, intangible assets and goodwill, income
taxes, workers’ insurance, share-based compensation, pensions and other
post-retirement and employment benefits and contingent liabilities. We base
our
estimates on historical experience and on various other assumptions that we
believe are reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Actual results may differ
from
these estimates under different assumptions or conditions.
We
believe the following are our most critical accounting policies. These policies
require significant judgments and estimates used in the preparation of our
consolidated financial statements. Management has discussed each of these
critical accounting policies and estimates with the audit committee of the
board
of directors.
Income
taxes—We
are a
Cayman Islands company and we are not subject to income tax in the Cayman
Islands. We operate through our various subsidiaries in a number of countries
throughout the world. Income taxes have been provided based upon the tax laws
and rates in the countries in which operations are conducted and income is
earned. There is no expected relationship between the provision for or benefit
from income taxes and income or loss before taxes because the countries have
taxation regimes that vary not only with respect to the nominal tax rate, but
also in terms of the availability of deductions, credits and other benefits.
Variations also arise when income earned and taxed in a particular country
or
countries fluctuates from year to year.
Our
annual tax provision is based on expected taxable income, statutory rates and
tax planning opportunities available to us in the various jurisdictions in
which
we operate. The determination and evaluation of our annual tax provision and
tax
positions involves the interpretation of the tax laws in the 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, and treaties, foreign currency exchange
restrictions or our level of operations or profitability in each jurisdiction
would impact our tax liability in any given year. We also operate in many
jurisdictions where the tax laws relating to the offshore drilling industry
are
not well developed. While our annual tax provision is based on the best
information available at the time, a number of years may elapse before the
ultimate tax liabilities in the various jurisdictions are
determined.
We
maintain liabilities for estimated tax exposures in jurisdictions of operation.
Our annual tax provision includes the impact of income tax provisions and
benefits for changes to liabilities that we consider appropriate, as well as
related interest. Tax exposure items primarily include potential challenges
to
intercompany pricing, disposition transactions and the applicability or rate
of
various withholding taxes. These exposures are resolved primarily through the
settlement of audits within these tax jurisdictions or by judicial means, but
can also be affected by changes in applicable tax law or other factors, which
could cause us to conclude a revision of past estimates is appropriate. We
are
currently undergoing examinations in a number of taxing jurisdictions for
various fiscal years. We believe that an appropriate liability has been
established for estimated exposures. However, actual results may differ
materially from these estimates. We review these liabilities quarterly and
to
the extent the audits or other events result in an adjustment to the liability
accrued for a prior year, the effect will be recognized in the period of the
event.
We
do not
believe 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 others, 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.
Judgment
is required in determining whether deferred tax assets will be realized in
full
or in part. When it is estimated to be more likely than not that all or some
portion of specific deferred tax assets, such as foreign tax credit carryovers
or net operating loss carryforwards will not be realized, a valuation allowance
must be established for the amount of the deferred tax assets that are estimated
to not be realizable. As of December 31, 2004, we had established a valuation
allowance against certain deferred tax assets, primarily U.S. foreign tax credit
carryforwards and certain net operating losses, in the amount of $115 million.
We decreased the valuation allowance to $48 million, as of December 31, 2005,
and we increased the valuation allowance to $59 million, as of December 31,2006. If our facts or financial results were to change, thereby impacting the
likelihood of realizing the deferred tax assets, judgment would have to be
applied to determine changes to the amount of the valuation allowance in any
given period. Such changes could result in either a decrease or an increase
in
our provision for income taxes, depending on whether the change in judgment
resulted in an increase or a decrease to the valuation allowance. See “Results
of Operations—Historical 2006 compared to 2005” and “Results of
Operations—Historical 2005 compared to 2004.” We continually evaluate strategies
that could allow for the future utilization of our deferred tax
assets.
We
have
not provided for deferred taxes on the unremitted earnings of certain
subsidiaries that are permanently reinvested. Should we make a distribution
from
the unremitted earnings of these subsidiaries, we may 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.
We
have
not provided for deferred taxes in circumstances where we expect that, due
to
the structure of operations and applicable law, the operations in that
jurisdiction will not give rise to future tax consequences. Should our
expectations change regarding the expected future tax consequences, we may
be
required to record additional deferred taxes that could have a material effect
on our consolidated financial position, results of operations or cash
flows.
Property
and equipment—Our
property and equipment represents approximately 64 percent of our total assets.
We determine the carrying value of these assets based on our property and
equipment accounting policies, which incorporate our estimates, assumptions,
and
judgments relative to capitalized costs, useful lives and salvage values of
our
rigs.
Our
property and equipment accounting policies are designed to depreciate our assets
over their estimated useful lives. 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 of our assets. The use of different estimates, assumptions and
judgments in the establishment of property and equipment accounting policies,
especially those involving the useful lives of our rigs, would likely result
in
materially different net book values of our assets and results of
operations.
In
addition, our policies are designed to appropriately and consistently capitalize
costs incurred to enhance, improve and extend the useful lives of our assets
and
expense those costs incurred to repair and maintain the existing condition
of
our rigs. Capitalized costs increase the carrying values and depreciation
expense of the related assets, which would also impact our results of
operations.
Useful
lives of rigs are difficult to estimate due to a variety of factors, including
technological advances that impact the methods or cost of oil and 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. A one year increase in
the
useful lives of all of our rigs would cause a decrease in our annual
depreciation expense of approximately $48 million while a one year decrease
would cause an increase in our annual depreciation expense of approximately
$84
million.
We
review
our property and equipment for impairment when events or changes in
circumstances indicate that the carrying value of such assets or asset groups
may be impaired or when reclassifications are made between property and
equipment and assets held for sale as prescribed by Statements of Financial
Accounting Standard (“SFAS”) No. 144, Accounting
for Impairment or Disposal of Long-Lived Assets.
Asset
impairment evaluations are based on estimated undiscounted cash flows for the
assets being evaluated. Supply and demand are the key drivers of rig idle time
and our ability to contract our rigs at economical rates. During periods of
an
oversupply, it is not uncommon for us to have rigs idled for extended periods
of
time, which could be an indication that an asset group may be impaired. Our
rigs
are equipped to operate in geographic regions throughout the world. Because
our
rigs are mobile, we may move rigs from an oversupplied market sector to one
that
is more lucrative and undersupplied when it is economical to do so. As such,
our
rigs are considered to be interchangeable within classes or asset groups and
accordingly, our impairment evaluation is made by asset group. We consider
our
asset groups to be High-Specification Floaters, Other Floaters, Jackups and
Other Rigs.
An
impairment loss is recorded in the period in which it is determined that the
aggregate carrying amount of assets within an asset group is not recoverable.
This requires us to make judgments regarding long-term forecasts of future
revenues and costs related to the assets subject to review. In turn, these
forecasts are uncertain in that they require assumptions about demand for our
services, future market conditions and technological developments. Significant
and unanticipated changes to these assumptions could require a provision for
impairment in a future period. Given the nature of these evaluations and their
application to specific asset groups and specific times, it is not possible
to
reasonably quantify the impact of changes in these assumptions.
Pension
and other postretirement benefits—Our
defined benefit pension and other postretirement benefit (retiree life insurance
and medical benefits) obligations and the related benefit costs are accounted
for in accordance with SFAS No.158, Employers’
Accounting for Defined Benefit Pension and other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106 and 123(R) (“SFAS
158”), SFAS No. 87, Employers’
Accounting for Pensions (“SFAS
87”) and SFAS No. 106, Employers’
Accounting for Postretirement Benefits Other than Pensions.
Pension
and postretirement costs and obligations are actuarially determined and are
affected by assumptions including expected return on plan assets, discount
rates, compensation increases, employee turnover rates and health care cost
trend rates. We evaluate our assumptions periodically and make adjustments
to
these assumptions and the recorded liabilities as necessary.
Two
of
the most critical assumptions are the expected long-term rate of return on
plan
assets and the assumed discount rate. We evaluate our assumptions regarding
the
estimated long-term rate of return on plan assets based on historical experience
and future expectations on investment returns, which are calculated by our
third
party investment advisor utilizing the asset allocation classes held by the
plan’s portfolios. We utilize a yield curve approach based on Aa corporate bonds
and the expected timing of future benefit payments as a basis for determining
the discount rate for our U.S. plans. Changes in these and other assumptions
used in the actuarial computations could impact our projected benefit
obligations, pension liabilities, pension expense and other comprehensive
income. We base our determination of pension expense on a market-related
valuation of assets that reduces year-to-year volatility. This market-related
valuation recognizes investment gains or losses over a five-year period from
the
year in which they occur. Investment gains or losses for this purpose are the
difference between the expected return calculated using the market-related
value
of assets and the actual return based on the market-related value of assets.
For
each
percentage point the expected long-term rate of return assumption is lowered,
pension expense would increase by approximately $2 million. For each one-half
percentage point the discount rate is lowered, pension expense would increase
by
approximately $3 million. See “―Retirement
Plans and Other Postemployment Benefits.”
Contingent
liabilities—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”). 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.
The
estimation of the liability for personal injury claims includes the application
of a loss development factor to reserves for known claims in order to estimate
our ultimate liability for claims incurred during the period. The loss
development method is based on the assumption that historical patterns of loss
development will continue in the future. Actual losses may vary from the
estimates computed with these reserve development factors as they are dependent
upon future contingent events such as court decisions and settlements.
Share-Based
Compensation
On
January 1, 2006, we adopted the Financial Accounting Standards Board (“FASB”)
SFAS No. 123 (revised 2004), Share-Based
Payment (“SFAS
123(R)”), which is a revision of SFAS No.123, Accounting
for Stock-Based Compensation (“SFAS
123”). We previously accounted for share-based compensation in accordance with
SFAS 123. Adoption of the new standards did not have a material effect on our
consolidated financial position, results of operations or cash flows.
Retirement
Plans and Other Postemployment Benefits
On
December 31, 2006, we adopted the recognition and disclosure provisions of
SFAS
158,
which
require the recognition of the funded status of the Defined Benefit and
Postretirement Benefits Other Than Pensions (“OPEB”) plans on the December 31,2006 balance sheet with a corresponding adjustment to accumulate other
comprehensive income. The adjustment to accumulate other comprehensive income
at
adoption represents the net unrecognized actuarial losses, unrecognized prior
service costs, and unrecognized transition obligation remaining from the initial
application of SFAS 87, all of which were previously netted against the plans’
funded status in the balance sheet. These amounts will be subsequently
recognized as net periodic pension cost pursuant to our historical accounting
policy for amortizing such amounts. Further, actuarial gains and losses that
arise in subsequent periods and are not recognized as net periodic pension
cost
in the same periods will be recognized as a component of other comprehensive
income. Those amounts will be subsequently recognized as a component of net
periodic pension cost on the same basis as the amounts recognized in accumulated
other comprehensive income.
The
incremental effects of adopting SFAS 158 on the consolidated balance sheet
at
December 31, 2006 are presented in the following table. The adoption of SFAS
158
did not affect the consolidated statement of operations for the year ended
December 31, 2006, or any prior period presented, and it will not affect our
operating results in future periods. The incremental effects of adopting the
provisions of SFAS 158 on the consolidated balance sheet are presented as
follows:
Defined
Benefit Pension Plans—We
maintain a qualified defined benefit pension plan (the “Retirement Plan”)
covering substantially all U.S. employees, and an unfunded plan (the
“Supplemental Benefit Plan”) to provide certain eligible employees with benefits
in excess of those allowed under the Retirement Plan. In conjunction with the
R&B Falcon merger, we acquired three defined benefit pension plans, two
funded and one unfunded (the “Frozen Plans”), that were frozen prior to the
merger for which benefits no longer accrue but the pension obligations have
not
been fully paid out. We refer to the Retirement Plan, the Supplemental Benefit
Plan and the Frozen Plans collectively as the “U.S. Plans.”
In
addition, we provide several defined benefit plans, primarily group pension
schemes with life insurance companies covering our Norway operations and two
unfunded plans covering certain of our employees and former employees (the
“Norway Plans”). Our contributions to the Norway Plans are determined primarily
by the respective life insurance companies based on the terms of the plan.
For
the insurance-based plans, annual premium payments are considered to represent
a
reasonable approximation of the service costs of benefits earned during the
period. We also have unfunded defined benefit plans (the “Other Non-U.S. Plans”)
that provide retirement and severance benefits for certain of our Indonesian,
Nigerian and Egyptian employees. The benefits we provide under defined benefit
pension plans are comprised of the U.S. Plans, the Norway Plans and the Other
Non-U.S. Plans (collectively, the “Transocean Plans”).
Pension
costs were reduced by expected returns on plan assets of $20 million
and
$21 million for the years ended December 31, 2006 and 2005,
respectively.
(b)
Weighted-average
based on relative average projected benefit obligation for the
year.
(c)
Weighted-average
based on relative average fair value of plan assets for the
year.
For
the
funded U.S. Plans, our funding policy consists of reviewing the funded status
of
these plans annually and contributing an amount at least equal to the minimum
contribution required under the Employee Retirement Income Security Act of
1974
(“ERISA”). Employer contributions to the funded U.S. Plans are based on
actuarial computations that establish the minimum contribution required under
ERISA and the maximum deductible contribution for income tax purposes. We
contributed $5 million to the funded U.S. Plans during 2006. No contributions
were made to the funded U.S. Plans during 2005. We contributed less than $1
million to the unfunded U.S. Plans during 2006 to fund benefit payments. We
contributed $1 million to the unfunded U.S. Plans during 2005 to fund benefit
payments.
Our
contributions to the Transocean Plans in 2006 and 2005, respectively, were
funded from our cash flows from operations.
Net
periodic benefit cost for the Transocean Plans included the following components
(in millions):
Plan
assets of the funded Transocean Plans have been favorably impacted by a
substantial rise in world equity markets during 2006 and an allocation of
approximately 60 percent of plan assets to equity securities. Debt securities
and other investments also experienced increased values, but to a lesser extent.
During 2006, the market value of the investments in the Transocean Plans
increased by $31 million, or 12.8 percent. The increase is due to net investment
gains of $28 million, primarily in the funded U.S. Plans, resulting from the
favorable performance of equity markets in 2006, $15 million of employer
contributions and $3 million of favorable foreign currency exchange rate
changes. These increases were offset by benefit plan payments of $15 million
from these plans. We expect to contribute $17 million to the Transocean Plans
in
2007. These contributions are comprised of an estimated $8 million to meet
minimum funding requirements for the funded U.S. Plans, $1 million to fund
expected benefit payments for the unfunded U.S. Plans and Other Non-U.S. Plans
and an estimated $8 million for the funded Norway Plans. We expect the required
contributions will be funded from cash flow from operations.
We
account for the Transocean Plans in accordance with SFAS 87 as amended by SFAS
158. These statements require us to calculate our pension expense and
liabilities using assumptions based on a market-related valuation of assets,
which reduces year-to-year volatility using actuarial assumptions. Changes
in
these assumptions can result in different expense and liability amounts, and
future actual experience can differ from these assumptions.
In
accordance with SFAS 87, changes in pension obligations and assets may not
be
immediately recognized as pension costs in the statement of operations but
generally are recognized in future years over the remaining average service
period of plan participants. As such, significant portions of pension costs
recorded in any period may not reflect the actual level of benefit payments
provided to plan participants.
Two
of
the most critical assumptions used in calculating our pension expense and
liabilities are the expected long-term rate of return on plan assets and the
assumed discount rate. In 2005, the increase in the fair value of plan assets
offset the decrease in the discount rate resulting in a decrease in the minimum
pension liability of $6 million. In 2006, the fair value of plan assets
continued to increase, resulting in a decrease in the minimum pension liability
of $25 million. At December 31, 2006, there was no minimum pension liability
included in accumulated other comprehensive income due to our adoption of SFAS
158. The minimum pension liability adjustment did not impact our results of
operations during the years ended December 31, 2004, 2005, or 2006, nor did
these adjustments affect our ability to meet any financial covenants related
to
our debt.
Our
expected long-term rate of return on plan assets for funded U.S. Plans was
9.0
percent as of December 31, 2006 and 2005. The expected long-term rate of return
on plan assets was developed by reviewing each plan’s target asset allocation
and asset class long-term rate of return expectations. We regularly review
our
actual asset allocation and periodically rebalance plan assets as appropriate.
For the U.S. Plans, we discounted our future pension obligations using a rate
of
5.8 percent at December 31, 2006, 5.5 percent at December 31, 2005 and 6.0
percent at December 31, 2004.
We
expect
pension expense related to the Transocean Plans for 2007 to decrease by
approximately $4 million primarily due to a change in the demographic
assumptions for future periods and plan asset growth realized in
2006.
Future
changes in plan asset returns, assumed discount rates and various other factors
related to the pension plans will impact our future pension expense and
liabilities. We cannot predict with certainty what these factors will be in
the
future.
Postretirement
Benefits Other Than Pensions—Wehave
several unfunded contributory and noncontributory postretirement benefit plans
covering substantially all of our U.S. employees. Funding of benefit payments
for plan participants will be made as costs are incurred. Net periodic benefit
cost for these other postretirement plans included the following components
(in
millions):
ODL—We
own a
50 percent interest in an unconsolidated joint venture company, Overseas
Drilling Limited (“ODL”). ODL owns the Joides
Resolution,
for
which we provide certain operational and management services. In 2006, we earned
$2 million for those services. Siem Offshore Inc. owns the other 50 percent
interest in ODL. Our director, Kristian Siem, is the chairman of Siem Offshore
Inc. and is also a director and officer of ODL. Mr. Siem is also chairman and
chief executive officer of Siem Industries, Inc., which owns an approximate
45
percent interest in Siem Offshore Inc.
In
November 2005, we entered into a loan agreement with ODL pursuant to which
we
may borrow up to $8 million. ODL may demand repayment at any time upon five
business days prior written notice given to us and any amount due to us from
ODL
may be offset against the loan amount at the time of repayment. As of December31, 2006 and 2005, $3 million and $4 million, respectively, was outstanding
under this loan agreement and was reflected as other long-term liabilities
in
our consolidated balance sheet. In 2006, ODL declared a dividend in the amount
of $4 million. In addition, ODL paid us cash dividends of $3 million and $11
million in 2005 and 2004, respectively.
Separation
of TODCO
Tax
Sharing Agreement with TODCO—Our
wholly owned subsidiary, Transocean Holdings Inc., is party to a tax sharing
agreement with TODCO that was entered into in connection with the TODCO IPO.
See
“Item 3. Legal Proceedings.”
New
Accounting Pronouncements
In
July
2006, the FASB issued FASB Interpretation No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109
(“FIN
48”). FIN 48 clarifies the accounting for income taxes recognized in an entity’s
financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes.
It
prescribes a minimum recognition threshold and measurement attribute for
recognizing and measuring the benefit of tax positions taken or expected to
be
taken in a tax return. FIN 48 also provides guidance on 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
will
be required to adopt this interpretation in the first quarter of fiscal year
2007. Management is in the process of quantifying the impact of FIN 48 on the
consolidated financial statements and has not yet finalized its evaluation.
In
September 2006, the FASB issued SFAS No. 157, Fair
Value Measurements (“SFAS
157”). SFAS 157 defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles, and expands disclosures
about
fair value measurements. SFAS 157 applies under other accounting pronouncements
that require or permit fair value measurements because the FASB previously
concluded in those accounting pronouncements that fair value is the relevant
measurement attribute. Accordingly, SFAS 157 does not require any new fair
value
measurements. SFAS 157 is effective for fiscal years beginning after November15, 2007. We will be required to adopt SFAS 157 in the first quarter of fiscal
year 2008. Management is currently evaluating the requirements of SFAS 157
and has not yet determined the impact on the consolidated financial
statements.
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities
(“SFAS
159”). SFAS 159 provides companies with an option to report selected financial
assets and liabilities at fair value. It also establishes presentation and
disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS 159 is effective as of the beginning of the first fiscal
year
beginning after November 15, 2007. We will be required to adopt SFAS 159 in
the
first quarter of fiscal year 2008. Management is currently evaluating the
requirements of SFAS 159 and has not yet determined the impact on the
consolidated financial statements.
In
June
2006, the FASB reached consensus on Emerging Issues Task Force ("EITF") No.
06-3, "How Taxes Collected from Customers and Remitted to Governmental
Authorities Should be Presented in the Income Statement" ("EITF 06-3"). The
scope of EITF 06-3 includes 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
excise taxes. The Task Force affirmed its conclusion that entities should
present these taxes in the consolidated statement of operations on either a
gross or a net basis, based on their accounting policy, which should be
disclosed pursuant to Accounting Principles Board Opinion No. 22, Disclosure
of Accounting Policies.
If
those taxes are significant, and are presented on a gross basis, the amounts
of
those taxes should be disclosed. The consensus on EITF 06-3 is effective as
of
the beginning of the first fiscal year beginning after December 15, 2006. We
generally record our tax-assessed revenue transactions on a net basis in our
consolidated statements of operations; therefore, we do not expect EITF 06-3
to
have a material effect on our consolidated balance sheet, statement of
operations or cash flows.
Quantitative
and Qualitative Disclosures About Market
Risk
Interest
Rate Risk
Our
exposure to market risk for changes in interest rates relates primarily to
our
long-term and short-term debt. The table below presents scheduled debt
maturities in U.S. dollars and related weighted-average interest rates for
each
of the years ended December 31 relating to debt obligations as of
December 31, 2006.
At
December 31, 2006 (in millions, except interest rate percentages):
Scheduled
Maturity Date (a) (b)
Fair
Value
2007
2008
2009
2010
2011
Thereafter
Total
12/31/06
Total
debt
Fixed
rate
$
100
$
19
$
−
$
−
$
565
$
904
$
1,588
$
1,773
Average
interest rate
7.5
%
2.8
%
−
%
−
%
3.0
%
7.5
%
5.8
%
Variable
rate
$
−
$
1,700
$
−
$
−
$
−
$
−
$
1,700
$
1,700
Average
interest rate
−
%
5.6
%
−
%
−
%
−
%
−
%
5.6
%
__________________________
(a)
Maturity
dates of the face value of our debt assume the put options on the
7.45%
Notes, Zero Coupon Convertible Debentures and the 1.5% Convertible
Debentures will be exercised in April 2007, May 2008 and May 2011,
respectively.
(b)
Expected
maturity amounts are based on the face value of debt.
At
December 31, 2006, we had approximately $1.7 billion of variable rate debt
at
face value (52 percent of total debt at face value). This variable rate debt
represented the Term Credit Facility and the Floating Rate Notes issued during
2006. At December 31, 2005, we had no variable rate debt outstanding. Based
upon
the December 31, 2006 and 2005 variable rate debt outstanding amounts, a one
percentage point change in interest rates would result in a corresponding change
in interest expense of approximately $17 million and no change per year,
respectively. In addition, a large part of our cash investments would earn
commensurately higher rates of return if interest rates increase. Using December31, 2006 and 2005 cash investment levels, a one percentage point change in
interest rates would result in a corresponding change in interest income of
approximately $3 million per year for both periods.
The
fair
market value of our debt at December 31, 2006 was $3.5 billion compared to
$1.9
billion at December 31, 2005. The increase in fair value of $1.6 billion was
primarily due to the issuance of debt during the year, as well as changes in
the
corporate bond market.
Foreign
Exchange Risk
Our
international operations expose us to foreign exchange risk. We use a variety
of
techniques to minimize the exposure to foreign exchange risk, including customer
contract payment terms and the possible use of foreign exchange derivative
instruments. Our primary foreign exchange risk management strategy involves
structuring customer contracts to provide for payment in both U.S. dollars,
which is our functional currency, and local currency. The payment portion
denominated in local currency is based on anticipated local currency
requirements over the contract term. Due to various factors, including customer
acceptance, local banking laws, other statutory requirements, local currency
convertibility and the impact of inflation on local costs, actual foreign
exchange needs may vary from those anticipated in the customer contracts,
resulting in partial exposure to foreign exchange risk. Fluctuations in foreign
currencies typically have not had a material impact on overall results. In
situations where payments of local currency do not equal local currency
requirements, foreign exchange derivative instruments, specifically foreign
exchange forward contracts, or spot purchases, may be used to mitigate foreign
currency risk. A foreign exchange forward contract obligates us to exchange
predetermined amounts of specified foreign currencies at specified exchange
rates on specified dates or to make an equivalent U.S. dollar payment equal
to
the value of such exchange. We do not enter into derivative transactions for
speculative purposes. At December 31, 2006, we had no open foreign exchange
derivative contracts.
MANAGEMENT’S
REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management
of Transocean Inc. (the “Company” or “our”) is responsible for establishing and
maintaining adequate internal control over financial reporting for the Company
as
defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act
of
1934.
The
Company’s internal control system was designed to provide reasonable assurance
to the Company’s management and Board of Directors regarding the
reliability of financial reporting and the preparation of financial statements
for external purposes in accordance with U.S. generally accepted accounting
principles.
Internal
control over financial reporting includes the controls themselves, monitoring
(including internal auditing practices), and actions taken to correct
deficiencies as identified.
There
are
inherent limitations to the effectiveness of internal control over financial
reporting, however well designed, including the possibility of human error
and
the possible circumvention or overriding of controls. The design of an internal
control system is also based in part upon assumptions and judgments made by
management about the likelihood of future events, and there can be no assurance
that an internal control will be effective under all potential future
conditions. As a result, even an effective system of internal controls can
provide no more than reasonable assurance with respect to the fair presentation
of financial statements and the processes under which they were prepared.
Management
assessed the effectiveness of the Company’s internal control over financial
reporting as of December 31, 2006. In making this assessment, management
used the criteria for internal control over financial reporting described in
Internal
Control-Integrated Framework
by the
Committee of Sponsoring Organizations of the Treadway Commission
(“COSO”).
Management’s assessment included an evaluation of the design of the Company’s
internal control over financial reporting and testing of the operating
effectiveness of its internal control over financial reporting. Management
reviewed the results of its assessment with the Audit Committee of the Company’s
Board of Directors. Based on this assessment, management has concluded that,
as
of December 31, 2006, the Company’s internal control over financial
reporting was effective.
Ernst
& Young LLP, an independent registered public accounting firm, audited
management’s assessment of the effectiveness of the Company’s internal control
over financial reporting as of December 31, 2006. Their report included
elsewhere herein expresses an unqualified opinion on management’s assessment and
on the effectiveness of our internal control over financial reporting as of
December 31, 2006.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
The
Board
of Directors and Shareholders ofTransocean
Inc.
We
have
audited management’s assessment, included in the accompanying Management’s
Report on Internal Control Over Financial Reporting, that Transocean Inc.
maintained effective internal control over financial reporting as of December31, 2006, based on criteria established in Internal Control—Integrated Framework
issued by the Committee of Sponsoring Organizations of the Treadway Commission
(the COSO criteria). Transocean 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 Transocean Inc. maintained effective
internal control over financial reporting as of December 31, 2006, is fairly
stated, in all material respects, based on the COSO criteria. Also, in our
opinion, Transocean Inc. maintained, in all material respects, effective
internal control over financial reporting as of December 31, 2006, based
onthe
COSO
criteria.
We
also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the consolidated
balance sheets of Transocean Inc. and Subsidiaries as of December 31, 2006
and
2005, and the related consolidated statements of operations, comprehensive
income, equity, and cash flows for each of the three years in the period ended
December 31, 2006 and
our
report dated February 27, 2007 expressed an unqualified opinion
thereon.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
The
Board
of Directors and Shareholders of Transocean Inc.
We
have
audited the accompanying consolidated balance sheets of Transocean Inc. and
Subsidiaries as of December 31, 2006 and 2005, and the related consolidated
statements of operations, comprehensive income, equity, and cash flows for
each
of the three years in the period ended December 31, 2006. Our audits also
included the financial statement schedule listed in the Index at Item 15(a).
These financial statements and schedule are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and schedule 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 financial statements referred to above present fairly, in all
material respects, the consolidated financial position of Transocean Inc. and
Subsidiaries at December 31, 2006 and 2005, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2006, in conformity with U.S. generally accepted accounting
principles. Also, in our opinion, the related financial statement schedule,
when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth
therein.
As
discussed in Note 2 to the consolidated financial statements, effective January1, 2006, the Company adopted Statement of Financial Accounting Standards
No. 123
(revised 2004), Share-Based
Payment
and, as
discussed in Note 19, effective December 31, 2006, the Company adopted Statement
of Financial Accounting Standards No. 158, Employers’
Accounting for Defined Benefit Pension and Other Postretirement Plans, an
amendment of FASB Statements No. 87, 88, 106, and 132(R).
We
also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Transocean 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 and our report dated
February 27, 2007 expressed an unqualified opinion thereon.
Minimum
pension liability adjustments (net of tax expense (benefit) $9, $2
and
$(2) for the years ended December 31, 2006, 2005 and 2004,
respectively)
Preference
Shares, $0.10 par value; 50,000,000 shares authorized, none issued
and
outstanding
−
−
Ordinary
Shares, $0.01 par value; 800,000,000 shares authorized, 292,454,457
and
324,750,166 shares issued and outstanding at December 31, 2006 and
2005,
respectively
Note
1—Nature of Business and Principles of Consolidation
Transocean
Inc. (together with its subsidiaries and predecessors, unless the context
requires otherwise, “Transocean,” the “Company,”“we,”“us” or “our”) is a
leading international provider of offshore contract drilling services for oil
and gas wells. Our mobile offshore drilling fleet is considered one of the
most
modern and versatile fleets in the world. We specialize in technically demanding
sectors of the offshore drilling business with a particular focus on deepwater
and harsh environment drilling services. We contract our drilling rigs, related
equipment and work crews primarily on a dayrate basis to drill oil and gas
wells. We also provide additional services, including integrated services.
At
December 31, 2006, we owned, had partial ownership interests in or operated
82
mobile offshore drilling units. As of this date, our fleet consisted of 33
High-Specification semisubmersibles and drillships (“High-Specification
Floaters”), 20 Other Floaters, 25 Jackups and four Other Rigs. We also have
three High-Specification Floaters under construction (see Note 5—Drilling
Fleet Expansion, Upgrades and Acquisition).
On
January 31, 2001, we completed a merger transaction (the “R&B Falcon
merger”) with R&B Falcon Corporation (“R&B Falcon”). At the time of the
merger, R&B Falcon operated a diverse global drilling rig fleet consisting
of drillships, semisubmersibles, jackup rigs and other units including the
Gulf
of Mexico Shallow and Inland Water segment fleet. R&B Falcon and the Gulf of
Mexico Shallow and Inland Water segment later became known as TODCO (together
with its subsidiaries and predecessors, unless the context requires otherwise,
“TODCO”) and the TODCO segment, respectively. In preparation for the initial
public offering discussed below, we transferred all assets and subsidiaries
out
of R&B Falcon that were unrelated to the Gulf of Mexico Shallow and Inland
Water business.
In
February 2004, we completed an initial public offering (the “TODCO IPO”) of
approximately 23 percent of TODCO’s outstanding shares of its common stock. In
September 2004 and December 2004, respectively, we completed additional public
offerings of TODCO common stock (respectively referred to as the “September 2004
Offering” and “December 2004 Offering” and, together with the TODCO IPO, the
“2004 Offerings”). We sold 30 percent of TODCO’s outstanding shares of its
common stock in the September 2004 Offering and 25 percent of TODCO’s
outstanding shares of its common stock in the December 2004 Offering. Prior
to
the December 2004 Offering, we held TODCO class B common stock, which was
entitled to five votes per share (compared to one vote per share of TODCO class
A common stock) and converted automatically into class A common stock upon
any
sale by us to a third party. In conjunction with the December 2004 Offering,
we
converted all of our remaining TODCO class B common stock not sold in the 2004
Offerings into shares of class A common stock. After the 2004 Offerings, we
held
a 22 percent ownership and voting interest in TODCO.
We
consolidated TODCO in our financial statements through December 16, 2004 and
that portion of TODCO that we did not own was reported as minority interest
in
our consolidated statements of operations and balance sheets. As a result of
the
conversion of the TODCO class B common stock into class A common stock, we
no
longer had a majority voting interest in TODCO and no longer consolidated TODCO
in our financial statements but accounted for our remaining investment using
the
equity method of accounting.
In
May
2005 and June 2005, respectively, we completed a public offering of TODCO common
stock and a sale of TODCO common stock pursuant to Rule 144 under the Securities
Act of 1933, as amended (respectively referred to as the “May Offering” and the
“June Sale,” collectively referred to as the “2005 Offering and Sale,” and,
collectively with the 2004 Offerings, the “TODCO stock sales”). We sold 20
percent of TODCO’s total outstanding shares in the May Offering and our
remaining two percent of TODCO’s total outstanding shares in the June Sale.
After the May Offering, we accounted for our remaining investment using the
cost
method of accounting. As a result of the June Sale, we no longer own any shares
of TODCO’s common stock. See Note 4—TODCO
Stock Sales.
For
investments in joint ventures and other entities that do not meet the criteria
of a variable interest entity or where we are not deemed to be the primary
beneficiary for accounting purposes of those entities that meet the variable
interest entity criteria, we use the equity method of accounting where our
ownership is between 20 percent and 50 percent or where our ownership is more
than 50 percent and we do not have significant control over the unconsolidated
affiliate. We use the cost method of accounting for investments in
unconsolidated affiliates where our ownership is less than 20 percent and where
we do not have significant influence over the unconsolidated affiliate. We
consolidate those investments that meet the criteria of a variable interest
entity where we are deemed to be the primary beneficiary for accounting purposes
and for entities in which we have a majority voting interest. Intercompany
transactions and accounts are eliminated.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
2—Summary of Significant Accounting Policies
Accounting
Estimates—The
preparation of financial statements in conformity with accounting principles
generally accepted in the U.S. requires management to make estimates and
assumptions that affect the reported amounts of assets, liabilities, revenues,
expenses and disclosure of contingent assets and liabilities. On an ongoing
basis, we evaluate our estimates, including those related to bad debts,
materials and supplies obsolescence, investments, intangible assets and
goodwill, property and equipment and other long-lived assets, income taxes,
workers' insurance, share-based compensation, pensions and other postretirement
benefits, other employment benefits and contingent liabilities. We base our
estimates on historical experience and on various other assumptions we believe
are reasonable under the circumstances, the results of which form the basis
for
making judgments about the carrying values of assets and liabilities that are
not readily apparent from other sources. Actual results could differ from such
estimates.
Cash
and Cash Equivalents—Cash
equivalents are stated at cost plus accrued interest, which approximates fair
value. Cash equivalents are highly liquid debt instruments with an original
maturity of three months or less and may consist of time deposits with a number
of commercial banks with high credit ratings, Eurodollar time deposits,
certificates of deposit and commercial paper. We may also invest excess funds
in
no-load, open-end, management investment trusts (“management trusts”). The
management trusts invest exclusively in high quality money market instruments.
As
a
result of the Deepwater
Nautilus project
financing in 1999, we were required to maintain in cash an amount to cover
certain principal and interest payments. Such restricted cash, classified as
other current assets in the consolidated balance sheet, was $12 million at
December 31, 2004. As a result of the repayment of the project financing (see
Note 7—Debt),
the restricted cash balance was released in May 2005.
Accounts
Receivable—Accounts
receivable are stated at the historical carrying amount net of write-offs and
allowance for doubtful accounts receivable. Uncollectible accounts receivable
are written off when a settlement is reached for an amount that is less than
the
outstanding historical balance.
Allowance
for Doubtful Accounts—We
establish reserves for doubtful accounts on a case-by-case basis when we believe
the required payment of specific amounts owed is unlikely to occur. In
establishing these reserves, we consider changes in the financial position
of a
major customer and restrictions placed on the conversion of local currency
to
U.S. dollars as well as disputes with our customers regarding the application
of
contract provisions to our drilling operations. This allowance was $26 million
and $15 million at December 31, 2006 and 2005, respectively. We derive a
majority of our revenue from services to international and government-owned
or
government-controlled oil companies, and, generally, do not require collateral
or other security to support client receivables.
Materials
and Supplies—Materials
and supplies are carried at average cost less an allowance for obsolescence.
Such allowance was $19 million at December 31, 2006 and 2005.
Property
and Equipment—Property
and equipment, consisting primarily of offshore drilling rigs and related
equipment, represented approximately 64 percent of our total assets at December31, 2006. The carrying values of these assets are based on estimates,
assumptions and judgments relative to capitalized costs, useful lives and
salvage values of our rigs. These estimates, assumptions and judgments reflect
both historical experience and expectations regarding future industry conditions
and operations. We compute depreciation using the straight-line method after
allowing for salvage values. Expenditures for renewals, replacements and
improvements are capitalized. Maintenance and repairs are charged to operating
expense as incurred. Upon sale or other disposition, the applicable amounts
of
asset cost and accumulated depreciation are removed from the accounts and the
net amount, less proceeds from disposal, is charged or credited to gain (loss)
from disposal of assets, net.
Estimated
original useful lives of our drilling units range from 18 to 35 years,
reflecting maintenance history and market demand for these drilling units,
buildings and improvements from 10 to 30 years and machinery and equipment
from
four to 12 years. From time to time, we may review the estimated remaining
useful lives of our drilling units and may extend the useful life when events
and circumstances indicate the drilling unit can operate beyond its original
useful life. During the fourth quarter of 2004, we extended the useful lives
to
35 years for four rigs, which had estimated useful lives ranging from 30 to
32
years. During the first quarter of 2006, we extended the useful life to 35
years
for one rig, which had an estimated useful life of 30 years. We determined
35
years was appropriate for each of these rigs based on the then current contracts
these rigs were operating under as well as the additional life-extending work,
upgrades and inspections we performed on these rigs. In 2006, 2005 and 2004,
the
impact of the change in estimated useful life of these rigs was a reduction
in
depreciation expense of $2 million ($0.01 per diluted share), $16 million ($0.05
per diluted share) and $5 million ($0.01 per diluted share), respectively,
which
had no tax effect.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Assets
Held for Sale—Assets
are classified as held for sale when we have a plan for disposal and those
assets meet the held for sale criteria of the Financial Accounting Standards
Board's (“FASB”) Statement of Financial Accounting Standards (“SFAS”) No. 144,
Accounting
for Impairment or Disposal of Long-Lived Assets.
At
December 31, 2006 and 2005, we had assets held for sale in the amounts of $11
million and $16 million, respectively, that were included in other current
assets (see Note 6—Asset
Dispositions).
Goodwill—In
accordance with SFAS No. 142, Goodwill
and Other Intangible Assets (“SFAS
142”), goodwill is tested for impairment at least annually at the reporting unit
level, which is defined as an operating segment or a component of an operating
segment that constitutes a business for which financial information is available
and is regularly reviewed by management. Management has determined that our
reporting units are the same as our operating segments for the purpose of
allocating goodwill and the subsequent testing of goodwill for impairment.
Since
the
disposition of TODCO, we operate in one operating segment (see Note 1), which
is
also our reporting unit for the test of goodwill impairment. The goodwill
impairment test performed at October 1, 2004 was carried forward to October1,2005 and 2006 since it met all necessary carry forward criteria within the
scope
of SFAS 142. We perform our annual test of goodwill impairment as of October
1.
As a result of these tests for impairment, we had no impairment of goodwill
for
the years ended December 31, 2006, 2005 and 2004.
Our
goodwill balance and changes in the carrying amount of goodwill are as follows
(in millions):
Primarily
represents net adjustments during 2006 of income tax-related
pre-acquisition contingencies.
Impairment
of Long-Lived Assets—The
carrying value of long-lived assets, principally property and equipment, is
reviewed for potential impairment when events or changes in circumstances
indicate that the carrying amount of such assets may not be recoverable. For
property and equipment held for use, the determination of recoverability is
made
based upon the estimated undiscounted future net cash flows of the related
asset
or group of assets being evaluated. Property and equipment held for sale are
recorded at the lower of net book value or fair value.
Operating
Revenues and Expenses—Operating
revenues are recognized as earned, based on contractual daily rates or on a
fixed price basis. In connection with drilling contracts, we may receive
revenues for preparation and mobilization of equipment and personnel or for
capital improvements to rigs. In connection with new drilling contracts,
revenues earned and incremental costs incurred directly related to preparation
and mobilization are deferred and recognized over the primary contract term
of
the drilling project using the straight-line method. Our policy to amortize
the
fees related to preparation, mobilization and capital upgrades on a
straight-line basis over the estimated firm period of drilling is consistent
with the general pace of activity, level of services being provided and dayrates
being earned over the life of the contract. For contractual daily rate
contracts, we account for loss contracts as the losses are incurred. Costs
of
relocating drilling units without contracts to more promising market areas
are
expensed as incurred. Upon completion of drilling contracts, any demobilization
fees received are reported in income, as are any related expenses. Capital
upgrade revenues received are deferred and recognized over the primary contract
term of the drilling project. The actual cost incurred for the capital upgrade
is depreciated over the estimated useful life of the asset. We incur periodic
survey and drydock costs in connection with obtaining regulatory certification
to operate our rigs on an ongoing basis. Costs associated with these
certifications are deferred and amortized over the period until the next survey
on a straight-line basis.
Other
Revenue—Our
other revenue represents client reimbursable revenue, integrated services
revenue and other miscellaneous revenues. We consider client reimbursable
revenues to be billings to our client for reimbursement of certain equipment,
materials and supplies, third party services, employee bonuses and out-of-pocket
expenses that we incur and recognize in operating and maintenance expense,
which
results in little or no effect on operating income. We refer to integrated
services as those that we provide under certain contracts that include well
and
logistics services in addition to our normal drilling services through third
party contractors and our employees.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Capitalized
Interest—We
capitalize interest costs for qualifying construction and upgrade projects.
We
capitalized interest costs on construction work in progress of $16 million
for
the year ended December 31, 2006. There was no capitalized interest for the
years ended December 31, 2005 and 2004.
Derivative
Instruments and Hedging Activities—We
account for our derivative instruments and hedging activities in accordance
with
SFAS No. 133, Accounting
for Derivative Instruments and Hedging Activities.
See
Note 8—Financial
Instruments and Risk Concentration and Note 9—Interest
Rate Swaps.
Foreign
Currency—The
majority of our revenues and expenditures are denominated in U.S. dollars to
limit our exposure to foreign currency fluctuations, resulting in the use of
the
U.S. dollar as the functional currency for all of our operations. Foreign
currency exchange gains and losses are primarily included in other income
(expense) as incurred. Net foreign currency gains (losses) included in other
income (expense) were $(3) million and $(4) million, for the years ended
December 31, 2006 and 2005, respectively. The foreign currency gains (losses)
for the year ended December 31, 2004 were immaterial to the financial
statements.
Income
Taxes—Income
taxes have been provided based upon the tax laws and rates in effect in the
countries in which operations are conducted and income is earned. There is
no
expected relationship between the provision for or benefit from income taxes
and
income or loss before income taxes because the countries in which we operate
have taxation regimes that vary not only with respect to nominal rate, but
also
in terms of the availability of deductions, credits and other benefits.
Variations also arise because income earned and taxed in any particular country
or countries may fluctuate from year to year. Deferred tax assets and
liabilities are recognized for the anticipated future tax effects of temporary
differences between the financial statement basis and the tax basis of our
assets and liabilities using the applicable tax rates in effect at year end.
A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that some or all of the benefit from the deferred tax asset will not
be
realized. See Note 15—Income
Taxes.
Share-Based
Compensation—On
January 1, 2006, we adopted SFAS No. 123 (revised 2004), Share-Based
Payment (“SFAS
123(R)”), which is a revision of SFAS No. 123, Accounting
for Stock-Based Compensation
(“SFAS
123”). SFAS 123(R) supersedes Accounting Principles Board (“APB”) Opinion No.
25, Accounting
for Stock Issued to Employees (“APB
25”), and amends SFAS No. 95, Statement
of Cash Flows (“SFAS
95”). While the approach in SFAS 123(R) is similar to the approach described in
SFAS 123, SFAS 123(R) requires recognition in the income statement of all
share-based payments to employees, including grants of employee stock options
based on their fair values and pro forma disclosure is no longer an alternative.
In March 2005, the Securities and Exchange Commission (“SEC”) issued Staff
Accounting Bulletin (“SAB”) No. 107, Share-Based
Payment (“SAB
107”), relating to SFAS 123(R). We have applied the provisions of SAB 107 in our
adoption of SFAS 123(R).
We
adopted SFAS 123(R) using the modified prospective method (“Prospective
Method”), which requires the application of SFAS 123(R) as of January 1, 2006.
Our consolidated financial statements as of and for the year ended December31,2006 reflect the application of SFAS 123(R). In accordance with the Prospective
Method, our consolidated financial statements for prior periods have not been
restated to reflect, and do not include, the application of SFAS 123(R).
Share-based compensation expense for the years ended December 31 are as follows
(in millions):
Income
tax benefit on share-based compensation expense
(2
)
(3
)
(7
)
SFAS
123(R) requires forfeitures to be estimated at the time of grant and revised,
if
necessary, in subsequent periods if actual forfeitures differ from those
estimates. Additionally, SFAS 123(R) requires the estimated forfeiture rate
be
applied and the cumulative effect determined for all prior periods in which
share-based compensation costs have been recorded. Prior to our adoption of
SFAS
123(R), we accounted for forfeitures as they occurred. Upon adopting SFAS
123(R), we estimated expected forfeitures over the life of each individual
award
and have included the impact of these expected forfeitures in our share-based
compensation expense for the year ended December 31, 2006 in addition to all
prior periods on a cumulative basis. The effect of this change is to reverse
compensation cost recognized in prior period financial statements for awards
that are not expected to vest based upon the expected forfeiture rate. The
cumulative effect of applying the expected forfeiture rate has been included
in
operating and maintenance expense and general and administrative expense, the
impact of which had no material effect on our consolidated financial position,
results of operations or cash flows.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We
adopted SFAS 123 effective January 1, 2003 and accounted for share-based
compensation prospectively for all share-based awards granted or modified on
or
subsequent to that date. As such, adoption of SFAS 123(R) using the Prospective
Method had no material impact on our consolidated financial position, results
of
operations or cash flows. In addition to the compensation cost recognition
requirements, SFAS 123(R) also requires the tax deduction benefits for an award
in excess of recognized compensation cost to be reported as a financing cash
flow rather than as an operating cash flow, which was required under SFAS 95.
We
reported operating cash flows related to tax deduction benefits of $22 million
and $6 million for the years ended December 31, 2005 and 2004,
respectively.
Under
SFAS 123, we recognized compensation cost on a straight line basis over the
vesting period up to the date of actual retirement. We will continue this
practice for awards granted prior to adoption of SFAS 123(R). As a result
of the
adoption of SFAS 123(R), we now recognize compensation cost on a straight
line
basis for time-based awards granted or modified after January 1, 2006 through
the date the employee is no longer required to provide service to earn the
award
(“service period”). For performance-based awards with graded vesting conditions
that are granted or modified after January 1, 2006, compensation expense
is
recognized on a straight line basis over the service period for each separately
vesting portion of the award as if the award was, in substance, multiple
awards.
If we had amortized compensation cost over the service period prior to adoption
of SFAS 123(R), share-based compensation expense would not have been materially
different for any of the periods presented.
Prior
to
January 1, 2003, we accounted for share-based awards to employees under the
provisions of SFAS 123 using the intrinsic value method prescribed by APB 25
and
related interpretations. If compensation expense for grants to employees under
our long-term incentive plan prior to January 1, 2003 had been recognized using
the fair value method of accounting under SFAS 123, net income and earnings
per
share for the years ended December 31, 2005 and 2004 would have been reduced
to
the pro forma amounts indicated below (in millions, except per share
data):
Add
back: Share-based compensation expense included in reported net income,
net of related tax effects
13
18
Deduct:
Total share-based compensation expense determined under the fair
value
method for all awards, net of related tax effects
Long-Term
Incentive Plan
(11
)
(22
)
Employee
Stock Purchase Plan (“ESPP”)
(4
)
(3
)
Pro
Forma Net Income
$
714
$
145
Basic
Earnings Per Share
As
Reported
$
2.19
$
0.47
Pro
Forma
2.18
0.45
Diluted
Earnings Per Share
As
Reported
$
2.13
$
0.47
Pro
Forma
2.12
0.45
The
above
pro forma amounts are not indicative of future results. The fair value of each
option grant under our long-term incentive plan was estimated on the date of
grant using the Black-Scholes-Merton option pricing model with the following
weighted-average assumptions used:
New
Accounting Pronouncements—In
July
2006, the FASB issued FASB Interpretation No. 48, Accounting
for Uncertainty in Income Taxes—an interpretation of FASB Statement No.
109
(“FIN
48”). FIN 48 clarifies the accounting for income taxes recognized in an entity’s
financial statements in accordance with SFAS No. 109, Accounting
for Income Taxes.
It
prescribes a minimum recognition threshold and measurement attribute for
recognizing and measuring the benefit of tax positions taken or expected to
be
taken in a tax return. FIN 48 also provides guidance on 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
will
be required to adopt this interpretation in the first quarter of fiscal year
2007. Management is in the process of quantifying the impact of FIN 48 on the
consolidated financial statements and has not yet finalized its evaluation.
In
September 2006, the FASB issued SFAS No. 157, Fair
Value Measurements (“SFAS
157”). SFAS 157 defines fair value, establishes a framework for measuring fair
value in generally accepted accounting principles, and expands disclosures
about
fair value measurements. SFAS 157 applies under other accounting pronouncements
that require or permit fair value measurements because the FASB previously
concluded in those accounting pronouncements that fair value is the relevant
measurement attribute. Accordingly, SFAS 157 does not require any new fair
value
measurements. SFAS 157 is effective for fiscal years beginning after November15, 2007. We will be required to adopt SFAS 157 in the first quarter of fiscal
year 2008. Management is currently evaluating the requirements of SFAS 157
and
has not yet determined the impact on the consolidated financial
statements.
In
February 2007, the FASB issued SFAS No. 159, The
Fair Value Option for Financial Assets and Financial Liabilities
(“SFAS
159”). SFAS 159 provides companies with an option to report selected financial
assets and liabilities at fair value. It also establishes presentation and
disclosure requirements designed to facilitate comparisons between companies
that choose different measurement attributes for similar types of assets and
liabilities. SFAS 159 is effective as of the beginning of the first fiscal
year
beginning after November 15, 2007. We will be required to adopt SFAS 159 in
the
first quarter of fiscal year 2008. Management is currently evaluating the
requirements of SFAS 159 and has not yet determined the impact on the
consolidated financial statements.
In
June
2006, the FASB reached consensus on Emerging Issues Task Force ("EITF") No.
06-3, "How Taxes Collected from Customers and Remitted to Governmental
Authorities Should be Presented in the Income Statement" ("EITF 06-3"). The
scope of EITF 06-3 includes 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
excise taxes. The Task Force affirmed its conclusion that entities should
present these taxes in the consolidated statement of operations on either a
gross or a net basis, based on their accounting policy, which should be
disclosed pursuant to APB Opinion No. 22, Disclosure
of Accounting Policies.
If
those taxes are significant, and are presented on a gross basis, the amounts
of
those taxes should be disclosed. The consensus on EITF 06-3 is effective as
of
the beginning of the first fiscal year beginning after December 15, 2006. We
generally record our tax-assessed revenue transactions on a net basis in our
consolidated statements of operations; therefore, we do not expect EITF 06-3
to
have a material effect on our consolidated balance sheet, statement of
operations or cash flows.
Reclassifications—Certain
reclassifications have been made to prior period amounts to conform with the
current year presentation. These reclassifications did not have a material
effect on the consolidated financial statements.
Adjustment
to initially apply SFAS 158 resulting in a net adjustment of $26
million.
Note
4—TODCO Stock Sales
In
February 2004, we completed the TODCO IPO in which we sold 13.8 million shares
of TODCO’s class A common stock, representing 23 percent of TODCO’s total
outstanding shares, at $12.00 per share. We received net proceeds of $156
million from the TODCO IPO and recognized a gain of $39 million ($0.12 per
diluted share), which had no tax effect, in the first quarter of 2004 and
represented the excess of net proceeds received over the net book value of
the
shares sold in the TODCO IPO.
In
conjunction with the closing of the TODCO IPO, TODCO granted restricted shares
and stock options to some of its employees under its long-term incentive plan
and some of these awards vested at the time of grant. In accordance with the
provisions of SFAS 123, TODCO recognized compensation expense of $6 million
($0.02 per Transocean’s diluted share), which had no tax effect, in the first
quarter of 2004 as a result of the immediate vesting of these awards. In
addition, certain of TODCO’s employees held options that were granted prior to
the TODCO IPO to acquire our ordinary shares. In accordance with the employee
matters agreement with TODCO, these options were modified at the TODCO IPO
date,
which resulted in the accelerated vesting of the options and the extension
of
the term of the options through the original contractual life. In connection
with the modification of these options, TODCO recognized additional compensation
expense of $2 million, which had no tax effect, in the first quarter of 2004.
In
September 2004, we completed the September 2004 Offering in which we sold 18.0
million shares of TODCO’s class A common stock, representing 30 percent of
TODCO’s total outstanding shares, at $15.75 per share. We received net proceeds
of $270 million from the September 2004 Offering and recognized a gain of $129
million ($0.40 per diluted share), which had no tax effect, in the third quarter
of 2004 and represented the excess of net proceeds received over the net book
value of the TODCO shares sold in the September 2004 Offering.
In
December 2004, we completed the December 2004 Offering in which we sold 15.0
million shares of TODCO’s class A common stock, representing 25 percent of
TODCO’s total outstanding shares, at $18.00 per share. We received net proceeds
of $258 million from the December 2004 Offering and recognized a gain of $140
million ($0.43 per diluted share), which had no tax effect, in the fourth
quarter of 2004 and represented the excess of net proceeds received over the
net
book value of the TODCO shares sold in the December 2004 Offering.
We
sold
12.0 million shares of TODCO’s class A common stock, representing 20 percent of
TODCO’s total outstanding shares, at $20.50 per share in the May Offering. We
sold our remaining 1.3 million shares of TODCO’s class A common stock,
representing two percent of TODCO’s total outstanding shares, at $23.57 per
share in the June Sale. We received net proceeds of $272 million from the 2005
Offering and Sale and recognized a gain in the second quarter of 2005 of $165
million ($0.49 per diluted share), which had no tax effect and represented
the
excess of net proceeds received over the net book value of the shares sold
in
the 2005 Offering and Sale.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
5—Drilling Fleet Expansion, Upgrades and Acquisition
Capital
expenditures, including capitalized interest, totaled $876 million during the
year ended December 31, 2006 and related to the construction of three enhanced
Enterprise-class drillships totaling $460 million and two Sedco
700-series rig upgrades totaling $150 million. The remaining $266 million
related to corporate infrastructure and our existing fleet, including the
replacement of equipment damaged during hurricanes Katrina and Rita on the
semisubmersible rigs Deepwater
Nautilus
and the
Transocean
Marianas
and the
reactivation of three of our Other Floaters.
In
March
2006, we were awarded a five-year drilling contract for an enhanced
Enterprise-class drillship, to be named the Discoverer
Clear Leader.
We
estimate total capital expenditure for the construction of this rig to be
approximately $630 million, excluding capitalized interest, but including
approximately $30 million for additional equipment requested by the client
for
which the client has agreed to an increased dayrate. This rig is expected to
be
operational in 2009.
In
June
2006, we were awarded a four-year drilling contract for another enhanced
Enterprise-class drillship. We estimate total capital expenditure for the
construction of this rig to be approximately $630 million, excluding capitalized
interest, but including approximately $11 million for additional equipment
requested by the client for which the client has agreed to an increased dayrate.
This rig is expected to be operational in 2009.
In
August
2006, were awarded a drilling contract for a third enhanced Enterprise-class
drillship, to be named the Discoverer
Inspiration.
We
estimate total capital expenditure for the construction of this rig to be
approximately $670 million, excluding capitalized interest. This amount includes
approximately $40 million for equipment that was not included in the original
costs of the other two enhanced Enterprise-class drillships. This rig is
expected to be operational in 2010.
Capital
expenditures totaled $182 million during the year ended December 31, 2005 and
related to corporate infrastructure and our existing fleet, including the
replacement of equipment damaged during hurricanes Katrina and Rita on the
Deepwater
Nautilus
and the
Transocean
Marianas
and the
purchase of the M.G.
Hulme, Jr.,
which
we had previously operated under a lease arrangement that resulted from a
sale/leaseback transaction with a special purpose entity (see Note
16—Off-Balance Sheet Arrangement).
Capital
expenditures totaled $127 million during the year ended December 31, 2004 and
related to our existing fleet and corporate infrastructure. A substantial
majority of the capital expenditures in 2004 related to the Transocean Drilling
segment. See Note 21—Segments, Geographical Analysis and Major
Customers.
Note
6—Asset Dispositions
During
2006, we sold three of our Other Floaters (Peregrine
III, Transocean Explorer and
Transocean
Wildcat),
three
of our tender rigs (W.D.
Kent, Searex IX
and
Searex X),
a
swamp barge (Searex
XII)
and a
platform rig. We received net proceeds from these sales of $464 million and
recognized gains on the sales of $411 million ($386 million, or $1.19 per
diluted share, net of tax). In addition, we sold and disposed of certain other
assets for net proceeds of $5 million and recognized net losses of $6 million
($0.02 per diluted share), which had no tax effect.
In
August
2006, we entered into agreements to sell Transocean CGR LLC (owner of the tender
rig Charley
Graves)
and the
drilling barge Searex
VI
in
connection with our efforts to dispose of non-strategic assets. We received
deposits totaling $1 million, which was reflected as unearned income and
included in other current liabilities in our consolidated balance sheet at
December 31, 2006. At December 31, 2006, the Charley
Graves
and
Searex
VI were
classified as
assets
held for sale in the amounts of $8 million and $2 million, respectively, and
were included in other current assets in our consolidated balance sheet. See
Note 2―Summary of Significant Accounting Policies and Note 26―Subsequent Events.
During
2005, we sold an Other Floater (Sedco
600),
a
Jackup rig (Transocean
Jupiter)
and a
land rig. We received net proceeds from these sales of $49 million and
recognized gains on the sales of $33 million ($28 million, or $0.08 per diluted
share, net of tax). In addition, we sold and disposed of certain other assets
for net proceeds of $18 million and we recognized net losses of $4 million
($0.01 per diluted share), which had no tax effect.
During
2004, we sold an Other Floater (Sedco
602)for
net
proceeds of $28 million and recognized a gain on the sale of $22 million ($0.07
per diluted share), which had no tax effect, in our Transocean Drilling segment.
In addition, we settled insurance claims and sold and disposed of marine support
vessels and certain other assets for net proceeds of $22 million. We recognized
net losses of $8 million ($4 million, or $0.01 per diluted share, net of tax)
in
our Transocean Drilling segment and net gains of $6 million ($0.02 per diluted
share), which had no tax effect, in our TODCO segment.
Zero
Coupon Convertible Debentures, due May 2020 (put options exercisable
May 2008 and May 2013)
18
17
1.5%
Convertible Debentures, due May 2021 (put options exercisable May
2011and
May 2016) (a)
400
400
8%
Debentures, due April 2027
57
57
7.45%
Notes, due April 2027 (put options exercisable April
2007)(b)
95
95
7.5%
Notes, due April 2031
598
598
Total
Debt
3,295
1,597
Less
Debt Due Within One Year (a)(b)
95
400
Total
Long-Term Debt
$
3,200
$
1,197
______________________
(a)
The
1.5% Convertible Debentures were classified as debt due within one
year at
December 31, 2005 since the holders had the option to require us to
repurchase the debentures in May
2006.
(b)
The
7.45% Notes are classified as debt due within one year at December31,2006 since
the holders can exercise their right to require us to repurchase
the notes
in April 2007.
The
scheduled maturity of our debt assumes the bondholders exercise their options
to
require us to repurchase the 7.45% Notes, Zero Coupon Convertible Debentures
and
1.5% Convertible Debentures in April 2007, May 2008 and May 2011, respectively.
All amounts are at face value except for the Zero Coupon Convertible Debentures,
which are included at the price we would be required to pay should the
bondholders exercise their right to require us to repurchase the debentures
in
May 2008. The scheduled maturities are as follows (in millions):
Revolving
Credit Facility—In
July
2005,
we
entered into a $500 million, five-year revolving credit agreement (“Revolving
Credit Facility”). In May 2006, we increased the credit limit on the facility
from $500 million to $1.0 billion and extended the maturity date by one year
from July 2010 to July 2011.
The
Revolving Credit Facility bears interest, at our option, at a base rate or
at
the London Interbank Offered Rate (“LIBOR”) plus a margin that can vary from
0.19 percent to 0.58 percent depending on our non-credit enhanced senior
unsecured public debt rating. A facility fee, varying from 0.06 percent to
0.17
percent depending on our non-credit enhanced senior unsecured public debt
rating, is incurred on the daily amount of the underlying commitment, whether
used or unused, throughout the term of the facility. A utilization fee, varying
from 0.05 percent to 0.10 percent depending on our non-credit enhanced senior
unsecured public debt rating, is payable if amounts outstanding under the
Revolving Credit Facility are greater than or equal to 50 percent of the total
underlying commitment. At December 31, 2006, the applicable margin, facility
fee
and utilization fee were 0.225 percent, 0.075 percent and 0.100 percent,
respectively. The Revolving Credit Facility requires compliance with various
covenants and provisions customary for agreements of this nature, including
a
debt to total tangible capitalization ratio, as defined by the Revolving Credit
Facility, of not greater than 60 percent. At December 31, 2006, we had no
borrowings outstanding and $1.0 billion remained available under this
facility.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Term
Credit Facility—In
August 2006, we entered into a two-year term credit facility under the Term
Credit Agreement dated August 30, 2006 (“Term Credit Facility”). Under the terms
of the Term Credit Facility, we were able to request borrowings up to $1.0
billion over the first six months of the term. After six months, any unused
capacity is cancelled. Once repaid, the funds cannot be reborrowed. At our
election, borrowings may be made under the Term Credit Facility at either
(i) the base rate, determined as the greater of (a) the prime loan
rate and (b) the sum of the weighted average overnight federal funds rate
plus 0.50 percent, or (ii) LIBOR plus 0.30 percent, based on current credit
ratings. We paid a fee of 0.065 percent per annum on the daily amount of the
unused commitments under the Term Credit Facility through October 3, 2006.
In
October 2006, we borrowed the full $1.0 billion in capacity. At December 31,2006, we had $700 million outstanding at a weighted-average interest rate of
5.65 percent.
Floating
Rate Notes—In
September 2006, we issued $1.0 billion aggregate principal amount of floating
rate notes, due September 2008 (“Floating Rate Notes”). We are required to pay
interest on the Floating Rate Notes on March 5, June 5, September 5 and December
5 of each year, beginning on December 5, 2006. The per annum interest rate
on
the Floating Rate Notes is equal to the three month LIBOR, reset on each payment
date, plus 0.20 percent. We may redeem some or all of the notes at any time
after September 2007 at a price equal to 100 percent of the principal amount
plus accrued and unpaid interest, if any. At December 31, 2006, $1.0 billion
principal amount of these notes was outstanding at an interest rate of 5.57
percent.
6.625%
Notes and 7.5% Notes—In
April
2001, we issued $700 million aggregate principal amount of 6.625% Notes due
April 2011 and $600 million aggregate principal amount of 7.5% Notes due April
2031. At December 31, 2006, $166 million and $600 million principal amount
of
the 6.625% Notes and 7.5% Notes, respectively, were outstanding (see “—Debt
Redemptions and Repayments”).
6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5%Senior
Notes and Exchange Offer—In
March
2002, we completed exchange offers and consent solicitations for TODCO’s 6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes (“the Exchange Offer”). After
the Exchange Offer, approximately $5 million, $8 million, $2 million, $4
million, $10 million and $10 million principal amount of the outstanding 6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged
remained the obligation of TODCO. At December 31, 2006, $247 million principal
amount of 7.375% Senior Notes were outstanding. TODCO’s remaining Senior Notes
were deconsolidated from our consolidated balance sheets at December 31, 2004
(see Note 4—TODCO Stock Sales). See
“―Debt
Redemptions and Repayments.”
1.5%
Convertible Debentures—In
May
2001, we issued $400 million aggregate principal amount of 1.5% Convertible
Debentures due May 2021. We have the right to redeem the debentures for a price
equal to 100 percent of the principal. Each holder has the right to require
us
to repurchase the debentures after five, 10 and 15 years at 100 percent of
the
principal amount (see “—Debt Redemptions and Repayments”). We may pay this
repurchase price with either cash or ordinary shares or a combination of cash
and ordinary shares. The debentures are convertible into our ordinary shares
at
the option of the holder at any time at a ratio of 13.8627 shares per $1,000
principal amount debenture, which is equivalent to an initial conversion price
of $72.136 per share. This ratio is subject to adjustments if certain events
take place, and conversion may only occur if the closing sale price per ordinary
share exceeds 110 percent of the conversion price for at least 20 trading days
in a period of 30 consecutive trading days ending on the trading day immediately
prior to the conversion date or if other specified conditions are met. At
December 31, 2006, $400 million principal amount of these notes was outstanding.
Zero
Coupon Convertible Debentures—In
May
2000, we issued Zero Coupon Convertible Debentures due May 2020 with a face
value at maturity of $865.0 million. The debentures were issued to the public
at
a price of $579.12 per debenture and accrue original issue discount at a rate
of
2.75 percent per annum compounded semiannually to reach a face value at maturity
of $1,000 per debenture. We will pay no interest on the debentures prior to
maturity and, since May 2003, we have the right to redeem the debentures for
a
price equal to the issuance price plus accrued original issue discount to the
date of redemption. Each holder has the right to require us to repurchase the
debentures on the third, eighth and thirteenth anniversary of issuance at the
issuance price plus accrued original issue discount to the date of repurchase.
We may pay this repurchase price with either cash or ordinary shares or a
combination of cash and ordinary shares. The debentures are convertible into
our
ordinary shares at the option of the holder at any time at a ratio of 8.1566
shares per debenture, which is equivalent to an initial conversion price of
$71.00 per share, subject to adjustments if certain events take place. At
December 31, 2006, $26 million face value of these notes was outstanding with
a
discounted value of $18 million. Should all of the debentures be put to us
in
May 2008, the debentures will have a discounted value of $19
million.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
7.45%
Notes and 8% Debentures—In
April
1997, we issued $100 million aggregate principal amount of 7.45% Notes due
April
2027 and $200 million aggregate principal amount of 8% Debentures due April
2027. Holders of the 7.45% Notes may elect to have all or any portion of the
7.45% Notes repaid in April 2007 at 100 percent of the principal amount. The
7.45% Notes, at any time after April 2007, and the 8% Debentures, at any time,
are redeemable at our option at a make-whole premium. At December 31, 2006,
$100
million and $57 million principal amount of these notes was outstanding,
respectively (see “—Debt Redemptions and Repayments”).
Debt
Redemptions and Repayments—Holders
of our 1.5% Convertible Debentures, due May 15, 2021 had the option to require
us to repurchase their debentures in May 2006; however, no holders exercised
such right. In May 2006, holders of $101,000 aggregate principal amount
converted their debentures into ordinary shares at a conversion rate of 13.8627
ordinary shares per $1,000 debenture, resulting in the issuance of 1,399
ordinary shares. In
July
2005, we acquired, pursuant to a tender offer, a total of $534 million, or
approximately 76.3 percent, of the aggregate principal amount of our 6.625%
Notes due April 2011 at 110.578 percent of face value, or $591 million, plus
accrued and unpaid interest.
In
March
2005, we redeemed our outstanding 6.95% Senior Notes due April 2008 at the
make-whole premium price provided in the indenture. We recognized a loss on
the
redemption of debt of $7 million ($0.02 per diluted share), which had no tax
effect.
In
December 2004, we acquired, pursuant to a tender offer, a total of $143 million
aggregate principal amount of our 8% Debentures due April 2027 at 130.449
percent of face value, or $186 million. We recognized a loss on the repurchase
of $45 million ($0.14 per diluted share), which had no tax effect.
In
October 2004, we redeemed our $342 million aggregate principal amount
outstanding 6.75% Senior Notes due April 2005 at the make-whole premium price
provided in the indenture. We redeemed these notes at 102.127 percent of face
value or $350 million. We recognized a loss on the redemption of $3 million
($0.01 per diluted share), which had no tax effect.
In
March
2004, we redeemed our $290 million aggregate principal amount outstanding 9.5%
Senior Notes due December 2008 at the make-whole premium price provided in
the
indenture. We redeemed these notes at 127.796 percent of face value or $370
million. We recognized a loss on the redemption of debt of $28 million ($0.09
per share), which had no tax effect.
Note
8—Financial
Instruments and Risk Concentration
Foreign
Exchange Risk—Our
international operations expose us to foreign exchange risk. This risk is
primarily associated with compensation costs denominated in currencies other
than the U.S. dollar, which is our functional currency, and with purchases
from
foreign suppliers. We use a variety of techniques to minimize the exposure
to
foreign exchange risk, including customer contract payment terms and the
possible use of foreign exchange derivative instruments.
Our
primary foreign exchange risk management strategy involves structuring customer
contracts to provide for payment in both U.S. dollars and local currency. The
payment portion denominated in local currency is based on anticipated local
currency requirements over the contract term. Due to various factors, including
customer acceptance, local banking laws, other statutory requirements, local
currency convertibility and the impact of inflation on local costs, actual
foreign exchange needs may vary from those anticipated in the customer
contracts, resulting in partial exposure to foreign exchange risk. Fluctuations
in foreign currencies typically have not had a material impact on overall
results. In situations where payments of local currency do not equal local
currency requirements, foreign exchange derivative instruments, specifically
foreign exchange forward contracts, or spot purchases, may be used to mitigate
foreign currency risk. A foreign exchange forward contract obligates us to
exchange predetermined amounts of specified foreign currencies at specified
exchange rates on specified dates or to make an equivalent U.S. dollar payment
equal to the value of such exchange.
We
do not
enter into derivative transactions for speculative purposes. Gains and losses
on
foreign exchange derivative instruments, which qualify as accounting hedges,
are
deferred as other comprehensive income and recognized when the underlying
foreign exchange exposure is realized. Gains and losses on foreign exchange
derivative instruments, which do not qualify as hedges for accounting purposes,
are recognized currently based on the change in market value of the derivative
instruments. At December 31, 2006 and 2005, we had no outstanding foreign
exchange derivative instruments.
Interest
Rate Risk—Our
use
of debt directly exposes us to interest rate risk. Floating rate debt, where
the
interest rate can be changed every year or less over the life of the instrument,
exposes us to short-term changes in market interest rates. Fixed rate debt,
where the interest rate is fixed over the life of the instrument and the
instrument's maturity is greater than one year, exposes us to changes in market
interest rates should we refinance maturing debt with new debt.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
addition, we are exposed to interest rate risk in our cash investments, as
the
interest rates on these investments change with market interest
rates.
From
time
to time, we may use interest rate swap agreements to manage the effect of
interest rate changes on future income. These derivatives are used as hedges
and
are not used for speculative or trading purposes. Interest rate swaps are
designated as a hedge of underlying future interest payments. These agreements
involve the exchange of amounts based on variable interest rates and amounts
based on a fixed interest rate over the life of the agreement without an
exchange of the notional amount upon which the payments are based. The interest
rate differential to be received or paid on the swaps is recognized over the
lives of the swaps as an adjustment to interest expense. Gains and losses on
terminations of interest rate swap agreements are deferred and recognized as
an
adjustment to interest expense over the remaining life of the underlying debt.
In the event of the early retirement of a designated debt obligation, any
realized or unrealized gain or loss from the swap would be recognized in
income.
The
major
risks in using interest rate derivatives include changes in interest rates
affecting the value of such instruments, potential increases in our interest
expense due to market increases in floating interest rates in the case of
derivatives that exchange fixed interest rates for floating interest rates
and
the credit worthiness of the counterparties in such transactions.
We
had no
interest rate swap transactions outstanding as of December 31, 2006 and 2005.
See Note 9—Interest Rate Swaps.
The
market values of any open swap transactions would be carried on our consolidated
balance sheet as an asset or liability depending on the movement of interest
rates after the transaction is entered into and depending on the security being
hedged.
Should
a
counterparty default at a time in which the market value of the swap with that
counterparty is classified as an asset in our consolidated balance sheet, we
may
be unable to collect on that asset. To mitigate such risk of failure, we enter
into swap transactions with a diverse group of high-quality
institutions.
Credit
Risk—Financial
instruments that potentially subject us to concentrations of credit risk are
primarily cash and cash equivalents and trade receivables. It is our practice
to
place our cash and cash equivalents in time deposits at commercial banks with
high credit ratings or mutual funds, which invest exclusively in high quality
money market instruments. In foreign locations, local financial institutions
are
generally utilized for local currency needs. We limit the amount of exposure
to
any one institution and do not believe we are exposed to any significant credit
risk.
We
derive
the majority of our revenue from services to international oil companies and
government-owned and government-controlled oil companies. Receivables are
dispersed in various countries. See Note 21—Segments, Geographical Analysis and
Major Customers. We maintain an allowance for doubtful accounts receivable
based
upon expected collectibility and establish reserves for doubtful accounts on
a
case-by-case basis when we believe the required payment of specific amounts
owed
to us is unlikely to occur. We are not aware of any significant credit risks
relating to our customer base and do not generally require collateral or other
security to support customer receivables.
Labor
Agreements—We
require highly skilled personnel to operate our drilling units. As a result,
we
conduct extensive personnel recruiting, training and safety programs. At
December 31, 2006, we had approximately 10,800 employees and we also utilized
approximately 1,700 persons through contract labor providers. As of such date,
approximately 15 percent of our employees and contract labor worldwide worked
under collective bargaining agreements, most of whom worked in Norway, U.K.
and
Nigeria. Of these represented individuals, 60 percent are working under
agreements that are subject to salary negotiation in 2007.
Note
9—Interest
Rate Swaps
In
June
2001, we entered into interest rate swap agreements in the aggregate notional
amount of $700 million with a group of banks relating to our $700 million
aggregate principal amount of 6.625% Notes due April 2011. In February 2002,
we
entered into interest rate swap agreements with a group of banks in the
aggregate notional amount of $900 million relating to our $350 million aggregate
principal amount of 6.75% Senior Notes due April 2005, $250 million aggregate
principal amount of 6.95% Senior Notes due April 2008 and $300 million aggregate
principal amount of 9.5% Senior Notes due December 2008. The objective of each
transaction was to protect the debt against changes in fair value due to changes
in the benchmark interest rate. Under each interest rate swap, we received
the
fixed rate equal to the coupon of the hedged item and paid LIBOR plus a
specified margin, which was designated as the respective benchmark interest
rates, on each of the interest payment dates until maturity of the respective
notes. The hedges were considered perfectly effective against changes in the
fair value of the debt due to changes in the benchmark interest rates over
their
term. As a result, the shortcut method applied and there was no requirement
to
periodically reassess the effectiveness of the hedges during the term of the
swaps.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
January 2003, we terminated all our outstanding interest rate swaps, which
were
designated as fair value hedges, and recorded $174 million as a fair value
adjustment to the underlying long-term debt in our consolidated balance sheet.
We amortize this amount as a reduction to interest expense over the remaining
life of the underlying debt. During the years ended December 31, 2006, 2005
and
2004, such reduction amounted to $3 million ($0.01 per diluted share), $9
million ($0.03 per diluted share) and $23 million ($0.07 per diluted share),
respectively. As a result of the redemption of our 6.95% Senior Notes in March
2005, 6.75% Senior Notes in October 2004 and 9.5% Senior Notes in March 2004,
we
recognized $13 million ($0.08 per diluted share) and $26 million ($0.08 per
diluted share) during the years ended December 31, 2005 and 2004, respectively,
of the unamortized fair value adjustment as a reduction to our loss on
redemption of debt (see Note 7—Debt). As a result of the repurchase of our
6.625% Notes in July 2005, we recognized $62 million of the unamortized fair
value adjustment as a reduction to our loss on repurchase of debt, which
resulted in a gain on this repurchase (see Note 7—Debt). There were no tax
effects related to these reductions. At December 31, 2006 and 2005, the
remaining balance to be amortized was $15 million and $18 million, respectively,
and related to the 6.625% Notes due April 2011.
The
following methods and assumptions were used to estimate the fair value of each
class of financial instruments for which it is practicable to estimate that
value:
Cash
and Cash Equivalents and Accounts Receivable-Trade—The
carrying amounts approximate fair value because of the short maturity of those
instruments.
Debt—The
fair
value of our fixed rate debt is calculated based on market prices. The carrying
value of variable rate debt approximates fair value.
Accrued
retiree life insurance and medical benefits
35
36
Deferred
revenue
28
16
Other
55
53
Total
Other Long-Term Liabilities
$
343
$
286
Note
13—Repurchase
of Ordinary Shares
In
October 2005, our board of directors authorized the repurchase of up to $2.0
billion of our ordinary shares. The repurchase program does not have an
established expiration date and may be suspended or discontinued at any time.
Under the program, repurchased shares are constructively retired and returned
to
unissued status.
In
May
2006, our board of directors authorized an increase in the overall amount of
ordinary shares which may be repurchased under our share repurchase program
from
$2.0 billion to $4.0 billion.
The
summary of shares repurchased is as follows (in millions, except per share
data):
Total
consideration paid to repurchase the shares was recorded in shareholders’ equity
as a reduction in ordinary shares and additional paid-in capital. Such
consideration was funded with existing cash balances, borrowings under our
Revolving Credit Facility and our Term Credit Facility and proceeds from the
issuance of our Floating Rate Notes (see Note 7—Debt).
At
December 31, 2006, we repurchased a total of $3.0 billion of our ordinary shares
and we had authority to repurchase an additional $1.0 billion of our ordinary
shares under the program. See Note 26—Subsequent
Events
Note
14—Supplementary
Cash Flow Information
Non-cash
investing activities for the years ended December 31, 2006, 2005 and 2004
included $186 million, $31 million and $10 million, respectively, related to
accruals of capital expenditures. The accruals have been reflected in the
consolidated balance sheet as an increase in property and equipment, net and
accounts payable.
Cash
payments for interest were $125 million, $129 million and $201 million for
the
years ended December 31, 2006, 2005 and 2004, respectively. Cash payments for
income taxes, net, were $125 million, $107 million and $75 million for the
years
ended December 31, 2006, 2005 and 2004, respectively.
Note
15—Income
Taxes
We
are a
Cayman Islands company, and we are not subject to income tax in the Cayman
Islands. We operate through our various subsidiaries in a number of countries
throughout the world. Income taxes have been provided based upon the tax laws
and rates in the countries in which operations are conducted and income is
earned. There is no expected relationship between the provision for or benefit
from income taxes and income or loss before income taxes because the countries
in which we operate have taxation regimes that vary not only with respect to
the
nominal tax rate, but also in terms of the availability of deductions, credits
and other benefits. Variations also arise when income earned and taxed in a
particular country or countries fluctuates from year to year.
Deferred
tax assets and liabilities are recognized for the anticipated future tax effects
of temporary differences between the financial statement basis and the tax
basis
of our assets and liabilities at the applicable tax rates in effect. We have
not
provided for deferred taxes in circumstances where we do not expect the
operations in a jurisdiction to give rise to future tax consequences, due to
the
structure of operations and applicable law. Should our expectations change
regarding the expected future tax consequences, we may be required to record
additional deferred taxes that could have a material adverse effect on our
consolidated financial position, results of operations or cash
flows.
The
$4
million decrease in our net deferred tax liability is composed of the deferred
tax benefit of $23 million, reduced by a $9 million adjustment to
additional paid-in capital for the tax effect of prior year equity compensation
deductions, a $3 million adjustment to accumulated other comprehensive income
for the tax effect of the adoption of SFAS 158, and an $8 million
reclassification to current income tax liability for prior year prepaid tax
on an intracompany transaction.
We
have
not provided for deferred taxes on the unremitted earnings of certain
subsidiaries that we consider to be permanently reinvested. Should we make
a
distribution of the unremitted earnings of these subsidiaries, we may 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.
A
valuation allowance for deferred tax assets is recorded when it is more likely
than not that some or all of the benefit from the deferred tax asset will not
be
realized. We provide a valuation allowance to offset deferred tax assets for
net
operating losses incurred during the year in certain jurisdictions and for
other
deferred tax assets where, in the opinion of management, it is more likely
than
not that the financial statement benefit of these losses will not be realized.
We provide a valuation allowance for foreign tax credit carryforwards to reflect
the possible expiration of these benefits prior to their utilization. During
the
year ended December 31, 2006, the valuation allowance for non-current deferred
tax assets increased $11 million, which resulted primarily from the increase
of
foreign tax credits. In the year ended December 31, 2005, the valuation
allowance decreased $67 million, which resulted primarily from the utilization
of the underlying deferred assets to offset current year income, from
adjustments related to the settlement of certain audits and from adjustments
related to the restructuring of certain of our non-U.S.
operations.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Our
U.K.
net operating loss carryforwards do not expire. The tax effect of the U.K.
net
operating loss carryforwards was $56 million at December 31, 2006. Our U.S.
foreign tax credit carryforwards of $59 million, net of valuation allowances
of
$58 million, will expire between 2009 and 2016. Our U.S. alternative minimum
tax
credits of $1 million do not expire.
In
addition to our recognized tax attributes, we have an unrecognized U.S. capital
loss carryforward and an unrecognized U.S. net operating loss carryforward.
We
have not recognized a deferred tax asset for the capital loss carryforward
as it
is not probable that we will realize the benefit of this tax attribute.
Our operations do not normally generate capital gain income, which is the
only type of income that may be offset by capital losses. In the year
ended December 31, 2005, we recognized a benefit of $66 million to record the
utilization of the capital loss carryforward to offset capital gain income
resulting from certain restructuring transactions. Certain payments from
TODCO under the tax sharing agreement also serve to increase or decrease the
capital loss carryforward. Should an opportunity to utilize the remaining
capital loss arise, the total potential tax benefit at December 31, 2006 was
$841 million. We have not recognized a deferred tax asset for certain of
our U.S. net operating loss carryforwards as it is not probable that we will
realize the benefit of the underlying tax deduction. Should an opportunity
to utilize the unrecognized net operating loss arise, the total potential tax
benefit at December 31, 2006 was $8 million.
We
are
subject to changes in tax laws, treaties and regulations in and between the
countries in which we operate. A material change in these tax laws, treaties
or
regulations could result in a higher or lower effective tax rate on our
worldwide earnings.
Transocean
Inc., a Cayman Islands company, is not subject to income taxes in the Cayman
Islands. For the three years ended December 31, 2006, there was no Cayman
Islands income or profits tax, withholding tax, capital gains tax, capital
transfer tax, estate duty or inheritance tax payable by a Cayman Islands company
or its shareholders. We have obtained assurance from the Cayman Islands
government under the Tax Concessions Law (1995 Revision) that in the event
that
any legislation is enacted in the Cayman Islands imposing tax computed on
profits, income, distributions or any capital assets, gain or appreciation,
or
any tax in the nature of estate duty or inheritance tax, such tax shall not,
until June 1, 2019, be applicable to us or to any of our operations or to our
shares, debentures or other obligations.
Our
income tax returns are subject to review and examination in the various
jurisdictions in which we operate. We are currently contesting various tax
assessments. We accrue for income tax contingencies that we believe are probable
exposures.
During
2006, we settled disputes with tax authorities in several jurisdictions and
the
statute of limitations for income tax contingencies for certain issues expired.
As a result of the resolution of these matters, we recognized a current tax
benefit of $30 million.
Our
2004
and 2005 U.S. federal income tax returns are currently under examination by
the
U.S. Internal Revenue Service (“IRS”). We believe our returns are materially
correct as filed, and we intend to vigorously defend against any proposed
changes. While we cannot predict or provide assurance as to the final outcome,
we do not expect the ultimate settlement of any liability resulting from any
examination to have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
In
April
2006, we received notice from the Norwegian tax authorities regarding their
intent to propose adjustments to taxable income for the tax years 1999, 2001
and
2002. These proposed assessments could result in an increase in tax of
approximately $260 million, plus interest and the authorities further indicated
they intend to impose penalties, which could range from 15 to 60 percent of
the
assessments. The anticipated assessments relate to restructuring transactions
undertaken in 2001 and 2002. The Norwegian tax authorities initiated inquiries
in September 2004 related to the restructuring transactions and a separate
dividend payment made during 2001. In February 2005, we filed a response to
these inquiries. In March 2005, pursuant to court orders, the Norwegian tax
authorities took action to obtain additional information regarding these
transactions. We have continued to respond to information requests from the
Norwegian authorities and filed a formal protest to the proposed assessment
in
June 2006. We also believe the Norwegian authorities are contemplating a tax
assessment of approximately $104 million on the dividend, plus interest and
a
penalty, which could range from 15 to 60 percent of the assessment. Norwegian
civil tax and criminal authorities continue to investigate the restructuring
transactions and dividend. We plan to vigorously contest any assertions by
the
Norwegian authorities in connection with the restructuring transactions or
dividend. While we cannot predict or provide assurance as to the final outcome
of these proceedings, we do not expect the ultimate resolution of these matters
to have a material adverse effect on our consolidated financial position,
results of operations or cash flows.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
February 2007, we entered into a settlement agreement with the IRS regarding
the
2001 to 2003 audit. The IRS agreed to settle all issues for this period. This
settlement resulted in no cash tax payment.
During
the fourth quarter of 2005, we entered into a settlement agreement with the
IRS
with respect to our 1999 and 2000 U.S. federal income tax returns, which
resulted in a payment of $36 million including interest. The IRS agreed to
settle all issues for this period. This settlement did not result in a material
effect on our consolidated financial position, results of operations or cash
flows.
In
December 2005, we restructured certain of our non-U.S. operations. As a result
of the restructuring, we incurred a deferred tax charge in the amount of $33
million.
As
a
result of changes in our estimates of certain pre-acquisition tax contingencies
and liabilities arising prior to our merger with Sedco Forex Holdings Limited
(“Sedco Forex”) effective December 31, 1999, we recorded a decrease of $5
million in goodwill and an income tax receivable of $5 million in December
2006.
Our
wholly owned subsidiary, Transocean Holdings Inc. (“Transocean Holdings”),
entered into a tax sharing agreement with TODCO in connection with the TODCO
IPO. The tax sharing agreement governs Transocean Holdings’ and TODCO’s
respective rights, responsibilities and obligations with respect to taxes and
tax benefits, the filing of tax returns, the control of audits and other tax
matters. Under this agreement, most U.S. federal, state, local and foreign
income taxes and income tax benefits (including income taxes and income tax
benefits attributable to the TODCO business) that accrued on or before the
closing of the TODCO IPO will be for the account of Transocean Holdings.
Accordingly, Transocean Holdings generally is liable for any income taxes that
accrued on or before the closing of the TODCO IPO, but TODCO generally must
pay
Transocean Holdings for the amount of any income tax benefits created on or
before the closing of the TODCO IPO (“pre-closing tax benefits”) that it uses or
absorbs on a return with respect to a period after the closing of the TODCO
IPO.
Under this agreement, we are entitled to receive from TODCO payment for most
of
the tax benefits TODCO generated prior to the TODCO IPO that they utilize
subsequent to the TODCO IPO. While TODCO was included in our consolidated
statements of operations and balance sheet as a consolidated subsidiary until
the fourth quarter of 2004, we followed the provisions of SFAS No. 109,
Accounting
for Income Taxes
(“SFAS
109”), which allowed us to evaluate the recoverability of the deferred tax
assets associated with the tax sharing agreement considering TODCO’s deferred
tax liabilities.
Because
we no longer own shares of TODCO, we no longer include TODCO as a consolidated
subsidiary in our financial statements. As a result, we recorded a non-cash
charge of $167 million ($0.51 per diluted share), which had no tax effect,
in
the fourth quarter of 2004 related to contingent amounts due from TODCO under
the tax sharing agreement. The non-cash charge was necessary as the future
payments under the tax sharing agreement are dependent on TODCO generating
future taxable income, which cannot be assumed until such income is actually
generated. Future payments we receive from TODCO’s utilization of the pre-TODCO
IPO deferred tax assets will be recognized in other income as those amounts
are
realized, which is generally based on when TODCO files its annual tax returns.
In 2006, we reached a settlement agreement with TODCO regarding the dispute
in
which we were seeking payment of these amounts, and TODCO was seeking to void
the entire tax sharing agreement. See Note 17—Commitments and
Contingencies.
In
2006
and 2005, respectively, we recognized $51 million ($0.16 per diluted share)
and
$11 million ($0.03 per diluted share) of other income in our consolidated
statement of operations related to TODCO’s utilization of tax benefits and stock
option deductions. Through December 31, 2006, we received $66 million in
estimated payments pertaining to TODCO’s 2006 federal and state income tax
returns that is deferred in other current liabilities in our consolidated
balance sheet. We will recognize these estimated payments as other income when
TODCO finalizes and files its 2006 federal and state income tax
returns.As
of
December, 31, 2006, tax benefits in excess of $200 million remain to be utilized
by TODCO under the tax sharing agreement, based on estimated usage to date.
The
ultimate amount and timing of the utilization is contingent on a variety of
factors including potential revisions to the tax benefits upon examination
by
the IRS and the amount of taxable income that TODCO realizes in future
years.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As
a
result of the deconsolidation of TODCO from our other U.S. subsidiaries for
U.S.
federal income tax purposes in conjunction with the TODCO IPO (see Note 4—TODCO
Stock Sales), we established an initial valuation allowance in the first quarter
of 2004 of $31 million ($0.09 per diluted share) against the estimated deferred
tax assets of TODCO in excess of its deferred tax liabilities and other deferred
tax assets not expected to be realized, taking into account prudent and feasible
tax planning strategies as required by SFAS 109. We adjusted the initial
valuation allowance during 2004 to reflect changes in our estimate of the
ultimate amount of TODCO’s deferred tax assets and other deferred tax assets not
expected to be realized. An allocation of tax benefits between TODCO and our
other U.S. subsidiaries occurred in the third quarter of 2005 upon the filing
of
our 2004 U.S. consolidated federal income tax return. As a result of this
allocation, we recorded additional income tax expense of approximately $8
million ($0.02 per diluted share) in 2005 to adjust the previously estimated
allocation. This allocation is subject to potential revision upon subsequent
IRS
audit of our tax return and such revision, should it occur, could impact our
effective tax rate for future years as well as the ultimate amount of payments
by TODCO related to the tax sharing agreement.
Note
16—Off-Balance
Sheet Arrangement
We
leased
the semisubmersible M.
G.
Hulme, Jr.
from
Deep Sea Investors, L.L.C. (“Deep Sea Investors”), a special purpose entity
formed by several leasing companies to acquire the rig from one of our
subsidiaries in November 1995 in a sale/leaseback transaction. We accounted
for
the lease of this semisubmersible drilling rig as an operating lease. We
recorded $5 million and $13 million of such rent expense for the years ended
December 31, 2005 and 2004, respectively. In May 2005, we purchased the rig
for
$43 million. The rig was reflected as property and equipment in the consolidated
balance sheet at December 31, 2005.
Effective
December 31, 2003, we adopted and applied the provisions of FASB Interpretation
No. 46, Consolidation
of Variable Interest Entities (“FIN
46”), as revised December 31, 2003, for all variable interest entities. FIN 46
requires the consolidation of variable interest entities in which an enterprise
absorbs a majority of the entity’s expected losses, receives a majority of the
entity’s expected residual returns, or both, as a result of ownership,
contractual or other financial interests in the entity. Because the
sale/leaseback agreement was with an entity in which we had no direct
investment, we were not entitled to receive the financial information of the
leasing entity and the equity holders of the leasing company would not release
the financial statements or other financial information to us in order for
us to
make the determination of whether the entity was a variable interest entity.
In
addition, without the financial statements or other financial information,
we
were unable to determine if we were the primary beneficiary of the entity and,
if so, what we would have consolidated. We had no exposure to loss as a result
of the sale/leaseback agreement. As a result of the purchase of the M.
G.
Hulme, Jr.,
we are
no longer associated with Deep Seas Investors and, as such, are no longer
required to review for FIN 46 applicability.
Note
17—Commitments
and Contingencies
Operating
Leases¾We
have
operating lease commitments expiring at various dates, principally for real
estate, office space and office equipment. In addition to rental payments,
some
leases provide that we pay a pro rata share of operating costs applicable to
the
leased property. As of December 31, 2006, future minimum rental payments related
to noncancellable operating leases are as follows (in millions):
Rental
expense for all operating leases, including leases with terms of less than
one
year, was approximately $32 million, $30 million and $40 million for the years
ended December 31, 2006, 2005 and 2004, respectively.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Purchase
Obligations—At
December 31, 2006, our purchase obligations as defined by SFAS No.47,
Disclosure
of Long-Term Obligations (as amended),
related
to our Sedco
706
upgrade
shipyard project and three enhanced Enterprise-class newbuilds are as follows
(in millions):
Legal
Proceedings—Several
of our subsidiaries have been named, along with numerous unaffiliated
defendants, in several complaints that have been filed in the Circuit Courts
of
the State of Mississippi involving over 700 persons that allege personal injury
arising out of asbestos exposure in the course of their employment by some
of
these defendants between 1965 and 1986. The complaints also name as defendants
certain of TODCO's subsidiaries to whom we may owe indemnity. Further, the
complaints name other unaffiliated defendant companies, including companies
that
allegedly manufactured drilling related products containing asbestos. The
complaints allege that the defendant drilling contractors used those
asbestos-containing products in offshore drilling operations, land based
drilling operations and in drilling structures, drilling rigs, vessels and
other
equipment and assert claims based on, among other things, negligence and strict
liability, and claims authorized under the Jones Act. The plaintiffs generally
seek awards of unspecified compensatory and punitive damages. We have not yet
been able to conduct extensive discovery nor determine the number of plaintiffs
that were employed by our subsidiaries or otherwise have any connection with
our
drilling operations. We intend to defend ourselves vigorously and, based on
the
limited information available to us at this time, we do not expect the
liability, if any, resulting from these matters to have a material adverse
effect on our consolidated financial position, results of operations or cash
flows.
In
1990
and 1991, two of our subsidiaries were served with various assessments
collectively valued at approximately $10 million from the municipality of Rio
de
Janeiro, Brazil to collect a municipal tax on services. We believe that neither
subsidiary is liable for the taxes and have contested the assessments in the
Brazilian administrative and court systems. We have received several adverse
rulings by various courts with respect to a June 1991 assessment, which is
valued at approximately $9 million. We are continuing to challenge the
assessment and filed a writ of mandamus to stay execution of a related tax
foreclosure proceeding. The government is currently attempting to enforce the
judgment on this assessment and the amount claimed is approximately $24 million,
which exceeds the amount we believe is at issue. We received a favorable ruling
in connection with a disputed August 1990 assessment, and the government has
lost what is expected to be its final appeal with respect to that ruling. We
also are awaiting a ruling from the Taxpayer's Council in connection with an
October 1990 assessment. If our defenses are ultimately unsuccessful, we believe
that the Brazilian government-controlled oil company, Petrobras, has a
contractual obligation to reimburse us for municipal tax payments. We do not
expect the liability, if any, resulting from these assessments to have a
material adverse effect on our consolidated financial position, results of
operations or cash flows.
The
Indian Customs Department, Mumbai alleged in July 1999 that the initial entry
into India in 1988 and other subsequent movements of the Trident
II
jackup
rig operated by the subsidiary constituted imports and exports for which proper
customs procedures were not followed and sought payment of customs duties of
approximately $31 million based on an alleged 1998 rig value of $49 million,
plus interest and penalties, and confiscation of the rig. In January 2000,
the
Customs Department found that we had imported the rig improperly and
intentionally concealed the import from the authorities, and directed us to
pay
certain other fees and penalties, in addition to the amount of customs duties
owed. We appealed the Customs Department ruling and an appellate tribunal
granted our request that the confiscation be stayed pending the appeal. The
appellate tribunal also found that the rig was originally imported without
proper documentation or payment of duties and sustained our valuation of the
rig
at the time of import as $13 million and ruled that subsequent movements of
the
rig were not liable to import documentation or duties, thus limiting our
exposure as to custom duties to approximately $6 million. The Supreme Court
of
India has affirmed the appellate ruling but the Customs Department has not
agreed with our interpretation of that order. We are contesting their
interpretation. We and our customer agreed to pursue and obtained the issuance
of the required importation documentation from the Ministry of Petroleum that,
if accepted by the Customs Department, would reduce the duty to nil. The Customs
Department did not accept the documentation or agree to refund the duties
already paid. We are pursuing our remedies against the Customs Department and
our customer. We do not expect the liability, if any, resulting from this matter
to have a material adverse effect on our consolidated financial position,
results of operations or cash flows.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
One
of
our subsidiaries is involved in an action with respect to customs penalties
relating to the Sedco
710
semisubmersible drilling rig. Prior to our merger with Sedco Forex, this
drilling rig, which was working for Petrobras in Brazil at the time, had been
admitted into the country on a temporary basis under authority granted to a
Schlumberger entity. Prior to the Sedco Forex merger, the drilling contract
was
moved to an entity that would become one of our subsidiaries. In early 2000,
the
drilling contract was extended for another year. On January 10, 2000, the
temporary import permit granted to the Schlumberger entity expired, and renewal
filings were not made until later that January. In April 2000, the Brazilian
customs authorities cancelled the import permit. The Schlumberger entity filed
an action in the Brazilian federal court of Campos for the purpose of extending
the temporary admission. Other proceedings were also initiated in order to
secure the transfer of the temporary admission to our subsidiary. Ultimately,
the court permitted the transfer to our entity but has not ruled that the
temporary admission could be extended without the payment of a financial
penalty. During the first quarter of 2004, the customs office renewed its
efforts to collect a penalty and issued a second assessment for this penalty
but
has now done so against our subsidiary. The assessment is for approximately
$71
million. We believe that the amount of the assessment, even if it were
appropriate, should only be approximately $7 million and should in any event
be
assessed against the Schlumberger entity. We and Schlumberger are contesting
our
respective assessments. We have put Schlumberger on notice that we consider
any
assessment to be the responsibility of Schlumberger. We do not expect the
liability, if any, resulting from this matter to have a material adverse effect
on our consolidated financial position, results of operations or cash
flows.
In
November 2006, we reached a negotiated settlement with TODCO, our former
subsidiary, arising out of the tax sharing agreement that we entered into with
TODCO in connection with TODCO’s initial public offering in 2004. As a result of
the settlement, we entered into an amended and restated tax sharing agreement
with TODCO. Under the terms of the amended and restated agreement, TODCO will
pay us for 55 percent of the value of the tax deductions arising from the
exercise of options to purchase our ordinary shares by current and former
employees and directors of TODCO. This payment rate applies retroactively to
amounts previously accrued by TODCO and to future payments. Under the terms
of
the amended and restated agreement, TODCO will also receive a $3 million
federal tax benefit for use of certain state and foreign tax assets. The amended
and restated agreement also provides that the change of control provision
contained in the agreement no longer applies to option deductions. However,
if
TODCO uses the option deductions after a change of control, it would be required
to pay us for 55 percent of the value of those deductions. See Note 15—Income
Taxes.
In
the
third quarter of 2006, we received tax assessments of approximately $100 million
from the state tax authorities of Rio de Janeiro in Brazil against one of our
Brazilian subsidiaries for customs taxes on equipment imported into the state
in
connection with our operations. The assessments resulted from a preliminary
finding by these authorities that our subsidiary’s record keeping practices were
deficient. We continue to review documents related to the assessments, and
while
our review is not complete, we currently believe that the substantial majority
of these assessments are without merit. We filed an initial response with the
Rio de Janeiro tax authorities on September 9, 2006 refuting these
additional tax assessments. While we cannot predict or provide assurance as
to
the final outcome of these proceedings, we do not expect it to have a material
adverse effect on our consolidated financial position, results of operations
or
cash flows.
We
are
involved in a number of other lawsuits, including a labor dispute involving
Hull
Blyth workers in Angola previously reported that is not material to us, all
of
which have arisen in the ordinary course of our business. We do not expect
the
liability, if any, resulting from these matters to have a material adverse
effect on our consolidated financial position, results of operations or cash
flows. We are also involved in various tax matters (see Note 15—Income
Taxes).
Retained
Risk—We
retain the risk, through self-insurance, for the deductible portion of our
insurance coverage as well as losses due to hurricanes in the U.S. Gulf of
Mexico in excess of $250 million in aggregate annually, except in the case
of a
total loss of a rig where the annual limit is approximately $300 million in
aggregate. We also retain any risk of losses in excess of the insured value
of
our drilling rig fleet (currently $13.0 billion in aggregate), losses in excess
of the $930 million limit on personal injury and third-party liability claims
and losses related to loss of revenue. We
currently maintain a $10 million per occurrence insurance deductible on hull
and
machinery, a $10 million per occurrence deductible on personal injury liability
and a $5 million per occurrence deductible on third party property damage.
In
addition to the per occurrence deductibles described above, we also have
aggregate deductibles that are applied to any occurrence in excess of the per
occurrence deductible until the aggregate deductible is exhausted. Such
aggregate deductibles are $20 million in the case of our hull and machinery
coverage and $25 million in the case of our personal injury liability and third
party property damage coverage. Additionally, for our personal injury and
third-party damage liabilities, we have retained $20 million of the risk that
exceeds our deductible amount. In the opinion of management, adequate accruals
have been made based on known and estimated losses related to such exposures.
Letters
of Credit and Surety Bonds—We
had
letters of credit outstanding totaling $405 million and $314 million at December31, 2006 and 2005, respectively. These letters of credit guarantee various
contract bidding and performance activities under various uncommitted lines
provided by several banks.
As
is
customary in the contract drilling business, we also have various surety bonds
in place that secure customs obligations relating to the importation of our
rigs
and certain performance and other obligations. Surety bonds outstanding totaled
$6 million and $8 million at December 31, 2006 and 2005, respectively.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
18—Share-Based
Compensation Plans
We
have a
long-term incentive plan for executives, key employees and outside directors
(the “Incentive Plan”). Under the Incentive Plan, awards can be granted in the
form of stock options, restricted shares, deferred units, stock appreciation
rights (“SARs”) and cash performance awards. Such awards include traditional
time-vesting awards (“time-based vesting awards”) and awards that are earned
based on the achievement of certain performance criteria (“performance-based
awards”). Our executive compensation committee of our board of directors
determines the terms and conditions of the awards under the Incentive Plan.
Options issued to date under the Incentive Plan have a 10-year term. Time-based
vesting awards typically vest in three equal annual installments beginning
on
the first anniversary date of the grant. Performance-based awards issued to
date
under the Incentive Plan have a two-year performance year with the number of
options, shares or deferred units earned being determined following the
completion of the performance year (the “determination date”) at which time
one-third of the options, shares or deferred units vest. Additional vesting
occurs on January 1 of the two subsequent years following the determination
date. As of December 31, 2006, we were authorized under the Incentive Plan
to
grant awards covered by up to (i) 22.9 million ordinary shares, which includes
up to 6.0 million restricted shares, to employees and (ii) 0.6 million
ordinary shares to outside directors. We issue new shares when stock options
are
exercised and restricted shares and deferred units vest.
Prior
to
adoption of SFAS 123(R), we used the Black-Scholes-Merton model to value stock
options granted or modified under SFAS 123 and have elected to continue using
this model to value stock options granted or modified under SFAS 123(R). We
determine the fair value of options granted or modified based on the expected
term, risk-free interest rate, dividend yield and expected volatility. The
expected term is based on historical information of past employee behavior
regarding exercises and forfeiture of options. The risk-free interest rate
assumption is based upon the published U.S. Treasury yield curve in effect
at
the time of grant for instruments with a similar life. The dividend yield
assumption is based on our history and expectation of dividend payouts.
Under
SFAS 123, we based expected volatility solely on historical data. Upon the
adoption of SFAS 123(R), we began using a blended volatility for the volatility
assumption. We changed the calculation of our volatility to better reflect
our
expectation of how our share price will react to the future cyclicality of
our
industry. The blended volatility is calculated using two components. The first
component is derived from volatility computed from historical data for a year
of
time approximately equal to the expected term of the stock option, starting
from
the date of grant. The second component is the implied volatility derived from
our “at-the-money” long dated call options with a term of six months or longer.
The two components are equally weighted to create a blended volatility. This
change in estimate did not have a material effect on our consolidated financial
statements. The fair value for restricted ordinary shares and deferred units
is
based on the market price of our ordinary shares on the date of
grant.
Share-based
compensation expense is recorded on the same financial statement line item
as
cash compensation paid to the same employees.
Due
to
termination of employment for convenience of the company, we had 11 and seven
individuals whose share-based compensation awards were modified during the
years
ended December 31, 2005 and 2004, respectively. As a result of these
modifications, we recorded additional share-based compensation expense of $2
million in both years ended December 31, 2005 and 2004. There were no
significant modifications during the year ended December 31, 2006.
As
of
December 31, 2006, total unrecognized compensation costs related to all unvested
share-based awards totaled $36 million, which is expected to be recognized
over
a weighted average period of 2.3 years.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Time-Based
Vesting Awards
Stock
Options—The
following table summarizes vested and unvested time-based vesting stock option
(“time-based options”) activity under the Incentive Plan during the year ended
December 31, 2006:
Time-based
options expected to vest in the table above include options that have not time
vested, where the amount is net of a discount for our estimated termination
related forfeitures. There were 53,450 time-based options granted during the
year ended December 31, 2005, with a weighted-average grant-date fair value
of
$17.83 per share. No time-based options were granted during the year ended
December 31, 2004.
The
total
pretax intrinsic value of time-based options exercised during the year ended
December 31, 2006 was $99 million. There were 7,695,838 and 1,153,857 time-based
options exercised during the years ended December 31, 2005 and 2004,
respectively. The total pretax intrinsic value of time-based options exercised
was $190 million and $17 million during the years ended December 31, 2005 and
2004, respectively.
The
following table summarizes unvested time-based option activity under the
Incentive Plan during the year ended December 31, 2006:
The
total
grant-date fair value of time-based options vested during the year ended
December 31, 2006 was $1 million. There were 595,412 and 1,407,602 time-based
options that vested during the years ended December 31, 2005 and 2004,
respectively. The total grant-date fair value of time-based options that vested
was $7 million and $20 million during the years ended December 31, 2005 and
2004, respectively.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Restricted
Ordinary Shares—The
following table summarizes unvested share activity for time-based vesting
restricted ordinary shares (“time-based shares”) granted under the Incentive
Plan during the year ended December 31, 2006:
The
total
grant-date fair value of time-based shares that vested during the year ended
December 31, 2006 was $1 million. There were 35,230 and 8,281 time-based shares
granted during the years ended December 31, 2005 and 2004, respectively. The
weighted-average grant-date fair value of time-based shares granted was $49.01
and $28.12 per share for the years ended December 31, 2005 and 2004,
respectively. There were 14,359 and 21,519 time-based shares that vested during
the years ended December 31, 2005 and 2004, respectively. The total grant-date
fair value of time-based shares that vested was less than $1 million for both
years ended December 31, 2005 and 2004.
Deferred
Units—A
deferred unit is a unit that is equal to one ordinary share but has no voting
rights until the underlying ordinary shares are issued. The following table
summarizes unvested activity for time-based vesting deferred units (“time-based
units”) granted under the Incentive Plan during the year ended December 31,2006:
The
total
grant-date fair value of the time-based units vested during the year ended
December 31, 2006 was $1 million. There were 18,600 and 20,538 time-based units
granted during the years ended December 31, 2005 and 2004, respectively. The
weighted-average grant-date fair value was $45.02 and $27.17 per share for
the
years ended December 31, 2005 and 2004, respectively. There were 6,080
time-based units vested with a total grant-date fair value of less than $1
million during the year ended December 31, 2005. No time-based units vested
during the year ended December 31, 2004.
SARs—The
following table summarizes time-based vesting SARs activity under the Incentive
Plan during the year ended December 31, 2006:
No
SARs
were granted during the years ended December 31, 2006, 2005 and 2004. The total
pretax intrinsic value of SARs exercised was $1 million during the year ended
December 31, 2006. There were 80,782 and 666 SARs exercised during the years
ended December 31, 2005 and 2004, respectively. The total pretax intrinsic
value
of SARs exercised was $1 million and less than $1 million for the years ended
December 31, 2005 and 2004, respectively.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As
of
December 31, 2006, all SARs granted under the Incentive Plan are fully vested.
There were 6,053 and 13,494 SARs vested during the years ended December 31,2005
and 2004, respectively. The total grant-date fair value of SARs vested was
less
than $1 million for both years ended December 31, 2005 and 2004.
Performance-Based
Awards
Stock
Options—We
granted performance-based stock options (“performance-based options”) that can
be earned depending on the achievement of certain performance targets. The
number of options earned is quantified upon completion of the performance year
at the determination date. The following table summarizes vested and unvested
performance-based option activity under the Incentive Plan during the year
ended
December 31, 2006:
The
number of performance-based options expected to vest in the table above includes
both (i) options that have reached their determination date but have not time
vested, in which case the amount is net of a discount for our estimated
termination-related forfeitures, and (ii) option grants that have not reached
their determination date, in which case the amount is net of a discount for
expected forfeitures based upon our current estimate of the number of options
expected to be earned using the performance criteria at the determination date.
There
were 324,714 and 544,273 performance-based options granted during the years
ended December 31, 2005 and 2004, respectively. The weighted-average grant-date
fair value of performance-based options granted was $20.79 and $11.26 per share
during the years ended December 31, 2005 and 2004, respectively.
The
total
pretax intrinsic value of performance-based options exercised during the year
ended December 31, 2006 was $10 million. There were 91,423 performance-based
options exercised, with a total pretax intrinsic value of $3 million, during
the
year ended December 31, 2005. No performance-based options were exercised during
the year ended December 31, 2004.
The
following table summarizes unvested performance-based option activity under
the
Incentive Plan during the year ended December 31, 2006:
Unvested
options include options that have not reached their determination date and
thus
the number of such options could be reduced due to the performance criteria
applied at the determination date. Options forfeited or cancelled include the
adjustment of options at the determination date due to the application of the
performance criteria.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
total
grant-date fair value of performance-based options vested during the year ended
December 31, 2006 was $3 million. There were 166,013 performance-based options
vested with a total grant-date fair value of $1 million during the year ended
December 31, 2005. No performance-based options vested during the year ended
December 31, 2004.
Restricted
Ordinary Shares—We
grant
performance-based restricted ordinary shares (“performance-based shares”) that
can be earned depending on the achievement of certain performance targets.
The
number of shares earned is quantified upon completion of the performance year
at
the determination date. The following table summarizes unvested share activity
for performance-based shares granted under the Incentive Plan during the year
ended December 31, 2006:
Unvested
shares include shares that have not reached their determination date and thus
the number of such shares could be reduced due to the performance criteria
applied at the determination date. Shares forfeited or cancelled include the
adjustment of shares at the determination date due to the application of the
performance criteria.
The
total
grant-date fair value of performance-based shares that vested during the year
ended December 31, 2006 was $6 million. There were 377,772 and 645,604
performance-based shares granted during the years ended December 31, 2005 and
2004, respectively. The weighted-average grant-date fair value was $57.90 and
$28.12 per share during the years ended December 31, 2005 and 2004,
respectively. There
were 272,913 performance-based shares that vested with a total grant-date fair
value of $6 million during the year ended December 31, 2005. No
performance-based shares vested during the year ended December 31, 2004.
Deferred
Units—We
grant
performance-based deferred units (“performance-based units”) that can be earned
depending on the achievement of certain performance targets. The number of
units
earned is quantified upon completion of the performance year at the
determination date. The following table summarizes unvested unit activity for
performance-based units granted under the Incentive Plan during the year ended
December 31, 2006:
Unvested
units include units that have not reached their determination date and thus
the
number of such units could be reduced due to the performance criteria applied
at
the determination date. Units forfeited or cancelled include the adjustment
of
units at the determination date due to the application of the performance
criteria.
The
total
grant-date fair value of performance-based units that vested during the year
ended December 31, 2006 was $2 million. There were 10,189 and 54,747
performance-based units granted during the years ended December 31, 2005 and
2004, respectively. The weighted-average grant-date fair value of
performance-based units granted was $57.90 and $28.12 per share during the
years
ended December 31, 2005 and 2004, respectively. There were 15,219
performance-based units that vested with a total grant-date fair value of less
than $1 million during the year ended December 31, 2005. No performance-based
units vested during the year ended December 31, 2004.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
ESPP—We
provide the ESPP for certain full-time employees. Under the terms of the ESPP,
employees can choose each year to have between two and 20 percent of their
annual base earnings withheld to purchase up to $21,250 of our ordinary shares.
The purchase price of the stock is 85 percent of the lower of the
beginning-of-year or end-of-year market price of our ordinary shares. At
December 31, 2006, 962,924 ordinary shares were available for issuance pursuant
to the ESPP after taking into account the shares to be issued for the 2006
plan
year.
Note
19—Retirement
Plans, Other Postemployment Benefits and Other Benefit Plans
On
December 31, 2006, we adopted the recognition and disclosure provisions of
SFAS
No.158, Employer’s
Accounting for Defined Benefit Pension and other Postretirement
Plans,
an
amendment of FASB Statements No. 87, 88 and 123(R)
(“SFAS
158”), which require the recognition of the funded status of the Defined Benefit
and Postretirement Benefits Other Than Pensions (“OPEB”) plans on the December31, 2006 balance sheet with a corresponding adjustment to accumulated other
comprehensive income. The adjustment to accumulated other comprehensive income
at adoption represents the net unrecognized actuarial losses, unrecognized
prior
service costs, and unrecognized transition obligation remaining from the initial
application of SFAS No. 87, Employers'
Accounting for Pension (“SFAS
87”), all of which were previously netted against the plans’ funded status on
the balance sheet. These amounts will be subsequently recognized as net periodic
pension cost pursuant to our historical accounting policy for amortizing such
amounts. Further, actuarial gains and losses that arise in subsequent periods
and are not recognized as net periodic pension cost in the same periods will
be
recognized as a component of other comprehensive income. Those amounts will
be
subsequently recognized as a component of net periodic pension cost on the
same
basis as the amounts recognized in accumulated other comprehensive income.
The
incremental effects of adopting SFAS 158 on the consolidated balance sheet
at
December 31, 2006 are presented in the following table. The adoption of SFAS
158
did not affect the consolidated statement of operations for the year ended
December 31, 2006, or any prior period presented, and it will not have a
material affect on our operating results in future periods. The incremental
effects of adopting the provisions of SFAS 158 on the consolidated balance
sheet
are presented as follows:
Defined
Benefit Pension Plans—We
maintain a qualified defined benefit pension plan (the “Retirement Plan”)
covering substantially all U.S. employees and an unfunded plan (the
“Supplemental Benefit Plan”) to provide certain eligible employees with benefits
in excess of those allowed under the Retirement Plan. In conjunction with the
R&B Falcon merger, we acquired three defined benefit pension plans, two
funded and one unfunded (the “Frozen Plans”), that were frozen prior to the
merger for which benefits no longer accrue but the pension obligations have
not
been fully paid out. We refer to the Retirement Plan, the Supplemental Benefit
Plan and the Frozen Plans collectively as the “U.S. Plans”.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
addition, we provide several defined benefit plans, primarily group pension
schemes with life insurance companies covering our Norway operations and two
unfunded plans covering certain of our employees and former employees (the
“Norway Plans”). Our contributions to the Norway Plans are determined primarily
by the respective life insurance companies based on the terms of the plan.
For
the insurance-based plans, annual premium payments are considered to represent
a
reasonable approximation of the service costs of benefits earned during the
period. We also have unfunded defined benefit plans (the “Other Non-U.S. Plans”)
that provide retirement and severance benefits for certain of our Indonesian,
Nigerian and Egyptian employees. The defined benefit pension benefits we provide
are comprised of the U.S. Plans, the Norway Plans and Other Non-U.S. Plans
(collectively, the “Transocean Plans”). For all plans, we have historically and
continue to use a January 1 measurement date for net periodic benefit cost
and a
December 31 measurement date for benefit obligations.
The
change in projected benefit obligation, change in plan assets, funded status
and
the amounts recognized in the consolidated balance sheets are shown in the
table
below (in millions):
Amounts
recognized in the consolidated balance sheets consist
of:
Pension
asset, non-current
$
5
$
-
Prepaid
benefit cost, non-current
-
3
Intangible
asset
-
1
Accrued
pension liability, current
1
-
Accrued
pension liability, non-current
82
65
Accumulated
other comprehensive income (c)
(42
)
(36
)
__________
(a)
Change
in beginning balance is due to the addition of the Indonesia Plan’s
January 1, 2006 beginning balance of $2 million.
(b)
Disclosure
is not applicable upon adoption of SFAS 158.
(c)
Amounts
are before income tax effect of $9 million and $13 million for
December31, 2006 and 2005, respectively.
The
accumulated benefit obligation for all defined benefit pension plans was $290
million and $279 million at December 31, 2006 and 2005,
respectively.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
aggregate projected benefit obligation and fair value of plan assets for plans
with a projected benefit obligation in excess of plan assets are as follows
(in
millions):
The
aggregate accumulated benefit obligation and fair value of plan assets for
plans
with an accumulated benefit obligation in excess of plan assets are as follows
(in millions):
Increase
(decrease) in minimum pension liability included in other comprehensive
income
$
(25
)
$
(6
)
$
6
____________
(a)
Amounts
are before income tax effect.
No
plan
assets are expected to be returned to us during the year ending December 31,2007.
There
were no amounts recognized in other comprehensive income as components of net
periodic benefit cost in the years ended December 31, 2006, 2005 and
2004.
The
following table shows the amounts in accumulated other comprehensive income
that
have not been recognized as components of net periodic benefit costs (in
millions):
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS -
Continued
The
following table shows the amounts in accumulated other comprehensive income
expected to be recognized as components of net periodic benefit cost during
the
next fiscal year (in millions):
Total
amount in accumulated other comprehensive income expected to be recognized
next year
$
4
Pension
obligations are actuarially determined and are affected by assumptions including
expected return on plan assets, discount rates, compensation increases and
employee turnover rates. We evaluate our assumptions periodically and make
adjustments to these assumptions and the recorded liabilities as
necessary.
Two
of
the most critical assumptions used in calculating our pension expense and
liabilities are the expected long-term rate of return on plan assets and the
assumed discount rate. We evaluate assumptions regarding the estimated long-term
rate of return on plan assets based on historical experience and future
expectations on investment returns, which are calculated by a third party
investment advisor utilizing the asset allocation classes held by the plan’s
portfolios. Beginning on December 31, 2005, we utilized a yield curve approach
based on Aa corporate bonds and the expected timing of future benefit payments
as a basis for determining the discount rate for our U.S. Plans. Prior to
December 31, 2005, we utilized the Moody’s Aa long-term corporate bond yield as
a basis for determining the discount rate for our U.S. Plans. Changes in these
and other assumptions used in the actuarial computations could impact our
projected benefit obligations, pension liabilities, pension expense and other
comprehensive income. We base our determination of pension expense on a
market-related valuation of assets that reduces year-to-year volatility. This
market-related valuation recognizes investment gains or losses over a five-year
period from the year in which they occur. Investment gains or losses for this
purpose are the difference between the expected return calculated using the
market-related value of assets and the actual return based on the market-related
value of assets.
The
following are the weighted-average assumptions used to determine benefit
obligations:
We
have
determined the asset allocation of the plans that is best able to produce
maximum long-term gains without taking on undue risk. After modeling many
different asset allocation scenarios, we have determined that an asset
allocation mix of approximately 60 percent equity securities, 30 percent debt
securities and 10 percent other investments is most appropriate. Other
investments are generally a diversified mix of funds that specialize in various
equity and debt strategies that are expected to provide positive returns each
year relative to U.S. Treasury Bills. These strategies may include, among
others, arbitrage, short-selling, and merger and acquisition investment
opportunities. We review asset allocations and results quarterly to ensure
that
managers are meeting specified objectives and policies as written and agreed
to
by us and each manager. These objectives and policies are reviewed each year.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
plan’s investment managers have discretion in the securities in which they may
invest within their asset category. Given this discretion, the managers may,
from time-to-time, invest in our stock or debt. This could include taking either
long or short positions in such securities. As these managers are required
to
maintain well diversified portfolios, the actual investment in our ordinary
shares or debt would be immaterial relative to asset categories and the overall
plan.
Our
pension plan weighted-average asset allocations for funded Transocean Plans
by
asset category are as follows:
We
contributed $15 million to our defined benefit pension plans in 2006, which
were
funded from our cash flows from operations. During 2006, contributions of $5
million were made to the funded U.S. Plans, $9 million to the funded Norway
Plans and $1 million to the Other Non-U.S. Plans.
We
expect
to contribute a total of $17 million to the Transocean Plans in 2007. These
contributions are comprised of an estimated $8 million to meet the minimum
funding requirements for the funded U.S. Plans, $1 million to fund expected
benefit payments for the unfunded U.S. Plans and the Other Non-U.S. Plans and
an
estimated $8 million for the funded Norway Plans.
The
following pension benefits payments are expected to be paid by the Transocean
Plans (in millions):
Postretirement
Benefits Other Than Pensions (“OPEB”)—We
haveseveral
unfunded contributory and noncontributory OPEB plans covering substantially
all
of our U.S. employees. Funding of benefit payments for plan participants will
be
made as costs are incurred. The postretirement health care plans include a
limit
on our share of costs for recent and future retirees. For all plans, we have
historically and continue to use a January 1 measurement date for net periodic
benefit cost and a December 31 measurement date for benefit
obligations.
We
amended our postretirement medical plans effective January 1, 2004. The
amendments placed limits on our medical benefits payments to retirees. In
addition, the amendments harmonized the benefits provided under each of our
postretirement medical plans. These changes to the plans resulted in a reduction
of $23 million in plan benefit obligations.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
change in benefit obligation, change in plan assets, funded status and amounts
recognized in the consolidated balance sheets are shown in the table below
(in
millions):
There
were no amounts recognized in other comprehensive income as components of net
periodic benefit cost in the years ended December 31, 2006, 2005 and
2004.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
following table shows the amounts in accumulated other comprehensive income
that
have not been recognized as components of net periodic benefit costs (in
millions):
The
following table shows the amounts in accumulated other comprehensive income
expected to be recognized as components of net periodic benefit cost during
the
next fiscal year (in millions):
Total
amount in accumulated other comprehensive income expected to be recognized
next year
$
(1
)
Our
OPEB
obligations and the related benefit costs are accounted for in accordance with
SFAS No. 106, Employers’
Accounting for Postretirement Benefits Other than Pensions.
Postretirement costs and obligations are actuarially determined and are affected
by assumptions including expected discount rates, employee turnover rates and
health care cost trend rates. We evaluate our assumptions periodically and
make
adjustments to these assumptions and the recorded liabilities as
necessary.
Two
of
the most critical assumptions for postretirement benefit plans are the assumed
discount rate and the expected health care cost trend rates. We utilize a yield
curve approach based on Aa corporate bonds and the expected timing of future
benefit payments as a basis for determining the discount rate. The accumulated
postretirement benefit obligation and service cost were developed using a health
care trend rate of 10.25 percent for 2006 reducing on an average of
approximately 0.65 percent per year to an ultimate trend rate of 5 percent
per
year for 2014 and later. The initial trend rate was selected with reference
to
recent Transocean experience and broader national statistics. The ultimate
trend
rate is a long-term assumption and was selected to reflect the anticipation
that
the portion of gross domestic product devoted to health care becomes
constant. Changes
in these and other assumptions used in the actuarial computations could impact
our projected benefit obligations, pension liabilities and pension
expense.
Weighted-average
discount rates used to determine benefit obligations were 5.64 percent and
5.37
percent for the years ended December 31, 2006 and 2005,
respectively.
Weighted-average
assumptions used to determine net periodic benefit cost were as
follows:
Rate
to which the cost trend rate is assumed to decline (the ultimate
trend
rate)
5
%
5
%
Year
that the rate reaches the ultimate trend rate
2014
2009
The
assumed health care cost trend rate could have a significant impact on the
amounts reported for postretirement benefits other than pensions. A
one-percentage point change in the assumed health care trend rate would have
the
following effects (in millions):
One-
One-
Percentage
Percentage
Point
Point
Increase
Decrease
Effect
on total service and interest cost components in 2006
$
-
$
-
Effect
on postretirement benefit obligations as of December 31,2006
$
4
$
(5
)
The
following postretirement benefits payments are expected to be paid (in
millions):
Defined
Contribution Plans—We
provide a defined contribution pension and savings plan covering senior non-U.S.
field employees working outside the United States. Contributions and costs
are
determined as 4.5 percent to 6.5 percent of each covered employee's salary,
based on years of service. In addition, we sponsor a U.S. defined contribution
savings plan that covers certain employees and limits our contributions to
no
more than 4.5 percent of each covered employee's salary, based on the employee's
contribution. We also sponsor various other defined contribution plans
worldwide. We recorded approximately $26 million, $21 million and $20 million
of
expense related to our defined contribution plans for the years ended December31, 2006, 2005 and 2004, respectively.
Deferred
Compensation Plan—We
provided a Deferred Compensation Plan (the “Plan”). The Plan's primary purpose
was to provide tax-advantageous asset accumulation for a select group of
management, highly compensated employees and non-employee members of the board
of directors.
Eligible
employees who enrolled in the Plan could elect to defer up to a maximum of
90
percent of base salary, 100 percent of any future performance awards, 100
percent of any special payments and 100 percent of directors' meeting fees
and
annual retainers; however, the administrative committee (seven individuals
appointed by the finance and benefits committee of the board of directors)
could, at its discretion, establish minimum amounts that must be deferred by
anyone electing to participate in the Plan. In addition, the executive
compensation committee of the board of directors could authorize employer
contributions to participants and our chief executive officer, with executive
compensation committee approval, was authorized to cause us to enter into
“deferred compensation award agreements” with such participants. There were no
employer contributions to the Plan during the years ended December 31, 2006,
2005 or 2004.
In
2005,
the Plan was amended to effectively freeze the Plan as of December 31,2004.
Note
20—Investments
in and Advances to Unconsolidated Affiliates
We
have a
50 percent interest in Overseas Drilling Limited (“ODL”), which owns the
drillship Joides
Resolution.
The
drillship is contracted to perform drilling and coring operations in deep waters
worldwide for the purpose of scientific research. We manage and operate the
vessel on behalf of ODL. We recognized investments in and advances to
unconsolidated affiliates of $9 million and $8 million for the years ended
December 31, 2006 and 2005, respectively, and reported these amounts in other
assets in our consolidated balance sheet. See Note 22—Related Party
Transactions.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We
recognized equity in earnings of unconsolidated affiliates of $5 million, $10
million and $9 million for the three years ended December 31, 2006, 2005 and
2004, respectively, and reported these amounts in other, net in our consolidated
statement of operations.
As
a
result of our deconsolidation of TODCO at December 17, 2004, we accounted for
our 22 percent interest in TODCO as an investment in an unconsolidated
subsidiary and recognized our investment in TODCO under the equity method of
accounting. As a result of the May Offering, we accounted for our remaining
two
percent interest using the cost method of accounting and as a result of the
June
Sale, we no longer own any shares of TODCO. See Note 4—TODCO Stock
Sales.
Note
21—Segments,
Geographical Analysis and Major Customers
Through
December 16, 2004, our operations were aggregated into two reportable segments:
(i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists
of floaters, jackups and other rigs used in support of offshore drilling
activities and offshore support services. The TODCO segment consisted of our
interest in TODCO, which conducts jackup, drilling barge, land rig, submersible
and other operations located in the U.S. Gulf of Mexico and inland waters,
Mexico, Trinidad and Venezuela. The organization and aggregation of our business
into the two segments were based on differences in economic characteristics,
customer base, asset class, contract structure and management structure. In
addition, the TODCO segment fleet was highly dependent upon the U.S. natural
gas
industry while the Transocean Drilling segment’s operations are more dependent
upon the worldwide oil industry. As a result of the deconsolidation of TODCO
(see Note 1—Nature of Business and Principles of Consolidation), we now operate
in one industry segment, the Transocean Drilling segment.
Our
Transocean Drilling segment fleet operates in a single, global market for the
provision of contract drilling services. The location of our rigs and the
allocation of resources to build or upgrade rigs are determined by the
activities and needs of our customers. Accounting policies of the segments
are
the same as those described in the Summary of Significant Accounting Policies
(see Note 2—Summary of Significant Accounting Policies).
Operating
revenues and income before income taxes and minority interest by segment were
as
follows (in millions):
Operating
Income (Loss) Before General and Administrative Expense
Transocean
Drilling
$
428
TODCO
(a) (b)
(33
)
395
Unallocated
general and administrative expense
(67
)
Unallocated
other income (expense), net (c)
(88
)
Income
Before Income Taxes and Minority Interest(c)
$
240
______________
(a)
Includes
results from the TODCO segment to December 17, 2004, the effective
date of
the TODCO deconsolidation.
(b)
Includes
$32 million of operating and maintenance expense that TODCO classifies
as
general and administrative expense.
(c)
Includes
gains from the TODCO stock sales of $309 million and a non-cash charge
of
$167 million related to contingent amounts due from TODCO under a
tax
sharing agreement between us and TODCO. See Note 4—TODCO Stock Sales and
Note 15—Income Taxes.
Other
Countries represents countries in which we operate that individually
had
operating revenues or long-lived assets representing less than 10
percent
of total operating revenues earned or total long-lived
assets.
A
substantial portion of our assets are mobile. Asset locations at the end of
the
period are not necessarily indicative of the geographic distribution of the
revenues generated by such assets during the periods. Although we are organized
under the laws of the Cayman Islands, none of our rigs operate in the Cayman
Islands. As a result, we have no operating revenues or long-lived assets in
the
Cayman Islands.
Our
international operations are subject to certain political and other
uncertainties, including risks of war and civil disturbances (or other events
that disrupt markets), expropriation of equipment, repatriation of income or
capital, taxation policies, and the general hazards associated with certain
areas in which operations are conducted.
For
the
year ended December 31, 2006, Chevron, BP and Shell accounted for approximately
14 percent, 11 percent and 11 percent, respectively, of our operating revenues.
For the year ended December 31, 2005, Chevron and BP each accounted for
approximately 12 percent of our operating revenues. For the year ended December31, 2004, BP, Petrobras and Chevron each accounted for approximately 10 percent
of our operating revenues, of which the majority was reported in the Transocean
Drilling segment. The
loss
of these or other significant customers could have a material adverse effect
on
our results of operations.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
22—Related
Party Transactions
ODL—In
conjunction with the management and operation of the Joides
Resolution
on
behalf of ODL, we earned $2 million, $1 million and $2 million for the years
ended December 31, 2006, 2005 and 2004, respectively. Such amounts are included
in other revenues in our consolidated statements of operations. At December31,2006 and 2005, we had receivables due from ODL of $1 million and $2 million,
respectively, which were recorded as accounts receivable - other in our
consolidated balance sheets. Siem Offshore Inc. owns the other 50 percent
interest in ODL. Our director, Kristian Siem, is the chairman of Siem Offshore
Inc. and is also a director and officer of ODL. Mr. Siem is also chairman and
chief executive officer of Siem Industries, Inc., which owns an approximate
45
percent interest in Siem Offshore Inc.
In
November 2005, we entered into a loan agreement with ODL pursuant to which
we
may borrow up to $8 million. ODL may demand repayment at any time upon five
business days prior written notice given to us and any amount due to us from
ODL
may be offset against the loan amount at the time of repayment. As of December31, 2006 and 2005, $3 million and $4 million, respectively, was outstanding
under this loan agreement and was reflected as other long-term liabilities
in
our consolidated balance sheet. In 2006, ODL declared a dividend in the amount
of $4 million. In addition, ODL paid us cash dividends of $3 million and $11
million in 2005 and 2004, respectively.
TODCO—We
entered into a transition services agreement under which we provided specified
administrative support to TODCO during the transitional period following the
closing of the TODCO IPO. TODCO provides specified administrative support on
our
behalf for rig operations in Trinidad and Venezuela. Prior to the
deconsolidation of TODCO (see Note 1—Nature of Business and Principles of
Consolidation and Note 4—TODCO Stock Sales), amounts we earned under the
transition services agreement and amounts we incurred for administrative support
from TODCO were eliminated upon consolidation. As a result of our
deconsolidation of TODCO, amounts earned under the transition services agreement
were reflected in other revenues and amounts incurred for administrative support
are reflected in operating and maintenance expense in our consolidated statement
of operations. While any amounts recorded between us and TODCO subsequent to
the
deconsolidation of TODCO in mid-December 2004 were not material, we incurred
$1
million of costs related to service fees that TODCO billed to us in 2005. At
December 31, 2006 and 2005, we had payables related to the agreements for the
separation of TODCO of $1 million, which was included in accounts payable in
our
consolidated balance sheet. At December 31, 2006 and 2005, we had a long-term
payable related to our indemnification of certain TODCO non-U.S. income tax
liabilities of $11 million, which was included in other long-term liabilities
in
our consolidated balance sheet.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
23—Earnings
Per Share
The
reconciliation of the numerator and denominator used for the computation of
basic and diluted earnings per share is as follows (in millions, except per
share data):
Add
back interest expense on the 1.5% convertible debentures
6
6
−
Net
Income for diluted earnings per share
$
1,391
$
722
$
152
Denominator
for Diluted Earnings per Share
Weighted-average
shares outstanding for basic earnings per share
313
327
321
Effect
of dilutive securities:
Employee
stock options and unvested stock grants
4
4
2
Warrants
to purchase ordinary shares
3
3
2
1.5%
convertible debentures
5
5
−
Adjusted
weighted-average shares and assumed conversions for diluted earnings
per
share
325
339
325
Basic
Earnings Per Share
Net
Income
$
4.42
$
2.19
$
0.47
Diluted
Earnings Per Share
Net
Income
$
4.28
$
2.13
$
0.47
Ordinary
shares subject to issuance pursuant to the conversion features of the Zero
Coupon Convertible Debentures (see Note 7—Debt) are not included in the
calculation of adjusted weighted-average shares and assumed conversions for
diluted earnings per share for the years ended December 31, 2005 and 2004
because the effect of including those shares is anti-dilutive. The Zero Coupon
Convertible Debentures are included in the calculation of adjusted
weighted-average shares for the year ended December 31, 2006; however, they
did
not have a material effect on the calculation. Ordinary shares subject to
issuance pursuant to the conversion features of the 1.5% Convertible Debentures
are not included in the calculation of the adjusted weighted-average shares
and
assumed conversions for diluted earnings per share for the year ended December31, 2004 because the effect of including those shares is
anti-dilutive.
In
connection with the R&B Falcon merger, we assumed the then outstanding
R&B Falcon stock warrants. Each warrant enables the holder to purchase 17.5
ordinary shares at an exercise price of $19.00 per share. The warrants expire
on
May 1, 2009. On March 1, 2006, we issued 333,039 ordinary shares related to
a
cashless exercise of 25,100 warrants. At December 31, 2006, there were 203,900
warrants outstanding to purchase 3,568,250 ordinary shares.
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
25—Quarterly
Results (Unaudited)
Shown
below are selected unaudited quarterly data. Amounts are rounded for consistency
in presentation with no effect to the results of operations previously reported
on Form 10-Q or Form 10-K.
Three
months ended
March
31,
June
30,
September
30,
December
31,
(in
millions, except per share data)
2006
Operating
Revenues
$
817
$
854
$
1,025
$
1,186
Operating
Income (a)
284
289
390
678
Net
Income (a)
206
249
309
621
Basic
Earnings Per Share
$
0.63
$
0.77
$
0.99
$
2.13
Diluted
Earnings Per Share
$
0.61
$
0.75
$
0.96
$
2.05
Weighted
Average Shares Outstanding
Shares
for basic earnings per share
325
324
312
292
Shares
for diluted earnings per share
337
336
323
304
2005
Operating
Revenues
$
631
$
727
$
763
$
771
Operating
Income (b)
143
185
204
188
Net
Income (b) (c)
92
302
170
152
Basic
Earnings Per Share
$
0.28
$
0.93
$
0.52
$
0.46
Diluted
Earnings Per Share
$
0.28
$
0.90
$
0.50
$
0.45
Weighted
Average Shares Outstanding
Shares
for basic earnings per share
324
326
329
330
Shares
for diluted earnings per share
331
338
341
336
_________________________
(a)
First
quarter 2006 included gain on sale of assets of $65 million. Second
quarter 2006 included gain on sale of assets of $111 million. Third
quarter 2006 included gain on sale of assets of $45 million. Fourth
quarter 2006 included gain on sale of assets of $191 million. See
Note
6—Asset Dispositions.
(b)
First
quarter 2005 included gain on sale of an asset of $19 million. Second
quarter 2005 included gain on sale of assets of $14 million. See
Note
6—Asset Dispositions.
(c)
First
quarter 2005 included a loss on retirement of debt of $7 million
(see Note
7—Debt). Second quarter 2005 included gain from TODCO stock sales of
$165
million (see Note 4—TODCO Stock Sales). Fourth quarter 2005 included a net
income tax benefit of $16 million related to various tax adjustments
(see
Note 15—Income Taxes).
Note
26—Subsequent
Events (Unaudited)
Asset
Dispositions—In
January 2007, we completed the sale of our membership interest in Transocean
CGR
LLC (owner of the tender rig Charley
Graves)
for net
proceeds of $33 million and expect to recognize a gain on the sale of $23
million ($20 million or $0.07 per diluted share, net of tax).
Share
Repurchases—In 2007,
we repurchased approximately $400 million of our ordinary shares, which amounted
to approximately 5.2 million ordinary shares. Total consideration was funded
with existing cash balances and borrowings under our Revolving Credit
Facility.
Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
We
have
not had a change in or disagreement with our accountants within 24 months prior
to the date of our most recent financial statements or in any period subsequent
to such date.
In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls
and
procedures were effective as of December 31, 2006 to provide reasonable
assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act (i) accumulated and communicated to our
management, including our Chief Executive Officer and our Chief Financial
Officer, to allow timely decisions regarding required disclosure and (ii)
recorded, processed, summarized and reported within the time periods specified
in the Securities and Exchange Commission’s rules and forms.
There
were no changes in these internal controls during the quarter ended December31,2006 that have materially affected, or are reasonably likely to materially
affect, our internal controls over financial reporting.
See
“Management’s Report on Internal Control Over Financial Reporting” and “Report
of Independent Registered Public Accounting Firm on Internal Control over
Financial Reporting” included in Item 8 of this Annual Report.
The
information required by Items 10, 11, 12, 13 and 14 is incorporated herein
by
reference to our definitive proxy statement for our 2007 annual general meeting
of shareholders, which will be filed with the Securities and Exchange Commission
pursuant to Regulation 14A under the Securities Exchange Act of 1934 within
120
days of December 31, 2006. Certain information with respect to our executive
officers is set forth in Item 4 of this annual report under the caption
“Executive Officers of the Registrant.”
Reserves
and allowances deducted from asset accounts:
Allowance
for doubtful accounts receivable
15
32
-
21
(a)
26
Allowance
for obsolete materials and supplies
$
19
$
3
$
-
$
3
(e)
$
19
_____________________________
(a)
Uncollectible
accounts receivable written off, net of
recoveries.
(b)
Includes
amounts related to the TODCO
deconsolidation.
(c)
Amount
includes $1 related to adjustments to the provision.
(d)
Obsolete
materials and supplies written off, net of
scrap.
(e)
Amount
represents $3 related to sale of
rigs/inventory.
Other
schedules are omitted either because they are not required or are not applicable
or because the required information is included in the financial statements
or
notes thereto.
Agreement
and Plan of Merger dated as of July 12, 1999 among Schlumberger Limited,
Sedco Forex Holdings Limited, Transocean Offshore Inc. and Transocean
SF
Limited (incorporated by reference to Annex A to the Joint Proxy
Statement/Prospectus dated October 27, included in a 424(b)(3) prospectus
filed by the Company on November 1, 2000)
2.3
Distribution
Agreement dated as of July 12, 1999 between Schlumberger Limited
and Sedco
Forex Holdings Limited (incorporated by reference to Annex B to the
Joint
Proxy Statement/Prospectus dated October 27, included in a 424(b)(3)
prospectus filed by the Company on November 1, 2000)
2.4
Agreement
and Plan of Merger and Conversion dated as of March 12, 1999 between
Transocean Offshore Inc. and Transocean Offshore (Texas) Inc.
(incorporated by reference to Exhibit 2.1 to the Registration Statement
on
Form S-4 of Transocean Offshore (Texas) Inc. filed on April 8, 1999
(Registration No. 333-75899))
3.1
Memorandum
of Association of Transocean Sedco Forex Inc., as amended (incorporated
by
reference to Annex E to the Joint Proxy Statement/Prospectus dated
October30, 2000 included in a 424(b)(3) prospectus filed by the Company
on
November 1, 2000)
3.2
Articles
of Association of Transocean Sedco Forex Inc., as amended (incorporated
by
reference to Annex F to the Joint Proxy Statement/Prospectus dated
October30, 2000 included in a 424(b)(3) prospectus filed by the Company
on
November 1, 2000)
3.3
Certificate
of Incorporation on Change of Name to Transocean Inc. (incorporated
by
reference to Exhibit 3.3 to the Company’s Form 10-Q for the quarter ended
June 30, 2002)
Second
Supplemental Indenture dated as of May 14, 1999 between the Company
and
Chase Bank of Texas, National Association, as trustee (incorporated
by
reference to Exhibit 4.5 to the Company's Post-Effective Amendment
No. 1
to Registration Statement on Form S-3 (Registration No.
333-59001-99))
4.4
Third
Supplemental Indenture dated as of May 24, 2000 between the Company
and
Chase Bank of Texas, National Association, as trustee (incorporated
by
reference to Exhibit 4.1 to the Company's Current Report on Form
8-K filed
on May 24, 2000)
Form
of Zero Coupon Convertible Debenture due May 24, 2020 between the
Company
and Chase Bank of Texas, National Association, as trustee (incorporated
by
reference to Exhibit 4.1 to the Company's Current Report on Form
8-K filed
on May 24, 2000)
Officers'
Certificate establishing the terms of the 6.50% Notes due 2003, 6.75%
Notes due 2005, 6.95% Notes due 2008, 7.375% Notes due 2018, 9.125%
Notes
due 2003 and 9.50% Notes due 2008 (incorporated by reference to Exhibit
4.13 to the Company's Annual Report on Form 10-K for the fiscal year
ended
December 31, 2001)
Warrant
Agreement, including form of Warrant, dated April 22, 1999 between
R&B
Falcon and American Stock Transfer & Trust Company (incorporated by
reference to Exhibit 4.1 to R&B Falcon's Registration Statement No.
333-81181 on Form S-3 dated June 21, 1999)
4.15
Supplement
to Warrant Agreement dated January 31, 2001 among Transocean Sedco
Forex
Inc., R&B Falcon Corporation and American Stock Transfer & Trust
Company (incorporated by reference to Exhibit 4.28 to the Company's
Annual
Report on Form 10-K for the year ended December 31,2000)
4.16
Supplement
to Warrant Agreement dated September 14, 2005 between Transocean
Inc. and
The Bank of New York (incorporated by reference to Exhibit 4.3 to
our
Post-Effective Amendment No. 3 on Form S-3 to Form S-4 filed on November18, 2005)
Revolving
Credit Agreement, dated as of July 8, 2005, among Transocean Inc.,
the
lenders from time to time party thereto, Citibank, N.A., Bank of
America,
N.A., JPMorgan Chase Bank, N.A., The Royal Bank of Scotland plc and
SunTrust Bank (incorporated by reference to Exhibit 4.1 to our Current
Report on Form 8-K filed on July 13, 2005)
4.20
Amendment
No.1 to Revolving Credit Agreement, dated as of May 12, 2006, among
Transocean Inc., the lenders from time to time parties thereto, Citibank.,
N.A., Bank of America, N.A., JP Morgan Chase Bank, N.A., the Royal
Bank of
Scotland plc and SunTrust Bank (incorporated by reference to Exhibit
4.1
to our Current Report on Form 8-K filed on May 12,2006)
4.21
Term
Credit Agreement dated August 30, 2006 among Transocean Inc., the
lenders
party thereto and JPMorgan Chase Bank, N.A. as Administrative Agent,
Citibank, N.A. as Syndication Agent, and The Bank of Tokyo-Mitsubishi
UFJ,
Ltd., Calyon New York Branch and The Royal Bank of Scotland plc
(incorporated by reference to Exhibit 4.1 to our Current Report on
Form
8-K filed on August 31, 2006)
4.22
Form
of Officers’ Certificate of Transocean Inc. establishing the form and
terms of the Floating Rate Notes due 2008 (incorporated by reference
to
Exhibit 4.2 to our Current Report on Form 8-K filed on September1,2006)
10.1
Tax
Sharing Agreement between Sonat Inc. and Sonat Offshore Drilling
Inc.
dated June 3, 1993 (incorporated by reference to Exhibit 10-(3) to
the
Company's Form 10-Q for the quarter ended June 30,1993)
Performance
Award and Cash Bonus Plan of Sonat Offshore Drilling Inc. (incorporated
by
reference to Exhibit 10-(5) to the Company's Form 10-Q for the quarter
ended June 30, 1993)
*10.3
Form
of Sonat Offshore Drilling Inc. Executive Life Insurance Program
Split
Dollar Agreement and Collateral Assignment Agreement (incorporated
by
reference to Exhibit 10-(9) to the Company's Form 10-K for the year
ended
December 31, 1993)
*10.4
Amended
and Restated Employee Stock Purchase Plan of Transocean Inc. (incorporated
by reference to Exhibit 10.1 to the Company's Current Report on Form
8-K
dated May 16, 2005)
*10.5
Amended
and Restated Long-Term Incentive Plan of Transocean Inc. (incorporated
by
reference to Appendix B to the Company’s Proxy Statement dated March 19,2004)
Amendment
to Transocean Inc. Deferred Compensation Plan (incorporate by reference
to
Exhibit 10.1 to our Current Report on Form 8-K filed on December29,2005)
1992
Long-Term Incentive Plan of Reading & Bates Corporation (incorporated
by reference to Exhibit B to Reading & Bates' Proxy Statement dated
April 27, 1992)
*10.10
1995
Long-Term Incentive Plan of Reading & Bates Corporation (incorporated
by reference to Exhibit 99.A to Reading & Bates' Proxy Statement dated
March 29, 1995)
*10.11
1995
Director Stock Option Plan of Reading & Bates Corporation
(incorporated by reference to Exhibit 99.B to Reading & Bates' Proxy
Statement dated March 29, 1995)
*10.12
1997
Long-Term Incentive Plan of Reading & Bates Corporation (incorporated
by reference to Exhibit 99.A to Reading & Bates' Proxy Statement dated
March 18, 1997)
*10.13
1998
Employee Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy
Statement dated April 23, 1998)
1998
Director Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy
Statement dated April 23, 1998)
*10.15
1999
Employee Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.A to R&B Falcon's Proxy
Statement dated April 13, 1999)
*10.16
1999
Director Long-Term Incentive Plan of R&B Falcon Corporation
(incorporated by reference to Exhibit 99.B to R&B Falcon's Proxy
Statement dated April 13, 1999)
Form
of 2004 Performance-Based Nonqualified Share Option Award Letter
(incorporated by reference to Exhibit 10.2 to our Current Report
on Form
8-K filed on February 15, 2005)
*10.22
Form
of 2004 Employee Contingent Restricted Ordinary Share Award (incorporated
by reference to Exhibit 10.3 to our Current Report on Form 8-K filed
on
February 15, 2005)
Exhibits
listed above as previously having been filed with the SEC are incorporated
herein by reference pursuant to Rule 12b-32 under the Securities Exchange Act
of
1934 and made a part hereof with the same effect as if filed herewith.
Certain
instruments relating to our long-term debt and our subsidiaries have not been
filed as exhibits since the total amount of securities authorized under any
such
instrument does not exceed 10 percent of our total assets and our subsidiaries
on a consolidated basis. We agree to furnish a copy of each such instrument
to
the SEC upon request.
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned; thereunto duly authorized, on March 1, 2007.
TRANSOCEAN
INC.
By
/s/
Gregory L. Cauthen
Gregory
L. Cauthen
Senior
Vice President and Chief Financial Officer
Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has
been
signed below by the following persons on behalf of the registrant in the
capacities indicated on March 1, 2007.