UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
FORM
10-K
(Mark
One)
|
x
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
|
For
the fiscal year ended December 31, 2005
OR
|
o
|
TRANSITION
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF
1934
|
For
the transition period from _____ to ______.
Commission
file number 333-75899
TRANSOCEAN
INC.
(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. x
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, 2005, 328,508,472 ordinary shares were outstanding and the aggregate
market value of such shares held by non-affiliates was approximately $17.7
billion (based on the reported closing market price of the ordinary shares
on
such date of $53.97 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 28, 2006, 325,966,986 ordinary shares were
outstanding.
DOCUMENTS
INCORPORATED BY REFERENCE
Portions
of the registrant's definitive Proxy Statement to be filed with the Securities
and Exchange Commission within 120 days of December 31, 2005, for its 2006
annual general meeting of shareholders, are incorporated by reference into
Part
III of this Form 10-K.
INDEX
TO ANNUAL REPORT ON FORM 10-K
FOR
THE YEAR ENDED DECEMBER 31, 2005
|
Item
|
Page
|
||
|
4
|
|||
|
4
|
|||
|
5
|
|||
|
11
|
|||
|
13
|
|||
|
13
|
|||
|
13
|
|||
|
14
|
|||
|
14
|
|||
|
15
|
|||
|
15
|
|||
|
16
|
|||
|
20
|
|||
|
20
|
|||
|
20
|
|||
|
22
|
|||
|
22
|
|||
|
24
|
|||
|
25
|
|||
|
27
|
|||
|
59
|
|||
|
60
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
110
|
|||
|
111
|
|||
Forward-Looking
Information
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. Statements
to the effect that we or management “anticipates,” “believes,” “budgets,”
“estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” or
“projects” a particular result or course of events, or that such result or
course of events “could,” “might,” “may,” “scheduled” or “should” occur, and
similar expressions, are also intended to identify forward-looking statements.
Forward-looking statements in this annual report include, but are not limited
to, statements involving contract commencements, contract option exercises,
revenues, expenses, results of operations, commodity prices, customer drilling
programs, supply and demand, utilization rates, dayrates, contract backlog,
planned shipyard projects and rig mobilizations and their effects, newbuild
projects and opportunities, the upgrade projects for the Sedco
700-series
semisubmersible rigs, other major upgrades, rig reactivations, expected downtime
(including downtime with respect to the Deepwater
Nautilus
and
Transocean
Marianas),
the
impact of the hurricane damage to the Deepwater
Nautilus
and
Transocean
Marianas
on
operating income, capital expenditures and insurance proceeds, PetroJack ASA
options, future activity in the deepwater, mid-water and the shallow and inland
water market sectors, market outlook for our various geographical operating
sectors, capacity constraints for fifth-generation rigs, rig classes and
business segments, effects of new rigs on the market, income related to the
TODCO tax sharing agreement, the TODCO tax sharing agreement dispute, intended
reduction of debt and other uses of excess cash, including ordinary share
repurchases, the timing and funding of share repurchases, planned asset sales,
timing of asset sales, proceeds from asset sales, our effective tax rate,
changes in tax laws, treaties and regulations, our other expectations with
regard to market outlook, operations in international markets, expected capital
expenditures, results and effects of legal proceedings and governmental audits
and assessments, adequacy of insurance, liabilities for tax issues, liquidity,
cash flow from operations, adequacy of cash flow for our obligations, effects
of
accounting changes, adoption of accounting policies, pension plan and other
postretirement benefit plan contributions and benefit payments and the timing
and cost of completion of capital projects. Such statements are subject to
numerous risks, uncertainties and assumptions, including, but not limited to,
those described under “Item 1A. Risk Factors,” the adequacy of sources of
liquidity, 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.
|
Business
|
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 March 2, 2006, we owned, had partial ownership interests
in
or operated 89 mobile offshore and barge drilling units. As of this date, our
fleet included 32 High-Specification semisubmersibles and drillships
(“floaters”), 23 Other Floaters, 25 Jackup Rigs and 9 Other Rigs.
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 sectors 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, Texas 77046. Our telephone number
at that address is (713) 232-7500.
In
June
1993, the Company, then known as “Sonat Offshore Drilling Inc.,” completed an
initial public offering of approximately 60 percent of the outstanding shares
of
its common stock as part of its separation from Sonat Inc., and in July 1995
Sonat Inc. sold its remaining 40 percent interest in the Company through a
secondary public offering. In September 1996, the Company acquired Transocean
ASA, a Norwegian offshore drilling company, and changed its name to “Transocean
Offshore Inc.” On May 14, 1999, we completed a corporate reorganization by which
we changed our place of incorporation from Delaware to the Cayman
Islands.
In
December 1999, we completed our merger with Sedco Forex Holdings Limited (“Sedco
Forex”), the former offshore contract drilling business of Schlumberger Limited
(“Schlumberger”). Effective upon the merger, we changed our name to “Transocean
Sedco Forex Inc.” 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 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”), a publicly traded company and a former
wholly-owned subsidiary. 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 May 2002, we changed our name to “Transocean Inc.”
In
February 2004, we completed an initial public offering (the “TODCO IPO”) of
common stock of TODCO in which we sold 13.8 million shares of TODCO class A
common stock, representing 23 percent of TODCO’s total outstanding shares. 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 17.9 million shares of TODCO’s class A common stock
(30 percent of TODCO’s total outstanding shares) in the September 2004 Offering
and 15.0 million shares of TODCO’s class A common stock (25 percent of TODCO’s
total outstanding shares) 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, represented by 13.3 million shares
of
class A common stock.
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 12.0
million shares of TODCO’s class A common stock (20 percent of TODCO’s total
outstanding shares) in the May Offering and our remaining 1.3 million shares
of
TODCO’s class A common stock (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.
For
information about the revenues, operating income, assets and other information
relating to our business segments 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 22 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, tenders, a mobile offshore
production unit and a platform drilling rig.
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
March 2, 2006, our fleet of 89 rigs, which excludes assets held for sale,
included:
|
·
|
32
High-Specification Floaters, which are comprised of:
|
|
-
|
13
Fifth-Generation Deepwater
Floaters;
|
|
-
|
15
Other Deepwater Floaters; and
|
|
-
|
four
Other High-Specification Floaters;
|
|
·
|
23
Other Floaters;
|
|
·
|
25
Jackups; and
|
|
·
|
9
Other Rigs, which are comprised of:
|
|
-
|
three
barge drilling rigs;
|
|
-
|
four
tenders;
|
|
-
|
one
mobile offshore production unit;
and
|
|
-
|
one
coring drillship.
|
As
of
March 2, 2006, our fleet was located in the U.S. Gulf of Mexico (12 units),
Trinidad (one unit), Canada (one unit), Brazil (eight units), North Europe
(17
units), the Mediterranean and Middle East (five units), the Caspian Sea (one
unit), West Africa (16 units), India (10 units) and Asia and Australia (18
units).
We
periodically review the use of the term “deepwater” in connection with our
fleet. The term as used in the drilling industry to denote a particular sector
of the market varies somewhat 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.
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 1980’s, 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, and reflect our strategic focus on the ownership and operation of premium
high-specification floating rigs and jackups.
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. Some of our drillships can
also
be operated in a moored configuration. 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 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.
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 and effectively integrate new technology.
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.
Rigs
described in the following tables with a customer name are under contract,
including rigs being mobilized under contract. Rigs described as “warm stacked”
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. Rigs described as “upgrade” are undergoing a shipyard project
to enhance the operational capabilities of the rig, and rigs described as
“reactivation” are in the process of being reactivated to return to service.
Rigs described as “cold stacked” are not being 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. Our cold
stacked rigs and some of our 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. When market
conditions are depressed, we may consider marketing some of our 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 (32)
The
following tables provide certain information regarding our High-Specification
Floaters as of March 2, 2006:
|
Name
|
Type
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
|||||||
|
Fifth-Generation
Deepwater Floaters (13)
|
||||||||||||||
|
Deepwater
Discovery (c)
|
HSD
|
2000
|
10,000
|
30,000
|
Nigeria
|
ExxonMobil
|
April
2006
|
|||||||
|
Nigeria
|
Chevron
|
June
2006
|
||||||||||||
|
Nigeria
|
Petrobras
|
August
2006
|
||||||||||||
|
Nigeria
|
Shipyard
|
September
2006
|
||||||||||||
|
Nigeria
|
Total
|
September
2008
|
||||||||||||
|
Brazil
|
Devon
|
December
2011
|
||||||||||||
|
Deepwater
Expedition (c)
|
HSD
|
1999
|
10,000
|
30,000
|
Brazil
|
Petrobras
|
May
2006
|
|||||||
|
-
|
Mob/Contract
Prep
|
July
2006
|
||||||||||||
|
Egypt
|
Shell
|
November
2006
|
||||||||||||
|
-
|
Mob/Contract
Prep
|
December
2006
|
||||||||||||
|
Morocco
|
Petronas
|
March
2007
|
||||||||||||
|
-
|
Mob/Contract
Prep
|
May
2007
|
||||||||||||
|
India
|
Reliance
|
June
2009
|
||||||||||||
|
Deepwater
Frontier (c)
|
HSD
|
1999
|
10,000
|
30,000
|
Brazil
|
Petrobras
|
June
2006
|
|||||||
|
-
|
Mob/Contract
Prep
|
September
2006
|
||||||||||||
|
India
|
Reliance
|
October
2008
|
||||||||||||
|
India
|
Shipyard
|
November
2008
|
||||||||||||
|
India
|
Reliance
|
December
2011
|
||||||||||||
|
Deepwater
Millennium (c)
|
HSD
|
1999
|
10,000
|
30,000
|
U.S.
Gulf
|
Anadarko
|
June
2010
|
|||||||
|
Deepwater
Pathfinder (c)
|
HSD
|
1998
|
10,000
|
30,000
|
Nigeria
|
Devon/Shell/Conoco
|
August
2006
|
|||||||
|
Nigeria
|
Shell/Agip/Petrobras
|
June
2007
|
||||||||||||
|
Nigeria
|
Shipyard
|
June
2007
|
||||||||||||
|
Nigeria
|
Devon
|
September
2007
|
||||||||||||
|
Nigeria
|
Shell/Agip/Petrobras
|
December
2008
|
||||||||||||
|
Discoverer
Deep Seas (c) (e)
|
HSD
|
2001
|
10,000
|
35,000
|
U.S.
Gulf
|
Chevron
|
March
2007
|
|||||||
|
U.S.
Gulf
|
Shipyard
|
March
2007
|
||||||||||||
|
U.S.
Gulf
|
Chevron
|
January
2011
|
||||||||||||
|
Discoverer
Enterprise (c) (e)
|
HSD
|
1999
|
10,000
|
35,000
|
U.S.
Gulf
|
BP
|
December
2010
|
|||||||
|
Discoverer
Spirit (c) (e)
|
HSD
|
2000
|
10,000
|
35,000
|
U.S.
Gulf
|
Chevron
|
March
2006
|
|||||||
|
U.S.
Gulf
|
Shell
|
August
2007
|
||||||||||||
|
U.S.
Gulf
|
Anadarko
|
August
2010
|
||||||||||||
|
Deepwater
Horizon (c)
|
HSS
|
2001
|
10,000
|
30,000
|
U.S.
Gulf
|
BP
|
September
2010
|
|||||||
|
Cajun
Express (c) (f)
|
HSS
|
2001
|
8,500
|
35,000
|
U.S.
Gulf
|
Chevron
|
May
2006
|
|||||||
|
U.S.
Gulf
|
Shipyard
|
June
2006
|
||||||||||||
|
U.S.
Gulf
|
Chevron
|
January
2010
|
||||||||||||
|
Deepwater
Nautilus (d)
|
HSS
|
2000
|
8,000
|
30,000
|
U.S.
Gulf
|
Shell
|
May
2006
|
|||||||
|
U.S.
Gulf
|
Shipyard
|
July
2006
|
||||||||||||
|
U.S.
Gulf
|
Shell
|
December
2008
|
||||||||||||
|
Sedco
Energy (c) (f)
|
HSS
|
2001
|
7,500
|
25,000
|
Nigeria
|
Chevron
|
December
2007
|
|||||||
|
Sedco
Express (c) (f)
|
HSS
|
2001
|
7,500
|
25,000
|
Angola
|
BP
|
April
2007
|
|||||||
|
Angola
|
Shipyard
|
May
2007
|
||||||||||||
|
Angola
|
BP
|
June
2008
|
||||||||||||
|
Other
Deepwater Floaters (15)
|
||||||||||||||
|
Deepwater
Navigator (c)
|
HSD
|
2000
|
7,200
|
25,000
|
Brazil
|
KMG/Devon
|
May
2006
|
|||||||
|
Brazil
|
Shell
|
December
2006
|
||||||||||||
|
Brazil
|
Petrobras
|
January
2011
|
|
Name
|
Type
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
|||||||
|
Discoverer
534 (c)
|
HSD
|
1975/1991
|
7,000
|
25,000
|
Singapore
|
Mob/Contract
Prep
|
April
2006
|
|||||||
|
China
|
Husky
|
June
2006
|
||||||||||||
|
-
|
Shipyard
|
March
2007
|
||||||||||||
|
India
|
Reliance
|
October
2009
|
||||||||||||
|
Discoverer
Seven Seas (c)
|
HSD
|
1976/1997
|
7,000
|
25,000
|
India
|
ONGC
|
March
2006
|
|||||||
|
India
|
Shipyard
|
May
2006
|
||||||||||||
|
India
|
ONGC
|
April
2007
|
||||||||||||
|
India
|
Shipyard
|
July
2007
|
||||||||||||
|
India
|
ONGC
|
August
2010
|
||||||||||||
|
Transocean
Marianas
|
HSS
|
1979/1998
|
7,000
|
25,000
|
U.S.
Gulf
|
Shipyard
|
March
2006
|
|||||||
|
U.S.
Gulf
|
BP
|
April
2006
|
||||||||||||
|
U.S.
Gulf
|
Shipyard
|
May
2006
|
||||||||||||
|
U.S.
Gulf
|
BP
|
December
2006
|
||||||||||||
|
U.S.
Gulf
|
BP
|
January
2010
|
||||||||||||
|
Sedco
707 (c)
|
HSS
|
1976/1997
|
6,500
|
25,000
|
Brazil
|
Petrobras
|
April
2006
|
|||||||
|
Brazil
|
Shipyard
|
June
2006
|
||||||||||||
|
Brazil
|
Petrobras
|
April
2010
|
||||||||||||
|
Jack
Bates
|
HSS
|
1986/1997
|
5,400
|
30,000
|
Australia
|
Woodside
|
April
2006
|
|||||||
|
Australia
|
Chevron
|
July
2006
|
||||||||||||
|
-
|
Mob/Contract
Prep
|
October
2006
|
||||||||||||
|
U.S.
Gulf
|
Woodside
|
November
2008
|
||||||||||||
|
Peregrine
I (c)
|
HSD
|
1982/1996
|
5,200
|
25,000
|
Brazil
|
Petrobras
|
January
2009
|
|||||||
|
Sedco
709 (c)
|
HSS
|
1977/1999
|
5,000
|
25,000
|
Angola
|
ExxonMobil
|
April
2006
|
|||||||
|
S.
Africa
|
Mob/Contract
Prep
|
September
2006
|
||||||||||||
|
Nigeria
|
Shell
|
September
2008
|
||||||||||||
|
M.
G. Hulme, Jr.
|
HSS
|
1983/1996
|
5,000
|
25,000
|
Nigeria
|
Total
|
August
2006
|
|||||||
|
Transocean
Richardson
|
HSS
|
1988
|
5,000
|
25,000
|
Ivory
Coast
|
CNR
|
April
2006
|
|||||||
|
Ivory
Coast
|
Shipyard
|
May
2006
|
||||||||||||
|
Angola
|
Total
|
June
2007
|
||||||||||||
|
Jim
Cunningham
|
HSS
|
1982/1995
|
4,600
|
25,000
|
Nigeria
|
Agip
|
February
2007
|
|||||||
|
-
|
Shipyard
|
March
2007
|
||||||||||||
|
Angola
|
ExxonMobil
|
March
2009
|
||||||||||||
|
Transocean
Leader
|
HSS
|
1987/1997
|
4,500
|
25,000
|
Norwegian
N. Sea
|
Statoil
|
July
2007
|
|||||||
|
Norwegian
N. Sea
|
Shipyard
|
August
2007
|
||||||||||||
|
Norwegian
N. Sea
|
Statoil
|
June
2008
|
||||||||||||
|
Transocean
Rather
|
HSS
|
1988
|
4,500
|
25,000
|
U.K.
North Sea
|
BP
|
April
2006
|
|||||||
|
U.K.
North Sea
|
Shell
|
July
2006
|
||||||||||||
|
U.K.
North Sea
|
Chevron
|
December
2006
|
||||||||||||
|
U.K.
North Sea
|
BP
|
September
2007
|
||||||||||||
|
U.K.
North Sea
|
Shipyard
|
October
2007
|
||||||||||||
|
U.K.
North Sea
|
BP
|
December
2007
|
||||||||||||
|
Sovereign
Explorer
|
HSS
|
1984
|
4,500
|
25,000
|
Trinidad
|
BG
|
April
2006
|
|||||||
|
-
|
Shipyard
|
May
2006
|
||||||||||||
|
Venezuela
|
Statoil
|
November
2006
|
||||||||||||
|
-
|
Shipyard
|
June
2007
|
||||||||||||
|
Sedco
710 (c)
|
HSS
|
1983/2001
|
4,500
|
25,000
|
Brazil
|
Petrobras
|
February
2006
|
|||||||
|
Brazil
|
Shipyard
|
March
2006
|
||||||||||||
|
Brazil
|
Petrobras
|
February
2007
|
||||||||||||
|
Brazil
|
Shipyard
|
April
2007
|
||||||||||||
|
Brazil
|
Petrobras
|
December
2010
|
|
Name
|
Type
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
|||||||
|
Other
High-Specification Floaters (4)
|
||||||||||||||
|
Henry
Goodrich
|
HSS
|
1985
|
2,000
|
30,000
|
Canada
|
Terra
Nova
|
August
2006
|
|||||||
|
Paul
B. Loyd, Jr.
|
HSS
|
1990
|
2,000
|
25,000
|
U.K.
North Sea
|
BP
|
June
2006
|
|||||||
|
U.K.
North Sea
|
Shipyard
|
July
2006
|
||||||||||||
|
U.K.
North Sea
|
BP
|
April
2009
|
||||||||||||
|
Transocean
Arctic
|
HSS
|
1986
|
1,650
|
25,000
|
Norwegian
N. Sea
|
Statoil
|
September
2007
|
|||||||
|
Norwegian
N. Sea
|
Shipyard
|
October
2007
|
||||||||||||
|
Norwegian
N. Sea
|
Statoil
|
November
2010
|
||||||||||||
|
Polar
Pioneer
|
HSS
|
1985
|
1,500
|
25,000
|
Norwegian
N. Sea
|
Statoil
|
July
2009
|
“HSD”
means high-specification drillship.
“HSS”
means high-specification semisubmersible.
|
(a)
|
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
|
|
(b)
|
Expiration
dates represent our current estimate of the earliest date that the
contract for each rig is likely to expire or the shipyard,
mobilization/contract preparation, reactivation or upgrade is likely
to be
complete. Some rigs have two or more contracts in continuation, so
the
last line shows the last expected termination date. Some contracts
may
permit the client to extend the
contract.
|
|
(c)
|
Dynamically
positioned.
|
|
(d)
|
The
Deepwater
Nautilus is
leased from its owner, an unrelated third party, pursuant to a fully
defeased lease arrangement.
|
|
(e)
|
Enterprise-class
rig.
|
|
(f)
|
Express-class
rig.
|
Other
Floaters (23)
The
following table provides certain information regarding our Other Floaters as
of
March 2, 2006:
|
Name
|
Type
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
|||||||
|
Sedco
700
|
OS
|
1973/1997
|
3,600
|
25,000
|
E.
Guinea
|
A.
Hess
|
January
2007
|
|||||||
|
Transocean
Amirante
|
OS
|
1978/1997
|
3,500
|
25,000
|
U.S.
Gulf
|
ENI
|
March
2006
|
|||||||
|
U.S.
Gulf
|
ENI/Nexen
|
July
2006
|
||||||||||||
|
U.S.
Gulf
|
Remington
|
December
2006
|
||||||||||||
|
U.S.
Gulf
|
Shipyard
|
January
2007
|
||||||||||||
|
Transocean
Legend
|
OS
|
1983
|
3,500
|
25,000
|
Korea
|
KNOC
|
March
2006
|
|||||||
|
-
|
Mob/Contract
Prep
|
April
2006
|
||||||||||||
|
|
Sakhalin
Is.
|
BP
|
November
2007
|
|||||||||||
|
C.
Kirk Rhein, Jr.
|
OS
|
1976/1997
|
3,300
|
25,000
|
U.S.
Gulf
|
Cold
stacked
|
-
|
|||||||
|
Transocean
Driller
|
OS
|
1991
|
3,000
|
25,000
|
Brazil
|
Petrobras
|
February
2006
|
|||||||
|
|
Brazil
|
Shipyard
|
March
2006
|
|||||||||||
|
|
Brazil
|
Petrobras
|
August
2010
|
|||||||||||
|
Falcon
100
|
OS
|
1974/1999
|
2,400
|
25,000
|
U.S.
Gulf
|
DeepGulf
Energy
|
April
2006
|
|||||||
|
|
U.S.
Gulf
|
Petrobras
|
March
2007
|
|||||||||||
|
Sedco
703
|
OS
|
1973/1995
|
2,000
|
25,000
|
Australia
|
Woodside
|
January
2007
|
|||||||
|
Sedco
711
|
OS
|
1982
|
1,800
|
25,000
|
U.K.
North Sea
|
Shell
|
June
2007
|
|||||||
|
|
U.K.
North Sea
|
Shipyard
|
July
2007
|
|||||||||||
|
|
U.K.
North Sea
|
Shell
|
October
2008
|
|||||||||||
|
Transocean
John Shaw
|
OS
|
1982
|
1,800
|
25,000
|
U.K.
North Sea
|
Nexen
|
June
2007
|
|||||||
|
|
-
|
Shipyard
|
July
2007
|
|||||||||||
|
Sedco
714
|
OS
|
1983/1997
|
1,600
|
25,000
|
U.K.
North Sea
|
Total
|
May
2007
|
|||||||
|
Sedco
712
|
OS
|
1983
|
1,600
|
25,000
|
U.K.
North Sea
|
Oilexco
|
March
2008
|
|
Name
|
Type
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
|||||||
|
Actinia
|
OS
|
1982
|
1,500
|
25,000
|
India
|
Reliance
|
July
2006
|
|||||||
|
India
|
Shipyard
|
August
2006
|
||||||||||||
|
India
|
Reliance
|
September
2006
|
||||||||||||
|
Sedco
601
|
OS
|
1983
|
1,500
|
25,000
|
Indonesia
|
Santos
|
November
2006
|
|||||||
|
Sedco
702 (d)
|
OS
|
1973/1992
|
1,500
|
25,000
|
Singapore
|
Upgrade
|
April
2008
|
|||||||
|
|
TBD
|
Shell
|
July
2010
|
|||||||||||
|
Sedneth
701
|
OS
|
1972/1993
|
1,500
|
25,000
|
Angola
|
Chevron
|
April
2006
|
|||||||
|
Angola
|
Shipyard
|
June
2006
|
||||||||||||
|
|
Angola
|
Chevron
|
June
2007
|
|||||||||||
|
Transocean
Prospect
|
OS
|
1983/1992
|
1,500
|
25,000
|
U.K.
North Sea
|
Reactivation
|
May
2006
|
|||||||
|
|
U.K.
North Sea
|
CNR
|
June
2008
|
|||||||||||
|
Transocean
Searcher
|
OS
|
1983/1988
|
1,500
|
25,000
|
Norwegian
N. Sea
|
Statoil
|
October
2006
|
|||||||
|
Transocean
Winner
|
OS
|
1983
|
1,500
|
25,000
|
Norwegian
N. Sea
|
Reactivation
|
September
2006
|
|||||||
|
|
Norwegian
N. Sea
|
TBD
|
October
2009
|
|||||||||||
|
Transocean
Wildcat
|
OS
|
1977/1985
|
1,300
|
25,000
|
U.K.
North Sea
|
Cold
stacked
|
-
|
|||||||
|
Transocean
Explorer
|
OS
|
1976
|
1,250
|
25,000
|
U.K.
North Sea
|
Cold
stacked
|
-
|
|||||||
|
J.
W. McLean
|
OS
|
1974/1996
|
1,250
|
25,000
|
U.K.
North Sea
|
ConocoPhillips
|
March
2006
|
|||||||
|
|
U.K.
North Sea
|
Shipyard
|
April
2006
|
|||||||||||
|
|
U.K.
North Sea
|
Shell
|
May
2008
|
|||||||||||
|
Sedco
704
|
OS
|
1974/1993
|
1,000
|
25,000
|
U.K.
North Sea
|
Venture
|
October
2006
|
|||||||
|
U.K.
North Sea
|
BG
|
March
2007
|
||||||||||||
|
U.K.
North Sea
|
Shipyard
|
March
2007
|
||||||||||||
|
U.K.
North Sea
|
BP
|
April
2008
|
||||||||||||
|
Sedco
706 (d)
|
OS
|
1976/1994
|
1,000
|
25,000
|
U.K.
North Sea
|
Total
|
June
2006
|
|||||||
|
TBD
|
Upgrade
|
February
2008
|
||||||||||||
|
Brazil
|
Chevron
|
March
2011
|
“OD”
means other drillship.
“OS”
means other semisubmersible.
“TBD”
means to be determined.
|
(a)
|
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
|
|
(b)
|
Expiration
dates represent our current estimate of the earliest date that the
contract for each rig is likely to expire or
the shipyard, mobilization/contract preparation, reactivation or
upgrade
is likely to be complete.
Some rigs have two or more contracts in continuation, so the last
line
shows the last expected termination date. Some contracts may permit
the
client to extend the contract.
|
|
(c)
|
Dynamically
positioned.
|
|
(d)
|
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 at a cost expected
to be
approximately $300 million for each rig. The Sedco
702
and Sedco
706
upgrades are scheduled to commence in early 2006 and in the third
quarter
of 2007, respectively. Once completed, these units will become part
of our
High-Specification Floaters fleet.
|
Jackups
(25)
The
following table provides certain information regarding our Jackups fleet as
of
March 2, 2006:
|
Name
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
||||||
|
Trident
IX
|
1982
|
400
|
21,000
|
Vietnam
|
JVPC
|
August
2006
|
||||||
|
Trident
17
|
1983
|
355
|
25,000
|
Vietnam
|
Petronas
Carigali
|
June
2006
|
||||||
|
Trident
20
|
2000
|
350
|
25,000
|
Caspian
Sea
|
Petronas
Carigali
|
January
2010
|
||||||
|
Harvey
H. Ward
|
1981
|
300
|
25,000
|
Malaysia
|
Petronas
Carigali
|
July
2006
|
||||||
|
Malaysia
|
Talisman
|
July
2008
|
||||||||||
|
J.
T. Angel
|
1982
|
300
|
25,000
|
Indonesia
|
EMP
|
March
2006
|
|
Name
|
Year
Entered
Service/
Upgraded(a)
|
Water
Depth
Capacity
(in
feet)
|
Drilling
Depth
Capacity
(in
feet)
|
Location
|
Customer
|
Estimated
Expiration
(b)
|
||||||
|
Singapore
|
Shipyard
|
June
2006
|
||||||||||
|
India
|
ONGC
|
January
2010
|
||||||||||
|
Roger
W. Mowell
|
1982
|
300
|
25,000
|
Malaysia
|
Talisman
|
November
2008
|
||||||
|
Ron
Tappmeyer
|
1978
|
300
|
25,000
|
India
|
ONGC
|
December
2006
|
||||||
|
India
|
Shipyard
|
January
2007
|
||||||||||
|
India
|
ONGC
|
January
2010
|
||||||||||
|
D.
R. Stewart
|
1980
|
300
|
25,000
|
Italy
|
ENI
|
March
2007
|
||||||
|
Randolph
Yost
|
1979
|
300
|
25,000
|
India
|
ONGC
|
December
2006
|
||||||
|
India
|
Shipyard
|
February
2007
|
||||||||||
|
India
|
ONGC
|
February
2010
|
||||||||||
|
C.
E. Thornton
|
1974
|
300
|
25,000
|
India
|
ONGC
|
October
2007
|
||||||
|
India
|
Shipyard
|
October
2007
|
||||||||||
|
F.
G. McClintock
|
1975
|
300
|
25,000
|
India
|
ONGC
|
January
2008
|
||||||
|
Shelf
Explorer
|
1982
|
300
|
25,000
|
Indonesia
|
Pearl
Oil
|
April
2006
|
||||||
|
Indonesia
|
Chevron
|
September
2006
|
||||||||||
|
Transocean
III
|
1978/1993
|
300
|
20,000
|
Egypt
|
Zeitco
|
July
2006
|
||||||
|
Egypt
|
Shipyard
|
July
2006
|
||||||||||
|
Egypt
|
Zeitco
|
August
2007
|
||||||||||
|
Transocean
Nordic
|
1984
|
300
|
25,000
|
India
|
ONGC
|
March
2007
|
||||||
|
-
|
Shipyard
|
March
2007
|
||||||||||
|
Trident
II
|
1977/1985
|
300
|
25,000
|
India
|
ONGC
|
November
2006
|
||||||
|
India
|
Shipyard
|
March
2007
|
||||||||||
|
India
|
ONGC
|
March
2010
|
||||||||||
|
Trident
IV
|
1980/1999
|
300
|
25,000
|
Nigeria
|
Chevron
|
December
2006
|
||||||
|
Nigeria
|
Shipyard
|
January
2007
|
||||||||||
|
Nigeria
|
Chevron
|
March
2008
|
||||||||||
|
Trident
VIII
|
1981
|
300
|
21,000
|
-
|
Mob/Contract
Prep
|
March
2006
|
||||||
|
Nigeria
|
Conoil
|
April
2008
|
||||||||||
|
Trident
XII
|
1982/1992
|
300
|
25,000
|
India
|
ONGC
|
October
2006
|
||||||
|
-
|
Mob/Contract
Prep
|
January
2007
|
||||||||||
|
India
|
ONGC
|
December
2009
|
||||||||||
|
Trident
XIV
|
1982/1994
|
300
|
20,000
|
Cabinda
|
Chevron
|
April
2006
|
||||||
|
-
|
Shipyard
|
May
2006
|
||||||||||
|
Trident
15
|
1982
|
300
|
25,000
|
Thailand
|
Chevron
|
December
2006
|
||||||
|
Thailand
|
Shipyard
|
April
2007
|
||||||||||
|
Thailand
|
Chevron
|
June
2011
|
||||||||||
|
Trident
16
|
1982
|
300
|
25,000
|
Malaysia
|
Chevron
|
September
2007
|
||||||
|
George
H. Galloway
|
1984
|
300
|
25,000
|
Italy
|
ENI
|
July
2008
|
||||||
|
Transocean
Comet
|
1980
|
250
|
20,000
|
Egypt
|
GUPCO
|
November
2006
|
||||||
|
Egypt
|
Shipyard
|
December
2006
|
||||||||||
|
Egypt
|
GUPCO
|
October
2007
|
||||||||||
|
Transocean
Mercury
|
1969/1998
|
250
|
20,000
|
Egypt
|
Petrobel
|
February
2008
|
||||||
|
Trident
VI
|
1981
|
220
|
21,000
|
Vietnam
|
PetroVietnam
|
January
2007
|
|
(a)
|
Dates
shown are the original service date and the date of the most recent
upgrade, if any.
|
|
(b)
|
Expiration
dates represent our current estimate of the earliest date that the
contract for each rig is likely to expire or the shipyard,
mobilization/contract preparation, reactivation or upgrade is likely
to be
complete. Some rigs have two or more contracts in continuation, so
the
last line shows the last expected termination date. Some contracts
may
permit the client to extend the
contract.
|
Other
Rigs
In
addition to our floaters and jackups, we also own or operate several other
types
of rigs. These rigs include three drilling barges, four tenders, 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 shallow water market sector begins at the outer limit of the transition
zone and extends to water depths of about 300 feet. We service this sector
with
our jackups and drilling tenders. 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 are as follows (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Operating
Revenues
|
||||||||||
|
United
States
|
$
|
648
|
$
|
856
|
$
|
753
|
||||
|
Brazil
|
265
|
278
|
317
|
|||||||
|
India
|
296
|
271
|
120
|
|||||||
|
United
Kingdom
|
335
|
209
|
212
|
|||||||
|
Other
Countries (a)
|
1,348
|
1,000
|
1,032
|
|||||||
|
Total
Operating Revenues
|
$
|
2,892
|
$
|
2,614
|
$
|
2,434
|
||||
|
As
of December 31,
|
||||||||||
|
2005
|
2004
|
|||||||||
|
Long-Lived
Assets
|
|
|||||||||
|
United
States
|
$
|
2,311
|
$
|
2,397
|
||||||
|
Brazil
|
762
|
865
|
||||||||
|
Nigeria
|
980
|
811
|
||||||||
|
Other
Countries (a)
|
2,695
|
2,932
|
||||||||
|
Total
Long-Lived Assets
|
$
|
6,748
|
$
|
7,005
|
||||||
|
(a)
|
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.
|
From
time
to time, we provide well services in addition to our normal drilling services
through third party contractors. 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 or fixed
price basis depending on the daily activity. As of March 2, 2006, we were
performing such services in the North Sea and 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. Major clients included BP, Shell, Petrobras, Chevron and ONGC. Our
largest clients in 2005 were Chevron and BP accounting for 12.1 percent and
11.7 percent, respectively, of our 2005 operating revenues. No other client
accounted for 10 percent or more of our 2005 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 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 the U.S. Outer Continental Shelf
Lands Act 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 January
31, 2006, we had approximately 9,600 employees and we also utilized
approximately 2,000 persons through contract labor providers. As of such date,
approximately 14 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, virtually all are working under
agreements that are subject to salary negotiation in 2006. These negotiations
could result in higher personnel expenses, other increased costs or increased
operating restrictions.
Our
website address is www.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-Financial Reports,” 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.
|
Risk
Factors
|
Our
business depends on the level of activity in the oil and gas industry, which
is
significantly affected by volatile oil and gas
prices.
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.
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. As of March 2, 2006, there are approximately 21 high-specification
rigs
and 51 jackup rigs under contract for construction with delivery dates ranging
from 2006 to approximately 2010. There are also a number of 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
drilling contracts may be terminated due to a number of
events.
Our
customers may terminate or suspend some of our term drilling contracts 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. 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 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.
Our
business involves numerous operating hazards.
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 for amounts that take into account a
number of factors including their approximate 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. Although our current practice is
generally
to
insure
all
of
our rigs
as
described above, our insurance would not completely cover the costs that would
be required to replace certain of our units, including certain
High-Specification Floaters.
However, we may in the future take significant self-insured retentions for
these
coverages, and we may also decide to partially or fully self-insure our drilling
rigs with respect to property damage. 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.
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
March 2, 2006, 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.
A
change in tax laws 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
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
shipyard projects are subject to delays and cost
overruns.
We
have
scheduled one deepwater newbuild rig project, two Sedco
700-series
rig upgrades and two reactivation projects in our Other Floaters
fleet, 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;
|
|
·
|
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.
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. To the extent that demand for drilling services
and the size of the worldwide industry fleet increase, shortages of qualified
personnel could arise, creating upward pressure on wages. We are continuing
our
recruitment and training programs as required to meet our anticipated personnel
needs.
On
January 31, 2006, approximately 14 percent of our employees and contracted
labor
worldwide worked under collective bargaining agreements, most of whom worked
in
Norway, U.K. and Nigeria. Of these represented individuals, virtually all are
working under agreements that are subject to salary negotiation in 2006. These
negotiations could result in higher personnel expenses, other increased costs
or
increased operating restrictions.
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.
In
the
past several years, 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.
|
Unresolved
Staff Comments
|
None.
|
Properties
|
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, Asia and Australia. We lease most of
these facilities.
|
Legal
Proceedings
|
Several
of our subsidiaries have been named, along with other defendants, in several
complaints that have been filed in the Circuit Courts of the State of
Mississippi 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 and other unaffiliated
defendant companies, including companies that allegedly manufactured drilling
related products containing asbestos that are the subject of the complaints.
The
number of unaffiliated defendant companies involved in each complaint ranges
from approximately 20 to 70. 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 seek, among other things, awards of unspecified compensatory
and punitive damages. The trial court has ordered that the plaintiffs provide
additional information regarding their employment histories. We have not yet
had
an opportunity to conduct extensive discovery nor have we been able to
definitively 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, however, and have an action to stay execution of a related tax
foreclosure proceeding. We expect that the government will attempt to enforce
the judgment on this assessment and that the amount claimed may exceed the
amounts we believe are 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 these 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, filed a "show cause notice" against one
of
our subsidiaries and various third parties in July 1999. The show cause notice
alleged 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 issued its order, which found that we had imported the rig
improperly and intentionally concealed the import from the authorities, and
directed us to pay a redemption fee of approximately $3 million for the rig
in
lieu of confiscation and to pay penalties of approximately $1 million in
addition to the amount of customs duties owed. In February 2000, we filed an
appeal with the Customs, Excise and Service Tax Appellate Tribunal (“CESTAT”),
together with an application to have the confiscation of the rig stayed pending
the outcome of the appeal. In March 2000, the CESTAT ruled on the stay
application, directing that the confiscation be stayed pending the appeal.
The
CESTAT issued its order on our appeal on February 2, 2001, and while it found
that the rig was imported in 1988 without proper documentation or payment of
duties, the redemption fee and penalties were reduced to less than $0.1 million
in view of the ambiguity surrounding the import practice at the time and the
lack of intentional concealment by us. The CESTAT further sustained our position
regarding the value 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 in view of the prevailing practice of the Customs Department, thus
limiting our exposure as to custom duties to approximately $6 million. Although
CESTAT did not grant us the benefit of a customs duty exemption due to the
absence of the required documentation, CESTAT left it open for our subsidiary
to
seek such documentation from the Ministry of Petroleum. Following the CESTAT
order, we tendered payment of redemption, penalty and duty in the amount
specified by the order by offset against a $0.6 million deposit and $10.7
million guarantee previously made by us. The Customs Department attempted to
draw the entire guarantee, alleging the actual duty payable is approximately
$22
million based on an interpretation of the CESTAT order that we believe is
incorrect. This action was stopped by an interim ruling of the High Court,
Mumbai on writ petition filed by us. We and the Customs Department both filed
appeals with the Supreme Court of India against the order of the CESTAT, and
both appeals were admitted. The Supreme Court has dismissed the Customs
Department appeal and affirmed the CESTAT order 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 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.
In
October 2001, TODCO was notified by the U.S. Environmental Protection Agency
("EPA") that the EPA had identified a subsidiary as a potentially responsible
party in connection with the Palmer Barge Line superfund site located in Port
Arthur, Texas. Based upon the information provided by the EPA and a review
of
TODCO's internal records to date, TODCO disputes its designation as a
potentially responsible party. Pursuant to the master separation agreement
with
TODCO, we are responsible and will indemnify TODCO for any losses TODCO incurs
in connection with this action. 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
August
2003, a judgment of approximately $9.5 million was entered by the Labor Division
of the Provincial Court of Luanda, Angola, against us and one of our labor
contractors, Hull Blyth, in favor of certain former workers on several of our
drilling rigs. The workers were employed by Hull Blyth to work on several
drilling rigs while the rigs were located in Angola. When the drilling contracts
concluded and the rigs left Angola, the workers' employment ended. The workers
brought suit claiming that they were not properly compensated when their
employment ended. In addition to the monetary judgment, the Labor Division
ordered the workers to be hired by us. We believe that this judgment is without
sufficient legal foundation and have appealed the matter to the Angola Supreme
Court. We further believe that Hull Blyth has an obligation to protect us from
any judgment. 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 the Sedco Forex merger, 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
have a
dispute with TODCO concerning payment to us under our tax sharing agreement
with
TODCO for the tax benefit that TODCO derives from exercises of options to
purchase our ordinary shares held by employees of TODCO. An arbitration
proceeding was initiated in January 2006, and the parties are in the process
of
appointing an arbitrator. We are 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. TODCO is seeking to avoid such payment and is asking that the entire
tax
sharing agreement be voided. TODCO also filed suit in Houston in the district
court of the State of Texas in January 2006 seeking to set aside the arbitration
provision and to void the entire tax sharing agreement. We believe TODCO owes
us
approximately $10.7 million based on options exercised through December 31,
2005, and we do not believe TODCO’s attempts to void the tax sharing agreement
have merit. We do not expect the outcome of this matter 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, 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.
|
Submission
of Matters to a Vote of Security Holders
|
The
Company did not submit any matter to a vote of its security holders during
the
fourth quarter of 2005.
|
Officer
|
Office
|
Age
as of
March 1,
2006
|
||
|
Robert
L. Long
|
President
and Chief Executive Officer
|
60
|
||
|
Jean
P. Cahuzac
|
Executive
Vice President and Chief Operating Officer
|
52
|
||
|
Eric
B. Brown
|
Senior
Vice President, General Counsel and Corporate Secretary
|
54
|
||
|
Gregory
L. Cauthen
|
Senior
Vice President and Chief Financial Officer
|
48
|
||
|
Steven
L. Newman
|
Senior
Vice President, Human Resources, Information Process Solutions and
Treasury
|
41
|
||
|
David
A. Tonnel
|
Vice
President and Controller
|
36
|
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 President, Chief Executive Officer and a member of the board of
directors of the Company. Mr. Long served as President of the Company from
December 2001 to October 2002, at which time he assumed the additional position
of Chief Executive Officer and became a member of the board of directors.
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 Executive Vice President and Chief Operating Officer of the Company.
Mr. Cahuzac served as Executive Vice President, Operations of the Company from
February 2001 until October 2002, at which time he assumed his current position.
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 since 1979.
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.
Steven
L.
Newman is Senior Vice President of Human Resources, Information Process
Solutions and Treasury. Mr. Newman served as Vice President of Performance
and
Technology of the Company from August 2003 until March 2005, at which time
he
assumed his current position. Mr. Newman served as Regional 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.
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
|
|||||||||
|
2004
|
First
Quarter
|
$
|
31.94
|
$
|
23.10
|
|||||
|
|
Second
Quarter
|
29.27
|
24.49
|
|||||||
|
|
Third
Quarter
|
36.24
|
25.94
|
|||||||
|
|
Fourth
Quarter
|
43.25
|
33.70
|
|||||||
|
|
||||||||||
|
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
|
|||||||
On
February 28, 2006, the last reported sales price of our ordinary shares on
the
NYSE Composite Tape was $74.18 per share. On such date, there were 12,747
holders of record of our ordinary shares and 325,966,986 ordinary shares
outstanding.
We
paid
quarterly cash dividends of $0.03 per ordinary share from the fourth quarter
of
1993 to the second quarter of 2002. Any future declaration and payment of
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, 2006, 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.
Directors are elected by a plurality of the votes cast in the election.
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 (1) passed by the holders of two-thirds
of
the shares voted at a general meeting or (2) 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
|
(a)
Total
Number
of
Shares
Purchased
(1)
|
(b)
Average
Price
Paid
Per
Share
|
(c)
Total Number of
Shares
Purchased as
Part
of Publicly
Announced
Plans or
Programs
(2)
|
(d)
Maximum Number (or
Approximate
Dollar
Value)
of Shares that May
Yet
Be Purchased Under
the
Plans or Programs (2)
(in
millions)
|
|||||||||
|
October 2005
|
(149
|
)
|
$
|
52.01
|
N/A
|
$
|
2,000.0
|
||||||
|
November 2005
|
—
|
—
|
N/A
|
N/A
|
|||||||||
|
December 2005
|
6,040,230
|
66.44
|
6,014,751
|
1,600.0
|
|||||||||
|
Total
|
6,040,081
|
$
|
66.44
|
6,014,751
|
$
|
1,600.0
|
|||||||
|
(1)
|
Total
number of shares purchased in December 2005 includes 25,479 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
October 2005, our board of directors authorized the repurchase of
up to $2
billion of our ordinary shares. 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 December
31, 2005, we have repurchased a total of 6,014,751 of our ordinary
shares
at a total cost of $400 million ($66.50 per share).
|
|
Selected
Financial Data
|
The
selected financial data as of December 31, 2005 and 2004 and for each of the
three years in the period ended December 31, 2005 has been derived from the
audited consolidated financial statements included elsewhere herein. The
selected financial data as of December 31, 2003, 2002 and 2001, and for the
years ended December 31, 2002 and 2001 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.”
On
January 31, 2001, we completed a merger transaction with R&B Falcon. As a
result of the merger, R&B Falcon became our indirect wholly owned
subsidiary. The merger was accounted for as a purchase and we were treated
as
the accounting acquiror. The balance sheet data as of December 31, 2001
represents the consolidated financial position of the combined company. The
statement of operations and other financial data for the year ended December
31,
2001 include eleven months of operating results and cash flows for the merged
company.
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. As a result of the conversion of the TODCO class B common stock into
class A common stock, our ownership and voting interest declined to
approximately 22 percent 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.
|
Years
ended December 31,
|
||||||||||||||||
|
2005
|
2004
|
2003
|
2002
|
2001
|
||||||||||||
|
(In
millions, except per share data)
|
||||||||||||||||
|
Statement
of Operations
|
||||||||||||||||
|
Operating
revenues
|
$
|
2,892
|
$
|
2,614
|
$
|
2,434
|
$
|
2,674
|
$
|
2,820
|
||||||
|
Operating
income (loss)
|
720
|
328
|
240
|
(2,310
|
)
|
550
|
(a)
|
|||||||||
|
Income
(loss) before cumulative effect of changes in accounting
principles
|
716
|
152
|
18
|
(2,368
|
)
|
253
|
|
|||||||||
|
Cumulative
effect of changes in accounting principles.
|
−
|
−
|
1
|
(1,364
|
)
|
−
|
|
|||||||||
|
Net
income (loss)
|
716
|
152
|
19
|
(3,732
|
)
|
253
|
|
|||||||||
|
Basic
earnings (loss) per share
|
|
|||||||||||||||
|
Income
(loss) before cumulative effect of changes in accounting principles
per
share
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
$
|
(7.42
|
)
|
$
|
0.82
|
|
||||
|
Cumulative
effect of changes in accounting principles
|
−
|
−
|
−
|
(4.27
|
)
|
−
|
|
|||||||||
|
Net
income (loss)
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
$
|
(11.69
|
)
|
$
|
0.82
|
(a)
|
||||
|
Diluted
earnings (loss) per share
|
|
|||||||||||||||
|
Income
(loss) before cumulative effect of changes in accounting principles
per
share
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
$
|
(7.42
|
)
|
$
|
0.80
|
|
||||
|
Cumulative
effect of changes in accounting principles
|
−
|
−
|
−
|
(4.27
|
)
|
−
|
||||||||||
|
Net
income (loss)
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
$
|
(11.69
|
)
|
$
|
0.80
|
(a)
|
||||
|
|
||||||||||||||||
|
Balance
Sheet Data (at end of period)
|
||||||||||||||||
|
Total
assets
|
$
|
10,457
|
$
|
10,758
|
$
|
11,663
|
$
|
12,665
|
$
|
17,048
|
||||||
|
Long-term
debt
|
1,197
|
2,462
|
3,612
|
3,630
|
4,540
|
|||||||||||
|
Total
shareholders’ equity
|
7,982
|
7,393
|
7,193
|
7,141
|
10,910
|
|||||||||||
|
Dividends
per share
|
−
|
−
|
−
|
$
|
0.06
|
$
|
0.12
|
|||||||||
|
Other
Financial Data
|
||||||||||||||||
|
Cash
provided by operating activities
|
$
|
864
|
$
|
600
|
$
|
525
|
$
|
939
|
$
|
560
|
||||||
|
Cash
provided by (used in) investing activities
|
169
|
551
|
(445
|
)
|
(45
|
)
|
(26
|
)
|
||||||||
|
Cash
provided by (used in) financing activities
|
(1,039
|
)
|
(1,174
|
)
|
(820
|
)
|
(533
|
)
|
285
|
|||||||
|
Capital
expenditures
|
182
|
127
|
494
|
141
|
506
|
|||||||||||
|
Operating
margin
|
25
|
%
|
13
|
%
|
10
|
%
|
N/M
|
20
|
%
|
|||||||
“N/M”
means not meaningful due to loss on impairments of long-lived
assets.
|
(a)
|
Includes
goodwill amortization of $155 million, or $0.49 per diluted share.
Goodwill is no longer amortized beginning in fiscal year 2002 in
accordance with the Financial Accounting Standards Board's (“FASB”)
Statement of Financial Accounting Standards (“SFAS”) 142, Goodwill
and Other Intangible Assets.
|
|
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 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, the “Company,” “Transocean,” “we,” “us” or “our”) is a
leading international provider of offshore contract drilling services for oil
and gas wells. As of March 2, 2006, we owned, had partial ownership interests
in
or operated 89 mobile offshore and barge drilling units. As of this date, our
fleet included 32 High-Specification semisubmersibles and drillships
(“floaters”), 23 Other Floaters, 25 Jackup Rigs and 9 Other Rigs.
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:
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
Change
|
||||||||
|
(In
millions, except daily amounts and percentages)
|
||||||||||
|
Average
daily revenue (a)(c)(d)
|
$
|
105,100
|
$
|
71,300
|
$
|
33,800
|
||||
|
Utilization (b)(c)(d)
|
79
|
%
|
58
|
%
|
N/A
|
|||||
|
Statement
of Operations (c)
|
||||||||||
|
Operating
revenue
|
$
|
2,891.7
|
$
|
2,613.9
|
$
|
277.8
|
||||
|
Operating
and maintenance expense
|
1,720.6
|
1,713.6
|
7.0
|
|||||||
|
Operating
income
|
719.5
|
327.9
|
391.6
|
|||||||
|
Net
income
|
715.6
|
152.2
|
563.4
|
|||||||
|
Balance
Sheet Data (at end of period) (c)
|
||||||||||
|
Cash
|
445.4
|
451.3
|
(5.9
|
)
|
||||||
|
Total
Assets
|
10,457.2
|
10,758.3
|
(301.1
|
)
|
||||||
|
Total
Debt
|
1,597.1
|
2,481.5
|
(884.4
|
)
|
||||||
“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)
|
Utilization
is the total actual number of revenue earning days as a percentage
of the
total number of calendar days in the
period.
|
|
(c)
|
We
consolidated TODCO’s (together with its subsidiaries and predecessors,
unless the context requires otherwise, “TODCO,” a publicly traded company
and a former wholly-owned subsidiary) results of operations and financial
condition in our consolidated financial statements through December
16,
2004. We deconsolidated TODCO effective December 17, 2004 and subsequently
accounted for our investment in TODCO under the equity method of
accounting through May 18, 2005, at which time our ownership interest
fell
below 20 percent. See “―Significant
Events.”
|
|
(d)
|
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.
|
2005
was
an exceptional year for the industry with strong demand and increasing dayrates
for all asset classes, and we believe this strong demand will continue in 2006.
Leading dayrates are at record levels for most rig classes and customers are
contracting rigs for longer terms than we have seen historically for rigs other
than newbuilds. Interest in high-specification floaters is particularly
strong and we are seeing interest on the part of some customers to discuss
availability of rigs starting as far out as 2008 and extending toward the end
of
the decade. There is also evidence of a broadening base of customers with
deepwater drilling rig requirements for exploration and production drilling
programs in various geographic locations. Some of these rig needs could
potentially be addressed by new rig construction. We are presently aware of
a
number of operators that have expressed an interest in awarding drilling
contracts for newly constructed ultra-deepwater floaters. As a result of the
level of activity industrywide, we are seeing increases in our cost
structure. A shortage of qualified people is driving compensation cost up
and suppliers are increasing prices as their backlogs build. These labor
and vendor price increases, while meaningful, are not significant in comparison
with our expected increase in revenue for 2006 and beyond. We also have a
deepwater newbuild rig, two major upgrades and a large number of repair and
maintenance shipyard projects underway or planned to commence in 2006. The
actual timing and duration of these shipyard projects, along with the actual
start of higher dayrate contracts, will have a significant influence on our
results of operations in 2006.
Our
revenues and operating and maintenance expenses for the year ended December
31,
2005 increased from the prior year due to increased activity and higher labor
and rig maintenance costs, partially offset by the deconsolidation of TODCO
effective December 17, 2004 (see “—Results of Operations”) and decreased
integrated services provided to our clients. For the year ended December 31,
2005, our revenues and our operating and maintenance expenses were adversely
affected as a result of damage sustained to two of our High-Specification
semisubmersibles during hurricanes Katrina and Rita (see “—Significant Events”).
Our financial results for the year ended December 31, 2005 included the
recognition of gains from our May 2005 public offering (the “May Offering”) and
June 2005 sale pursuant to Rule 144 under the Securities Act of 1933 (the “June
Sale,” and, together with the May Offering, the “2005 Offering and Sale”) of
TODCO common stock, gains from the sale of three rigs, other income recognized
under the TODCO tax sharing agreement and reductions in tax expense related
to
the settlement of various tax audits, partially offset by income tax provisions
attributable to the restructuring of certain non-U.S. operations and charges
pertaining to a loss on retirement of debt (see “—Significant Events”). Our
financial results for the year ended December 31, 2004 included gains recognized
on the TODCO initial public offering (“TODCO IPO”) as well as the September 2004
and December 2004 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”) and a gain from
the sale of a rig, partially offset by a tax valuation allowance adjustment
and
stock option expense recorded in connection with the TODCO IPO as well as a
non-cash charge related to contingent amounts due from TODCO under the tax
sharing agreement and charges pertaining to losses on retirement of debt (see
“—Results of Operations”). Cash decreased during the year ended December 31,
2005 primarily as a result of increased capital expenditures, the early
retirements of debt and repurchase of ordinary shares, partially offset by
proceeds received from the 2005 Offering and Sale, the sale of rigs and
exercises of stock options, as well as cash provided by operating activities.
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
(see “―Significant Events”), we
now
operate in one business 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.
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 1980’s, 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, and reflect our strategic focus on the ownership and operation of premium
high-specification floating rigs and jackups.
Significant
Events
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 is expected to be out of service
approximately 60 days in 2006. The Transocean
Marianas
was out
of service for 95 days in 2005 and is expected to be out of service
approximately 100 days in 2006. Operating income in 2005 was negatively impacted
by approximately $39 million due to lost revenue and higher operating and
maintenance costs on the Transocean
Marianas
and the
Deepwater
Nautilus.
Depending on the timing of the repairs, we currently estimate the total lost
revenue plus repair, crew and other costs for the two rigs to have a negative
impact on operating income of approximately $45 million to $55 million in 2006.
In addition, we also expect to spend approximately $30 million on capital
expenditures to replace damaged equipment. See "—Income
and Expense Categories-Operating and Maintenance Costs.”
Asset
Acquisition—In
May
2005, we purchased the semisubmersible rig M.
G.
Hulme, Jr.,
which
we had previously operated under a lease arrangement. See “—Off-Balance Sheet
Arrangement.”
Asset
Dispositions—In
January 2005, we completed the sale of the semisubmersible rig Sedco
600
for net
proceeds of $24.9 million, of which $2.5 million was received in 2004,
and recognized a gain on the sale of $18.8 million. In June 2005, we
sold the jackup rig Transocean
Jupiter
and a
land rig for net proceeds of $23.5 million and recognized a gain on the sale
of
$14.0 million. See “—Capital Expenditures, Acquisitions and
Dispositions.”
In
February 2006, we completed the sale of the drillship Peregrine
III for
net
proceeds of $78.7 million, of which $7.8 million was received in December 2005,
and expect to recognize a gain on the sale of approximately $62 million. See
“—Liquidity and Capital Resources-Capital Expenditures, Acquisitions and
Dispositions.”
Debt
Repurchase and Redemption—In
March
2005, we redeemed our $247.8 million aggregate principal amount outstanding
6.95% Senior Notes due April 2008 at the make-whole premium price provided
in
the indenture. We redeemed these notes at 108.259 percent of face value, or
$268.2 million, plus accrued and unpaid interest. In the first quarter of 2005,
we recognized a loss on this redemption of $6.7 million, which reflected
adjustments for fair value of the debt at the date of the merger with R&B
Falcon Corporation and the unamortized fair value adjustment on a previously
terminated interest rate swap. We funded the redemption with existing cash
balances.
In
July
2005, we acquired, pursuant to a tender offer, a total of $534.4 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 $590.9 million, plus
accrued and unpaid interest. In the third quarter of 2005, we recognized a
gain
on this repurchase of $0.2 million, which reflected adjustments for the
unamortized fair value adjustment on a previously terminated interest rate
swap.
We funded the repurchase with existing cash balances.
Revolving
Credit Agreement—In
July
2005, we entered into a $500.0 million, five-year revolving credit agreement
(the “Revolving Credit Agreement”). In conjunction with entering into this
facility, we terminated our $800.0 million, five-year revolving credit agreement
dated December 2003 and recognized a loss on the termination of this agreement
of $0.8 million in the third quarter of 2005.
Repurchase
of Ordinary Shares—In
October 2005, our board of directors authorized the repurchase of up to $2
billion of our ordinary shares. In December 2005, we repurchased and retired
$400 million of our ordinary shares, which amounted to approximately 6.0 million
ordinary shares. See “—Liquidity and Capital Resources-Sources and Uses of
Cash.”
TODCO—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 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. In the second quarter of 2005, we
received net proceeds of $271.9 million from the 2005 Offering and Sale and
recognized a gain of $165.0 million, which represented the excess of net
proceeds received over the net book value of the shares sold in the 2005
Offering and Sale. We refer collectively to the 2005 Offering and Sale and
the
public offerings of TODCO Class A common stock in 2004 as the “TODCO Stock
Sales.”
Outlook
Drilling
Market—Oil
and
natural gas commodity prices continue to be strong, and we expect prices to
remain high for the near future relative to historical price levels. Future
price expectations have historically been a key driver for offshore drilling
demand. However, the availability of quality drilling prospects, exploration
success, relative production costs, the stage of reservoir development and
political and regulatory environments also affect our customers’ drilling
programs.
Prospects
for our 32 High-Specification Floaters continue to be robust. We have recently
been awarded a five-year contract for the construction of an enhanced
Enterprise-class
drillship, to be named the Discoverer
Clear Leader,
with an
estimated total capital expenditure of approximately $650 million. We currently
expect this rig to begin operations in the U.S. Gulf of Mexico in approximately
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. We
are
also currently in discussions with several clients concerning other potential
drilling contracts for newbuild deepwater rigs.
We
have
also signed a number of other new contracts or extensions for our
High-Specification Floaters that reflect the strong activity in this sector.
We
have been awarded multi-year contracts for the Transocean
Marianas, Jack Bates, Sedco 709, Deepwater Discovery,
the two
Sedco
700-series
semisubmersible upgrades, Discoverer
Spirit and
Deepwater Millennium. Additionally,
we have entered into contract extensions for multi-year programs for the
Deepwater
Nautilus,
Deepwater
Frontier, Cajun Express
and
Discoverer
Enterprise.
We
continue to believe that, over the long term, deepwater exploration and
development drilling opportunities in the Gulf of Mexico, West Africa, Brazil
and India and other emerging deepwater market sectors represent a significant
source of future deepwater rig demand. We continue to see an appreciable
customer preference for using fifth-generation equipment in these deepwater
areas, which we believe has led to a near-term shortage of these highest
specification rigs.
Our
Other
Floaters fleet, comprised of 23 semisubmersible rigs, is largely committed
to
contracts that extend into 2007, excluding three semisubmersible rigs that
remain idle. This fleet continues to benefit from improving activity levels
in
all regions. Robust customer demand remains evident in most operating regions,
including the North Sea, West Africa and India. In the U.K. sector of the North
Sea, our three most recent contract awards within this fleet have dayrates
ranging from $250,000 to $310,000. These three contracts have varying
commencement dates in 2007 for one-year durations extending into 2008. We have
begun the reactivation of two previously idle semisubmersibles, the Transocean
Prospect
and
Transocean
Winner,
both
supported by multi-year contracts, which are expected to commence by June 2006
and October 2006, respectively. We continue to evaluate contract opportunities
that could result in the reactivation of our idle rigs, the semisubmersible
rigs
C.
Kirk Rhein, Jr.
and
Transocean
Wildcat.
Should
a decision be made to reactivate any of the idle units, they are not expected
to
be operational before the third quarter of 2006.
In
the
fourth quarter of 2005, we entered into agreements with a subsidiary of Royal
Dutch Petroleum (Shell) and with Chevron for the upgrades of two Sedco
700-series
semisubmersibles in our Others Floaters fleet. Under the Shell agreement, Shell
is committed to a three-year contract to be finalized by the parties based
upon
stated drilling contract principles. We expect the upgrade to be completed
in
approximately the second quarter of 2007, subject to finalization of project
arrangements and other factors, at a cost of approximately $300 million
depending upon final specifications and other factors. Drilling operations
would
commence after commissioning and acceptance following the shipyard work. Shell
has the right to terminate the contract if the shipyard work is not completed
by
February 15, 2008.
Under
the
Chevron agreement, Chevron is committed to a three-year contract, with a right
to extend the contract for an additional two years, to be finalized by the
parties based upon stated drilling contract principles. We expect the upgrade
to
be completed in approximately the second quarter of 2008, subject to
finalization of project arrangements and other factors, at a cost of
approximately $300 million depending upon final specifications and other
factors. Drilling operations would commence after commissioning and acceptance
following the shipyard work. Chevron has the right to terminate the contract
if
the shipyard work is not completed by December 31, 2008.
The
outlook for activity for the jackup market sector remains strong, particularly
in South East Asia, India and West Africa. We recently signed three-year
contracts for drilling programs in India involving five of our jackups. We
expect to remain at or near full utilization for our Jackups fleet in the near
term. However, we continue to monitor the potential effect of newbuild jackups,
which have scheduled delivery dates ranging from 2006 through approximately
2010. While we have not seen an appreciable effect to date, the addition of
rig
capacity could have an adverse impact on utilization and dayrates.
In
January 2006, we entered into rig marketing and purchase option agreements
with
PetroJack ASA pursuant to which we were granted exclusive marketing rights
for,
and options to purchase, up to three premium jackup rigs under construction.
Our
marketing rights and option period runs through March 15, 2006. We have not
exercised any of the options but would anticipate exercising an option if we
could secure a drilling contract of sufficient value and duration for the rig.
We are not obligated to exercise any of the options.
While
we
anticipate a favorable demand environment to continue during 2006 and into
2007,
our results of operations in 2006 will be significantly influenced by the actual
timing and duration of the various shipyard projects and the actual start of
higher dayrate contracts. We expect our results in the first two quarters of
2006 to be negatively impacted by the combination of anticipated higher
operating and maintenance expenses and lost revenue due to out of service time
and delays in the start of higher dayrate contracts.
We
expect
downtime and significant costs to be incurred during the first quarter of 2006
resulting from planned shipyard projects and/or mobilizations for the
Discoverer
534, Sedco 710, J. W. McLean, Transocean Driller and J. T.
Angel,
as well
as for the Transocean
Marianas
and the
Deepwater
Nautilus
due to
the hurricane incidents. These
rig
mobilizations and shipyard projects are expected to have an adverse impact
on
revenues and operating income. We also expect to incur significant costs related
to the reactivation of the previously idled Transocean
Prospect
and
Transocean
Winner.
In
addition, vendor price increases and rising labor costs due to increased
drilling activity, as well as anticipated increases in insurance costs, are
expected to increase operating and maintenance costs. The combination of these
trends is expected to lead to a level of operating and maintenance costs in
the
first and second quarters of 2006 that is higher than the fourth quarter of
2005.
Our
shipyard projects, including the construction of the deepwater drillship
Discoverer
Clear Leader, the
Sedco
700-series
rig upgrades, our two rig reactivations and any other potential newbuild
projects, are subject to risks of delay and cost overruns for a variety of
reasons, including some outside of our control. A delay could adversely affect
any drilling contract for the rig following the shipyard work, depending upon
the drilling contract terms.
We
also
expect that a number of pre-existing, fixed-price contract options will be
exercised by our customers, which will preclude us from taking full advantage
of
increased market rates for those rigs subject to these contract options. We
have
seven existing contracts with fixed-priced or capped options for dayrates that
we believe are less than current market dayrates. Customers may also use
well-in-progress or similar provisions in our existing contracts to delay the
start of higher dayrates in subsequent contracts.
We
continue to monitor the potential effects of announced newbuild deepwater
drilling rigs and deepwater upgrade projects. Most of these units have scheduled
completion dates in 2008 and beyond, and we are unable to predict what effect,
if any, the additional capacity will have on the drilling market. While we
currently believe demand for deepwater drilling services will remain strong
into
2008, the addition of deepwater rig capacity could have an adverse impact on
utilization and dayrates.
The
offshore contract drilling market remains highly competitive and cyclical,
and
it has been historically difficult to forecast future market conditions.
Declines in oil and/or gas prices and other risks may reduce rig demand and
adversely affect utilization and dayrates. Major operator and national oil
company capital budgets are key drivers of the overall business climate, and
these may change within a fiscal year depending on exploration results and
other
factors. Additionally, 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.
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.
Tax
Matters—We
are a
Cayman Islands company registered in Barbados. 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 non-U.S.
assessments. We accrue for income tax contingencies that we believe are probable
exposures. While we cannot predict or provide assurance as to the final outcome,
we do not expect the liability, if any, resulting from existing or future
assessments to have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
Our
2002
and 2003 U.S. federal income tax returns are currently under examination by
the
IRS and our 2001 U.S. federal income tax return remains open for examination.
No
examination report has been received at this time. While we cannot predict
or
provide assurance as to the final outcome, we do not expect the liability,
if
any, resulting from the examination to have a material adverse effect on our
consolidated financial position, results of operations or cash
flows.
In
September 2004, the Norwegian tax authorities initiated inquiries related to
a
restructuring transaction undertaken in 2001 and 2002 and a 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. During 2005,
we
have continued to respond to information requests from the Norwegian
authorities. Based on these inquiries, we believe the Norwegian authorities
are
contemplating a tax assessment of approximately $96.4 million on the dividend,
plus penalty and interest. No assessment has been made, and we believe
such an assessment would be without merit. While we cannot predict or
provide assurance as to the final outcome, we do not expect the liability,
if
any, resulting from the inquiry to have a material adverse effect on our
consolidated financial position, results of operations or cash
flows.
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, we established
an
initial valuation allowance in the first quarter of 2004 of approximately $31.0
million 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 the Financial Accounting Standards Board’s (“FASB”) Statement of
Financial Accounting Standard (“SFAS”) 109, Accounting
for Income Taxes. We
adjusted the initial valuation allowance during 2004 to reflect changes in
our
estimate of the ultimate amount of TODCO’s deferred tax assets. 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 in the third quarter of 2005 to adjust
the
previously estimated allocation. This allocation is subject to potential
revision upon subsequent IRS audit of our tax returns 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 under the tax sharing
agreement.
Under
the
tax sharing agreement entered into between us and TODCO in connection with
the
TODCO IPO, we are entitled to receive from TODCO payment for most of the tax
benefits generated prior to the TODCO IPO that TODCO utilizes subsequent to
the
TODCO IPO. As long as TODCO was our consolidated subsidiary, we followed the
provisions of SFAS 109, which allowed us to evaluate the recoverability of
the
deferred tax assets associated with the tax sharing agreement considering the
deferred tax liabilities of TODCO. We recorded a valuation allowance for the
excess of these deferred tax assets over the deferred tax liabilities of TODCO,
also taking into account prudent and feasible tax planning strategies as
required by SFAS 109. Because we no longer own any shares of TODCO, we no longer
include TODCO as a consolidated subsidiary in our financial statements, and
we
are no longer able to apply the provisions of SFAS 109 in accounting for the
utilization of these deferred tax assets. As a result, we recorded a non-cash
charge of $167.1 million in the fourth quarter of 2004 related to contingent
amounts due from TODCO under the tax sharing agreement. In future years, as
TODCO generates taxable income and utilizes its pre-TODCO IPO tax assets, TODCO
is required to pay us for the benefits received in accordance with the
provisions of the tax sharing agreement. We will recognize those amounts as
other income as those amounts are realized, which is generally based on when
TODCO files its annual tax returns. We are involved in an arbitration proceeding
with TODCO in which we are seeking payment of certain disputed amounts, and
TODCO is seeking, in both this proceeding as well as in a lawsuit, to
void the entire tax sharing agreement. We believe TODCO owes us the disputed
payments and do not believe TODCO’s attempts to void the tax sharing agreement
have merit. See “Item 3. Legal Proceedings.”
During
the year ended December 31, 2005, we received $32.0 million in payments from
TODCO related to TODCO’s expected utilization of such tax benefits for the 2004
and 2005 tax years. Of the $32.0 million received, $11.4 million and $20.6
million was received for the 2004 tax year and a portion of the 2005 tax year,
respectively. Included in the 2005 payments are $1.7 million relating to stock
options deductions. In 2005, TODCO filed its 2004 U.S. federal and state income
tax returns and we recognized $11.4 million as other income in our consolidated
income statement. The amounts received pertaining to TODCO’s 2005 federal and
state income tax returns, as well as payments received related to stock options
deductions, were 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 2005 federal and state income tax returns and
the
dispute with TODCO is resolved.
Estimated
tax benefits in excess of $300 million remain to be utilized by TODCO under
the
tax sharing agreement, although the ultimate amount and timing of the
utilization is highly contingent on a variety of factors including potential
revisions to the tax benefits upon examination by the IRS, which is currently
reviewing our 2002 and 2003 tax years, the amount of taxable income that TODCO
realizes in future years and the resolution of the dispute with TODCO related
to
the tax sharing agreement.
Performance
and Other Key Indicators
Contract
Backlog—The
following table reflects our contract backlog and associated average contractual
dayrates at the periods ended on or prior to December 31, 2005 for our
Transocean Drilling segment and reflects firm commitments only, typically
represented by signed 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. Our contract backlog is calculated by multiplying the contracted
operating dayrate by the firm contract period, excluding revenues for
mobilization, demobilization, contract preparation and customer reimbursables
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.
|
December
31,
2005
|
September
23,
2005
|
December
31,
2004
|
||||||||
|
(In
millions)
|
||||||||||
|
Contract
Backlog
|
||||||||||
|
High-Specification
Floaters
|
$
|
8,329.5
|
$
|
5,093.3
|
$
|
1,897.6
|
||||
|
Other
Floaters
|
1,643.2
|
1,062.6
|
206.3
|
|||||||
|
Jackups
|
808.3
|
531.8
|
558.9
|
|||||||
|
Other
Rigs
|
132.3
|
148.0
|
200.3
|
|||||||
|
Total
|
$
|
10,913.3
|
$
|
6,835.7
|
$
|
2,863.1
|
||||
The
following table reflects the amount and the average dayrate of our contract
backlog by year as of December 31, 2005.
|
For
the years ending December 31,
|
|||||||||||||||||||
|
Total
|
2006
|
2007
|
2008
|
2009
|
Thereafter
|
||||||||||||||
|
(In
millions, except average dayrates)
|
|||||||||||||||||||
|
Contract
Backlog
|
|||||||||||||||||||
|
High-Specification
Floaters
|
$
|
8,329.5
|
$
|
1,962.8
|
$
|
2,067.8
|
$
|
2,113.6
|
$
|
1,310.7
|
$
|
874.6
|
|||||||
|
Other
Floaters
|
1,643.2
|
772.5
|
485.1
|
223.3
|
137.8
|
24.5
|
|||||||||||||
|
Jackups
|
808.3
|
466.7
|
204.6
|
65.1
|
29.2
|
42.7
|
|||||||||||||
|
Other
Rigs
|
132.3
|
61.5
|
30.9
|
24.8
|
15.1
|
-
|
|||||||||||||
|
Total
|
$
|
10,913.3
|
$
|
3,263.5
|
$
|
2,788.4
|
$
|
2,426.8
|
$
|
1,492.8
|
$
|
941.8
|
|||||||
|
Average
Dayrates
|
Total
|
2006
|
2007
|
2008
|
2009
|
Thereafter
|
|||||||||||||
|
High-Specification
Floaters
|
$
|
269,100
|
$
|
205,000
|
$
|
268,100
|
$
|
315,900
|
$
|
316,300
|
$
|
308,600
|
|||||||
|
Other
Floaters
|
$
|
160,100
|
$
|
132,600
|
$
|
186,400
|
$
|
226,500
|
$
|
215,800
|
$
|
115,500
|
|||||||
|
Jackups
|
$
|
72,100
|
$
|
68,200
|
$
|
75,000
|
$
|
87,700
|
$
|
80,000
|
$
|
80,000
|
|||||||
|
Other
Rigs
|
$
|
36,700
|
$
|
39,400
|
$
|
35,200
|
$
|
33,900
|
$
|
34,600
|
-
|
||||||||
|
Total
|
$
|
194,700
|
$
|
137,100
|
$
|
200,300
|
$
|
265,200
|
$
|
267,300
|
$
|
263,100
|
|||||||
Fleet
Utilization and Average Daily Revenue—The
following table shows our average daily revenue and utilization for the
quarterly periods ended on or prior to 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.
|
Three
months ended
|
||||||||||
|
December
31,
2005
|
September
30,
2005
|
December
31,
2004
|
||||||||
|
Average
Daily Revenue
|
||||||||||
|
Transocean
Drilling Segment:
|
||||||||||
|
High-Specification
Floaters
|
||||||||||
|
Fifth-Generation
Deepwater Floaters
|
$
|
215,800
|
$
|
197,100
|
$
|
180,100
|
||||
|
Other
Deepwater Floaters
|
$
|
138,800
|
$
|
141,700
|
$
|
119,400
|
||||
|
Other
High-Specification Floaters
|
$
|
161,700
|
$
|
166,300
|
$
|
135,700
|
||||
|
Total
High-Specification Floaters
|
$
|
174,100
|
$
|
168,800
|
$
|
149,000
|
||||
|
Other
Floaters
|
$
|
98,500
|
$
|
90,400
|
$
|
64,000
|
||||
|
Jackups
|
$
|
64,900
|
$
|
58,900
|
$
|
55,800
|
||||
|
Other
Rigs
|
$
|
48,500
|
$
|
48,000
|
$
|
48,100
|
||||
|
Segment
Total
|
$
|
113,300
|
$
|
107,100
|
$
|
93,900
|
||||
|
TODCO
Segment (a)
|
-
|
-
|
$
|
28,600
|
||||||
|
Total
Drilling Fleet
|
$
|
113,300
|
$
|
107,100
|
$
|
74,200
|
||||
|
Utilization
|
||||||||||
|
Transocean
Drilling Segment:
|
||||||||||
|
High-Specification
Floaters
|
||||||||||
|
Fifth-Generation
Deepwater Floaters
|
86
|
%
|
94
|
%
|
89
|
%
|
||||
|
Other
Deepwater Floaters
|
79
|
%
|
83
|
%
|
69
|
%
|
||||
|
Other
High-Specification Floaters
|
100
|
%
|
99
|
%
|
92
|
%
|
||||
|
Total
High-Specification Floaters
|
84
|
%
|
89
|
%
|
80
|
%
|
||||
|
Other
Floaters
|
71
|
%
|
68
|
%
|
50
|
%
|
||||
|
Jackups
|
89
|
%
|
98
|
%
|
81
|
%
|
||||
|
Other
Rigs
|
49
|
%
|
51
|
%
|
54
|
%
|
||||
|
Segment
Total
|
78
|
%
|
82
|
%
|
69
|
%
|
||||
|
TODCO
Segment (a)
|
-
|
-
|
47
|
%
|
||||||
|
Total
Drilling Fleet
|
78
|
%
|
82
|
%
|
61
|
%
|
||||
|
(a)
|
TODCO
was deconsolidated effective December 17, 2004.
|
Financial
Condition
December
31, 2005 compared to December 31, 2004
|
December
31,
|
|||||||||||||
|
2005
|
2004
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except % change)
|
|||||||||||||
|
Total
Assets
|
$
|
10,457.2
|
$
|
10,758.3
|
$
|
(301.1
|
)
|
(2.8
|
)%
|
||||
The
decrease in assets was mainly due to decreases in property and equipment, net
of
depreciation of $257.0 million and investments in unconsolidated affiliates
of
$101.1 million, partially offset by increases in accounts receivable of $157.7
million. The decrease in property and equipment, net is primarily related to
depreciation and asset sales during 2005, partially offset by capital
expenditures. The decrease in investments in unconsolidated affiliates is
primarily related to our disposition of TODCO. The increase in accounts
receivable is primarily related to the increase in activity during
2005.
Liquidity
and Capital Resources
Sources
and Uses of Cash
Our
primary sources of cash in 2005 were our cash flows from operations, proceeds
from asset sales, including the disposition of our investment in TODCO, and
proceeds from issuance of ordinary shares upon the exercise of stock options
and
warrants. Our primary uses of cash were debt repayments, repurchases of ordinary
shares and capital expenditures. At December 31, 2005, we had $445.4 million
in
cash and cash equivalents.
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
Change
|
||||||||
|
(In
millions)
|
||||||||||
|
Net
Cash Provided by Operating Activities
|
||||||||||
|
Net
income
|
$
|
715.6
|
$
|
152.2
|
$
|
563.4
|
||||
|
Depreciation
|
405.8
|
524.6
|
(118.8
|
)
|
||||||
|
Other
non-cash items
|
(122.1
|
)
|
(48.1
|
)
|
(74.0
|
)
|
||||
|
Working
capital
|
(135.1
|
)
|
(28.8
|
)
|
(106.3
|
)
|
||||
|
$
|
864.2
|
$
|
599.9
|
$
|
264.3
|
|||||
Net
cash
provided by operating activities increased due to an increase in cash generated
from net income, partially offset by a decrease in cash related to working
capital items, which resulted primarily from an increase in accounts receivable
as a result of activity and dayrate improvement.
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
Change
|
||||||||
|
(In
millions)
|
||||||||||
|
Net
Cash Provided by Investing Activities
|
||||||||||
|
Capital
expenditures
|
$
|
(181.9
|
)
|
$
|
(127.0
|
)
|
$
|
(54.9
|
)
|
|
|
Proceeds
from disposal of assets, net
|
74.1
|
52.9
|
21.2
|
|||||||
|
Proceeds
from TODCO Stock Sales, net
|
271.9
|
683.6
|
(411.7
|
)
|
||||||
|
Reduction
of cash from the deconsolidation of TODCO
|
−
|
(68.6
|
)
|
68.6
|
||||||
|
Joint
ventures and other investments, net
|
4.5
|
10.4
|
(5.9
|
)
|
||||||
|
$
|
168.6
|
$
|
551.3
|
$
|
(382.7
|
)
|
||||
Net
cash
provided by investing activities decreased $382.7 million over the previous
year. The decrease is primarily the result of a decrease in net proceeds from
the TODCO Stock Sales of $411.7 million and an increase in capital expenditures,
which includes $42.5 million for the purchase of the M.G.
Hulme, Jr.
(see
“―Off-Balance Sheet Arrangement”).
Partially offsetting these decreases was the increase in net proceeds from
asset
sales as compared to the prior year and the absence of a decrease in cash of
$68.6 million resulting from the deconsolidation of TODCO during 2004.
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
Change
|
||||||||
|
(In
millions)
|
||||||||||
|
Net
Cash Used in Financing Activities
|
||||||||||
|
Repayments
under revolving credit agreement
|
$
|
−
|
$
|
(250.0
|
)
|
$
|
250.0
|
|||
|
Repayments
on other debt instruments
|
(880.2
|
)
|
(955.3
|
)
|
75.1
|
|||||
|
Repurchases
of ordinary shares
|
(400.0
|
)
|
−
|
(400.0
|
)
|
|||||
|
Net
proceeds from issuance of ordinary shares under stock-based compensation
plans
|
219.5
|
30.4
|
189.1
|
|||||||
|
Proceeds
from issuance of ordinary shares upon exercise of warrants
|
10.6
|
−
|
10.6
|
|||||||
|
Decrease
in restricted cash
|
12.0
|
−
|
12.0
|
|||||||
|
Other,
net
|
(0.6
|
)
|
1.0
|
(1.6
|
)
|
|||||
|
$
|
(1,038.7
|
)
|
$
|
(1,173.9
|
)
|
$
|
135.2
|
|||
Net
cash
used in financing activities decreased in 2005 compared to 2004 primarily due
to
lower debt repayments, which included scheduled debt repayments, the early
redemption of our 9.5% Senior Notes and 6.75% Senior Notes and the repurchase
of
$142.7 million aggregate principal amount of our 8% Debentures by means of
a
tender offer in 2004, compared to the early redemption of our 6.95% Senior
Notes
and the repurchase of approximately 76.3 percent of our 6.625% Notes by means
of
a tender offer in 2005. We had repayments under our revolving credit facility
in
2004 with no comparable activity during 2005. We also received higher proceeds
from stock option and warrant exercises compared to the same period in 2004
and
the decrease in restricted cash of $12.0 million resulting from the repayment
of
the Deepwater
Nautilus
project
financing in May 2005 and the subsequent release of the restrictions on the
related cash.
In
December 2005, we repurchased and retired $400 million of our ordinary shares
from an investment bank, which amounted to approximately 6.0 million ordinary
shares, or $66.50 per share. Total consideration paid to repurchase the shares
of approximately $400 million was recorded in shareholders’ equity as a
reduction in ordinary shares and additional paid-in capital. Such consideration
was funded with existing cash balances.
Capital
Expenditures, Acquisitions 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 recently were awarded a drilling contract for the construction
of
a new deepwater drilling rig and are currently in discussions with various
clients for potential other deepwater drilling contracts related to new
deepwater rig construction. In addition, from time to time, we review possible
dispositions of drilling units.
Capital
Expenditures—Capital
expenditures totaled $181.9 million during the year ended December 31, 2005,
which included the purchase of the M.G.
Hulme, Jr.
(see
“—Off-Balance Sheet Arrangement”).
During
2006, we expect to spend between $750 million and $800 million on our existing
fleet, including approximately $250 million on the construction of the deepwater
drillship Discoverer
Clear Leader,
approximately $200 million required for the upgrade of two of our Sedco
700-series
rigs for Shell and Chevron, approximately $30 million to replace and upgrade
equipment damaged during hurricanes Katrina and Rita on the Deepwater
Nautilus
and the
Transocean
Marianas and
approximately $25 million to reactivate two of our Other Floaters. These amounts
are dependent upon the actual level of operational and contracting activity.
These amounts do not include capital expenditures that would be incurred as
a
result of any of the other newbuild or other reactivation opportunities being
discussed with clients (see “—Outlook”).
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 agreement (see “—Sources and
Uses of Liquidity”) and may utilize other commercial bank or capital market
financings.
Dispositions—In
January 2005, we completed the sale of the semisubmersible rig Sedco
600
for net
proceeds of $24.9 million and recognized a gain on the sale of $18.8 million.
A
deposit of $2.5 million was received in 2004 and was reflected as deferred
income in our consolidated balance sheet. At December 31, 2004, this asset
was
held for sale in the amount of $5.6 million and was included in other current
assets in our consolidated balance sheet. In June 2005, we sold the jackup
rig
Transocean
Jupiter
and a
land rig for net proceeds of $23.5 million and recognized a gain on these sales
of $14.0 million.
In
February 2006, we completed the sale of the drillship Peregrine
III
for net
proceeds of $78.7 million and expect to recognize a gain on the sale of
approximately $62 million. In December 2005, we received a deposit of $7.8
million, which was reflected as unearned income and included in other current
liabilities in our consolidated balance sheet. At December 31, 2005, this asset
was held for sale in the amount of $12.3 million and was included in other
current assets in our consolidated balance sheet.
During
the year ended December 31, 2005, we sold and disposed of certain other assets
for net proceeds of approximately $18.4 million and we recorded net losses
of
$3.8 million.
Sources
and Uses of Liquidity
Our
primary sources of liquidity are cash flows from operations, proceeds from
asset
sales, proceeds from issuance of ordinary shares upon the exercise of stock
options and warrants and existing cash balances. Our primary uses of cash are
debt repayments, repurchases of ordinary shares and capital expenditures.
We
expect
to use existing cash balances, internally generated cash flows 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 allow cash balances to increase and will continue
to consider the reduction of debt prior to scheduled maturities.
In
October 2005, our board of directors authorized the repurchase of up to $2
billion of our ordinary shares. The
ordinary shares may be repurchased from time to time in open market or private
transactions. Decisions to repurchase shares will be 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 the program from current and
future cash balances, but we could use debt to fund 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. At
February 28, 2006, after prior purchases, we still had authority to repurchase
$1.6 billion of our ordinary shares under the program.
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 cash flow will continue to
be
positive over the next year.
In
July
2005, we entered into a bank line of credit under a $500.0 million, five-year
revolving credit agreement. At February 28, 2006, $500.0 million remained
available under this revolving credit agreement. In conjunction with entering
into this facility, we terminated our $800.0 million, five-year revolving credit
agreement.
The
new
revolving credit agreement 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 credit agreement, not greater
than 60 percent. There is no interest coverage covenant associated with this
facility. Other provisions of the credit agreement 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 this facility. 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
merger, consolidation or reorganization transactions. A default under our public
debt could trigger a default under our credit line and cause us to lose access
to this facility.
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 February
28, 2006, $1.6 billion 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, downgrades of ratings of our debt,
industry conditions, general economic conditions, market conditions and market
perceptions of us and our industry.
Our
contractual obligations included in the table below are at face value (in
millions).
|
For
the years ending December 31,
|
||||||||||||||||
|
Total
|
2006
|
2007-2008
|
2009-2010
|
Thereafter
|
||||||||||||
|
Contractual
Obligations
|
||||||||||||||||
|
Debt
|
$
|
1,588.4
|
$
|
400.0
|
$
|
119.0
|
$
|
−
|
$
|
1,069.4
|
||||||
|
Operating
Leases
|
50.8
|
18.0
|
20.8
|
10.6
|
1.4
|
|||||||||||
|
Purchase
Obligations
|
241.5
|
176.4
|
65.1
|
−
|
−
|
|||||||||||
|
Defined
Benefit Pension Plans
|
2.7
|
2.7
|
−
|
−
|
−
|
|||||||||||
|
Total
Obligations
|
$
|
1,883.4
|
$
|
597.1
|
$
|
204.9
|
$
|
10.6
|
$
|
1,070.8
|
||||||
Bondholders
may, at their option, require us to repurchase the 1.5% Convertible Debentures
due 2021, the 7.45% Notes due 2027 and the Zero Coupon Convertible Debentures
due 2020 in May 2006, April 2007 and May 2008, 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 for redemption
at
any time. We may elect to call the 1.5% Convertible Debentures due 2021 for
redemption at any time after May 20, 2006. If we call the 1.5% Convertible
Debentures for redemption, 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.
If
our ordinary shares are trading above the respective debentures' conversion
prices and we elect to call any of the debentures, the holders may choose to
convert their debentures before the redemption date.
We
have
an obligation to make contributions in 2006 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, 2005, 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, 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
|
2006
|
2007-2008
|
2009-2010
|
Thereafter
|
||||||||||||
|
(In
millions)
|
||||||||||||||||
|
Other
Commercial Commitments
|
||||||||||||||||
|
Standby
Letters of Credit
|
$
|
313.8
|
$
|
242.0
|
$
|
20.1
|
$
|
34.9
|
$
|
16.8
|
||||||
|
Surety
Bonds
|
8.0
|
7.2
|
0.8
|
−
|
−
|
|||||||||||
|
Total
|
$
|
321.8
|
$
|
249.2
|
$
|
20.9
|
$
|
34.9
|
$
|
16.8
|
||||||
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.
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.
Gains
and
losses on foreign exchange derivative instruments that qualify and are
designated as accounting cash flow hedges are deferred as accumulated other
comprehensive income (loss) and recognized when the underlying foreign exchange
exposure is realized. Gains and losses on foreign exchange derivative
instruments that are not designated as cash flow hedges or no longer qualify
as
hedges or are terminated as such for accounting purposes are recognized
currently in other, net in our consolidated statements of operations based
on
the change in market value of the derivative instruments. At December 31, 2005,
we had no open foreign exchange derivative instruments.
From
time
to time, we may use interest rate swaps to manage the effect of interest rate
changes on our future interest rate expense. Interest rate swaps that we enter
into are designated as a hedge of future interest payments on our underlying
debt. The interest rate differential to be received or paid under the swaps
is
recognized over the lives of the swaps as an adjustment to interest expense.
If
an interest rate swap is terminated or no longer qualifies for hedge accounting,
the gain or loss is amortized over the remaining life of the underlying debt.
We
do not enter into interest rate swaps for speculative purposes.
In
June
2001, we entered into $700 million aggregate notional amount of interest rate
swaps as a fair value hedge against our 6.625% Notes due April 2011. In February
2002, we entered into $900 million aggregate notional amount of interest rate
swaps as a fair value hedge against our 6.75% Senior Notes due April 2005,
6.95%
Senior Notes due April 2008 and 9.5% Senior Notes due December 2008. The swaps
effectively converted the fixed interest rate on each of the four series of
notes 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 $173.5 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, 2005, such reduction amounted to $9.1 million. As a
result of the redemption of our 6.95% Senior Notes in March 2005, we recognized
$13.2 million of the unamortized fair value adjustment as a reduction to our
loss on redemption of debt. In addition, as a result of the repurchase of some
of our 6.625% Notes in July 2005, we recognized $62.0 million of the unamortized
fair value adjustment as an offset to our loss on repurchase of debt, which
resulted in a gain on this repurchase in 2005. The remaining balance to be
amortized at December 31, 2005 of $17.9 million relates to the 6.625% Notes
due
April 2011. See “—Significant Events.”
Income
and Expense Categories
Contract
Drilling Revenue—Our
contract drilling revenues are based primarily on dayrates received for our
drilling services and the number of operating days during the relevant periods.
The level of our contract drilling revenue depends on dayrates, which in turn
are primarily a function of industry supply and demand for drilling units in
the
market sectors in which we operate. During periods of high demand, our rigs
typically achieve higher utilization and dayrates than during periods of low
demand. Some of our drilling contracts also enable us to earn mobilization,
contract preparation, capital upgrade, bonus and demobilization revenue.
Mobilization, contract preparation and capital upgrade revenue earned on a
lump
sum basis is recognized on a straight-line basis over the original contract
term
and in relation to our drilling revenues, which are earned on a contractual
fixed dayrate basis. Bonus and demobilization revenue is recognized when
earned.
Other
Revenue—We
classify our revenues into two categories: (1) contract drilling revenues and
(2) other revenues, as we believe other revenue will become a more significant
component of our total revenues. Our other revenue represents client
reimbursable revenue, integrated services revenue and other miscellaneous
revenues. Under certain of our contracts, we provide well services in addition
to our normal drilling services through third party contractors. We refer to
these other services as integrated services.
Operating
and Maintenance Costs—Our
operating and maintenance costs represent all direct and indirect costs
associated with the operation and maintenance of our drilling rigs. Operating
and maintenance costs also include all costs related to local and regional
offices as well as all costs related to operations support, engineering support,
marketing and other similar costs. The principal elements of these costs are
direct and indirect labor and benefits, repair and maintenance, contract
preparation expenses, insurance, boat and helicopter rentals, professional
and
technical fees, freight costs, communications, customs duties, tool rentals
and
services, fuel and water, general taxes and licenses. Labor, repair and
maintenance costs, insurance premiums, personal injury losses and drilling
rig
casualty losses represent the most significant components of our operating
and
maintenance costs.
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. We currently maintain a per occurrence
insurance deductible of $10 million on our hull and machinery and personal
injury insurance and a $5 million deductible on third party property damage
insurance. We also currently have an additional aggregate deductible of $20
million per year that is applied to any hull and machinery occurrence until
it
has been exhausted. After the $20 million aggregate deductible is fully
exhausted, the hull and machinery deductible of $10 million per occurrence
continues to apply. We do not carry insurance for loss of revenue. As a result
of damages sustained during hurricanes Katrina and Rita to two of our
semisubmersible rigs, the
Deepwater Nautilus
and
Transocean
Marianas,
we
expect to fully exhaust our per occurrence and aggregate deductibles for the
policy period ending in April 2006 and expect to receive insurance proceeds
of
approximately $10 million (see “—Significant Events”). Most of our insurance
programs are up for renewal in the second quarter of 2006. Due to the large
hurricane related losses the offshore energy insurance industry has sustained,
we currently expect insurance premiums to increase dramatically for renewals.
We
may take significantly higher deductibles or self insure some or all of our
drilling fleet in order to mitigate such premium increases. If we take larger
deductibles or self insure some or all of our drilling fleet, our operating
and
maintenance costs could become more volatile.
Depreciation
Expense—Our
depreciation expense is based on capitalized costs and our estimates,
assumptions and judgments relative to useful lives and salvage values of our
assets. We compute depreciation using the straight-line method, generally after
allowing for salvage values.
General
and Administrative Expense—General
and administrative expense includes all costs related to our corporate
executives, directors, investor relations, corporate accounting and reporting,
and all corporate costs related to information technology, internal audit,
legal, tax, treasury, risk management and human resource functions.
Interest
Expense—Interest
expense consists of interest associated with our senior notes and other debt
and
related financing cost amortization. Interest expense is partially offset by
the
amortization of fair value adjustments resulting from various interest rate
swaps that were terminated during 2003. We expect the amortization of these
fair
value adjustments to continue over the life of the related debt instruments
(see
“—Derivative Instruments”).
Income
Taxes—Provisions
for income taxes are based on expected taxable income, statutory rates and
tax
planning opportunities available to us in the various jurisdictions in which
we
operate. Taxable income may differ from pre-tax income for financial accounting
purposes, particularly in countries with revenue-based taxes. There is no
expected relationship between the provision for income taxes and income before
income taxes because the countries in which we operate have different taxation
regimes. We provide a valuation allowance for deferred tax assets when it is
more likely than not that some or all of the benefit from the deferred tax
asset
will not be realized. See “—Critical Accounting Estimates.”
Results
of Operations
Historical
2005 compared to 2004
Following
is an analysis of our Transocean Drilling segment operating results, as well
as
an analysis of income and expense categories that we have not allocated to
our
segments. See “—Overview” for a definition of average daily revenue, revenue
earnings day and utilization.
Transocean
Drilling Segment
|
Years
eneded
December
31,
|
|||||||||||||
|
2005
|
2004
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except day amounts and percentages)
|
|||||||||||||
|
Revenue
earning days
|
26,224
|
23,427
|
2,797
|
12
|
%
|
||||||||
|
Utilization
|
79
|
%
|
68
|
%
|
N/A
|
16
|
%
|
||||||
|
Average
daily revenue
|
$
|
105,100
|
$
|
91,100
|
$
|
14,000
|
15
|
%
|
|||||
|
|
|||||||||||||
|
Contract
drilling revenues
|
$
|
2,757.1
|
$
|
2,134.1
|
$
|
623.0
|
29
|
%
|
|||||
|
Other
revenues
|
134.6
|
146.3
|
(11.7
|
)
|
(8
|
)%
|
|||||||
|
|
2,891.7
|
2,280.4
|
611.3
|
27
|
%
|
||||||||
|
Operating
and maintenance expense
|
(1,720.6
|
)
|
(1,432.6
|
)
|
(288.0
|
)
|
20
|
%
|
|||||
|
Depreciation
|
(405.8
|
)
|
(432.6
|
)
|
26.8
|
(6
|
)%
|
||||||
|
Gain
from disposal of assets, net
|
29.0
|
13.4
|
15.6
|
N/M
|
|||||||||
|
Operating
income before general and administrative expense
|
$
|
794.3
|
$
|
428.6
|
$
|
365.7
|
85
|
%
|
|||||
“N/A”
means not applicable
“N/M”
means not meaningful
The
$623.0 million increase in contract drilling revenues was primarily related
to
increased activity and utilization combined with lower revenues in 2004 of
approximately $38.0 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 $13.7 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 $21.0 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 $11.7 million due to
a
$22.7 million decrease in integrated services revenue, partially offset by
an
$11.0 million increase in client reimbursable revenue and compensation received
in 2005 relating to the 2004 labor strike in Norway of $4.9 million.
Operating
and maintenance expenses increased by $288.0 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 $39.2 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 stock
vestings with no comparable activity in 2004. Partially offsetting these
increases were expenses of $34.7 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 $29.0 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 $13.4 million related to the sale of the semisubmersible rig
Sedco
602
and the
sales and disposal of other assets.
Total
Company Results of Operations
|
Years
ended
December
31,
|
|||||||||||||
|
2005
|
2004
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except % change)
|
|||||||||||||
|
General
and Administrative Expense
|
$
|
74.8
|
$
|
67.0
|
$
|
7.8
|
12
|
%
|
|||||
|
Other
(Income) Expense, net
|
|||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
(10.1
|
)
|
(9.2
|
)
|
(0.9
|
)
|
10
|
%
|
|||||
|
Interest
income
|
(19.6
|
)
|
(9.3
|
)
|
(10.3
|
)
|
N/M
|
||||||
|
Interest
expense
|
111.2
|
171.7
|
(60.5
|
)
|
35
|
%
|
|||||||
|
Gain
from TODCO Stock Sales
|
(165.0
|
)
|
(308.8
|
)
|
(143.8
|
)
|
47
|
%
|
|||||
|
Non-cash
TODCO tax sharing agreement charge
|
-
|
167.1
|
(167.1
|
)
|
N/M
|
||||||||
|
Loss
on retirement of debt
|
7.3
|
76.5
|
(69.2
|
)
|
90
|
%
|
|||||||
|
Other,
net
|
(6.7
|
)
|
(0.4
|
)
|
(6.3
|
)
|
N/M
|
||||||
|
Income
Tax Expense
|
86.8
|
91.3
|
4.5
|
5
|
%
|
||||||||
|
Minority
Interest
|
-
|
(3.2
|
)
|
3.2
|
N/M
|
||||||||
The
increase in general and administrative expense was primarily attributable to
increases of approximately $6.0 million in accounting, legal and professional
fees as well as $4.1 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 $3.3
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 $8.4 million.
Approximately
$56.0 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 $4.0 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 $143.8 million during 2005 compared to 2004
(see “―Significant
Events”).
During
2004, we recognized a $167.1 million non-cash charge related to contingent
amounts due from TODCO under a tax sharing agreement between us and TODCO (see
“―Historical
2004 compared to 2003-Significant Events”).
During
2005, we recognized losses of $7.3 million related to the early redemption
and
repurchase of $782.2 million aggregate principal amount of our debt (see
“―Significant
Events”). During 2004, we recognized losses of $76.5 million related to the
early retirements of $774.8 million aggregate principal amount of our debt
(see
“―Historical
2004 compared to 2003-Significant Events”).
The
$6.3
million favorable change in other, net primarily relates to $11.4 million of
income recognized under the tax sharing agreement with TODCO (see “―Significant
Events”), 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 $14.1 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 $16.8 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 $11.6 million, including a provision for a valuation allowance
of
approximately $32.4 million related to the TODCO IPO.
The
decrease in minority interest was primarily attributable to the deconsolidation
of TODCO.
TODCO
Segment
The
results discussed below for the TODCO segment are through December 16, 2004
as a
result of the TODCO Stock Sales and the deconsolidation of TODCO. See
“—Significant Events.” See “—Overview” for a definition of average daily
revenue, revenue earning days and utilization.
|
Years
ended
December
31,
|
|||||||||||||
|
2005
|
2004
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except day amounts and percentages)
|
|||||||||||||
|
Revenue
earning days
|
−
|
10,476
|
(10,476
|
)
|
N/M
|
||||||||
|
Utilization
|
−
|
43
|
%
|
N/A
|
N/M
|
||||||||
|
Average
daily revenue
|
−
|
$
|
26,900
|
$
|
(26,900
|
)
|
N/M
|
||||||
|
Contract
drilling revenues
|
−
|
$
|
282.3
|
$
|
(282.3
|
)
|
N/M
|
||||||
|
Other
revenues
|
−
|
51.2
|
(51.2
|
)
|
N/M
|
||||||||
|
|
333.5
|
(333.5
|
)
|
N/M
|
|||||||||
|
Operating
and maintenance expense
|
−
|
(281.0
|
)
|
281.0
|
N/M
|
||||||||
|
Depreciation
|
−
|
(92.0
|
)
|
92.0
|
N/M
|
||||||||
|
Gain
from disposal of assets, net
|
−
|
5.8
|
(5.8
|
)
|
N/M
|
||||||||
|
Operating
loss before general and administrative expense
|
−
|
$
|
(33.7
|
)
|
$
|
33.7
|
N/M
|
||||||
“N/A”
means not applicable
“N/M”
means not meaningful
Historical
2004 compared to 2003
Overview
Our
revenue and operating and maintenance expenses for the year ended December
31,
2004 increased from the prior year due to the current year effect of including
the operations of the drillships Deepwater
Pathfinder and
Deepwater Frontier
as a
result of the 2003 acquisitions of the ownership interests in the Deepwater
Drilling L.L.C. (“DD LLC”) and Deepwater Drilling II L.L.C. (“DDII LLC”) joint
ventures and the subsequent payoff of the synthetic lease financing arrangements
in late December 2003, as well as from increased integrated services provided
to
our clients in 2004. In 2003, the Discoverer
Enterprise
riser
incident, an electrical fire on the Peregrine
I
and a
labor strike and restructuring of a benefit plan in Nigeria negatively impacted
revenues and operating and maintenance expense. In 2004, the Discoverer
Enterprise
operating and maintenance expense was partially reduced by an insurance
settlement related to the riser incident (see
“—Significant Events”). Adding to the increase in operating and maintenance
expense were repairs resulting from a fire on the jackup rig Trident
20
and a
well control incident on the semisubmersible rig Jim
Cunningham that
occurred in the third quarter of 2004
(see
“―Significant Events”),
while a
well control incident on TODCO’s inland barge Rig
62
and a
fire on TODCO’s inland barge Rig
20
negatively impacted operating and maintenance expense in 2003. Revenues were
negatively impacted by suspended operations due to the strike in
Norway
(see
“―Significant Events”),
the
fire on the Trident
20
and the
well control incident on the semisubmersible rig Jim
Cunningham,
all of
which occurred during the third quarter of 2004. Our year ended December 31,
2004 financial results included non-cash charges pertaining to losses on
retirement of debt partially offset by the recognition of a gain on the sale
of
a semisubmersible rig. We also recognized gains on the 2004 Offerings, which
were partially offset by a tax valuation allowance adjustment and stock option
expense recorded in connection with the TODCO IPO, as well as a non-cash charge
related to contingent amounts due from TODCO under the tax sharing agreement
between us and TODCO (see “—Significant Events”). Cash decreased during the year
ended December 31, 2004 primarily as a result of the early retirements of debt
instruments resulting from our continued focus on debt reduction, partially
offset by proceeds received from the 2004 Offerings and cash provided by
operating activities.
Significant
Events
Transocean
Drilling Segment
Operational
Incidents—In
May
2003, a drilling riser separated on our deepwater drillship Discoverer
Enterprise
and the
rig temporarily suspended drilling operations for our customer. The rig resumed
operations in July 2003 and we resolved a disagreement with our customer
regarding the incident in early 2004, which had no significant effect on our
results of operations. In June 2004, we finalized discussions with our insurers
relating to an insurance claim for a portion of our losses stemming from this
incident and received an insurance settlement during 2004, the majority of
which
was received in June 2004, which had a favorable effect on pre-tax earnings
of
$13.4 million.
In
July
2004, members of the OFS, one of three unions representing offshore workers
in
Norway, called a strike on our semisubmersible units operating in the country.
OFS called the strike after it was unable to reach an agreement with the
Norwegian Shipowners Association, which represents rig owners in Norway. The
strike affected the semisubmersible rigs Polar
Pioneer,
Transocean
Searcher
and
Transocean
Leader.
The
strike ended in late October 2004 following government intervention, and the
Transocean
Searcher
and
Transocean
Leader
resumed
operations in the Norwegian sector of the North Sea in November 2004. The
Polar
Pioneer
commenced operations in December 2004 following the completion of planned survey
and upgrade work. Operating income would have been an estimated $9.0 million
higher absent the labor strike.
In
July
2004, the jackup rig Trident
20
suffered
damage resulting from a fire in the rig's engine room while operating offshore
Turkmenistan in the Caspian Sea. The rig, which was under a three-well contract,
was out of service a majority of the third and fourth quarters and returned
to
work in December 2004. Total repair, crew and other costs resulted in
approximately $12.5 million of additional operating and maintenance expense.
Operating income would have been an estimated $26.4 million higher absent the
incident.
In
August
2004, the semisubmersible rig Jim
Cunningham
experienced a well control incident that resulted in a fire while operating
offshore Egypt. The rig was out of service all of the fourth quarter and
returned to work in February 2005. Repair, crew and other costs totaled
approximately $12.0 million of which approximately $7.0 was incurred in 2004.
Operating income would have been an estimated $14.4 million higher absent the
incident.
Asset
Dispositions—In
March
2004, we entered into an agreement to sell a semisubmersible rig, the
Sedco
600,
for net
proceeds of approximately $25.0 million. At December 31, 2004, the rig was
classified as an asset held for sale and included in other current assets in
our
consolidated balance sheet. We completed the sale of the rig in January 2005
for
net proceeds of $24.9 million and recognized a gain on the sale of $18.8 million
in the first quarter of 2005.
In
June
2004, we completed the sale of a semisubmersible rig, the Sedco
602, for
net
proceeds of approximately $28.0 million and recognized a gain on the sale of
$21.7 million.
Debt
Redemptions and Repurchases
In
March
2004, we completed the redemption of our $289.8 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 $370.3 million, plus accrued and unpaid interest. We recognized
a
loss on the redemption of debt of $28.1 million, which reflected adjustments
for
fair value of the debt at the date of the merger with R&B Falcon and the
unamortized fair value adjustment on a previously terminated interest rate
swap.
We funded the redemption with existing cash balances, which included proceeds
from the TODCO IPO.
In
October 2004, we redeemed our $342.3 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 $349.5 million, plus accrued and unpaid interest. We recognized a
loss
on the redemption of $3.3 million, which reflected adjustments for fair value
of
the debt at the date of the R&B Falcon merger and the unamortized fair value
adjustment on a previously terminated interest rate swap. We funded the
redemption with existing cash on hand, which included proceeds from the
September 2004 Offering.
In
December 2004, we acquired, pursuant to a tender offer, a total of $142.7
million, or 71.3 percent, aggregate principal amount of our 8% Debentures due
April 2027 at 130.449 percent of face value, or $186.1 million, plus accrued
and
unpaid interest. We recognized a loss on the repurchase of $45.1 million. We
funded the repurchase with existing cash balances.
In
December 2004, the previously discussed deconsolidation of TODCO resulted in
the
elimination from our consolidated balance sheets of TODCO’s 6.75% Senior Notes
due April 2005, 6.95% Senior Notes due April 2008, 9.5% Senior Notes due
December 2008 and 7.375% Senior Notes due April 2018, which had an aggregate
principal amount outstanding of $7.7 million, $2.2 million, $10.2 million and
$3.5 million, respectively.
TODCO
Tax Sharing Agreement Charge
Under
the
tax sharing agreement entered into between us and TODCO in connection with
the
TODCO IPO, we are entitled to receive from TODCO payment for most of the tax
benefits generated prior to the TODCO IPO that TODCO utilizes subsequent to
the
TODCO IPO. As long as TODCO was our consolidated subsidiary, we followed the
provisions of SFAS 109, which allowed us to evaluate the recoverability of
the
deferred tax assets associated with the tax sharing agreement considering the
deferred tax liabilities of TODCO. We recorded a valuation allowance for the
excess of these deferred tax assets over the deferred tax liabilities of TODCO,
also taking into account prudent and feasible tax planning strategies as
required by SFAS 109. Because we no longer own a majority voting interest in
TODCO, we no longer include TODCO as a consolidated subsidiary in our financial
statements, and we are no longer able to apply the provisions of SFAS 109 in
accounting for the utilization of these deferred tax assets. As a result, we
recorded a non-cash charge of $167.1 million in the fourth quarter of 2004
related to contingent amounts due from TODCO under the tax sharing agreement.
In
future years, as TODCO generates income and utilizes its pre-TODCO IPO tax
assets, TODCO is required to pay us for the benefits received in accordance
with
the provisions of the tax sharing agreement. We will recognize those amounts
as
other income as those amounts are realized, which is generally based on when
TODCO files its annual tax returns. See “—Outlook-Tax Matters.”
TODCO
Segment
Delta
Towing—As
a
result of the adoption of FASB Interpretation (“FIN”) 46 and a determination
that TODCO was the primary beneficiary for accounting purposes of TODCO’s joint
venture, Delta Towing Holdings, LLC (“Delta Towing”), TODCO consolidated Delta
Towing at December 31, 2003. Due to the consolidation of Delta Towing, other
revenues and operating and maintenance expense increased during the year ended
December 31, 2004 by $29.3 million and $24.5 million, respectively.
TODCO
Stock Sales
In
February 2004, we completed the TODCO IPO in which we sold 13.8 million shares
of TODCO class A common stock representing 23 percent of TODCO’s total
outstanding shares, at $12.00 per share. We received net proceeds of $155.7
million from the TODCO IPO and recognized a gain of $39.4 million in the first
quarter of 2004, and represented the excess of net proceeds received over the
net book value of the TODCO shares sold in the TODCO IPO. TODCO was formerly
known as R&B Falcon Corporation (“R&B Falcon”). Before the closing of
the TODCO IPO, TODCO transferred to us all assets and subsidiaries unrelated
to
TODCO’s business (see "Item 1. Business"). R&B Falcon’s business was
previously considerably broader than TODCO’s ongoing business.
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, we established
an
initial valuation allowance in the first quarter of 2004 of approximately $31.0
million 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
the year to reflect changes in our estimate of the ultimate amount of TODCO’s
deferred tax assets.
In
conjunction with the closing of the TODCO IPO, TODCO granted restricted stock
and stock options to certain of its employees under its long-term incentive
plan
and certain of these awards vested at the time of grant. In accordance with
the
provisions of SFAS 123, Accounting
for Stock-Based Compensation,
TODCO
recognized compensation expense of $5.6 million in the first quarter of 2004
as
a result of the immediate vesting of certain awards. TODCO amortized $4.6
million to compensation expense subsequent to the TODCO IPO and prior to our
deconsolidation of TODCO from our consolidated financial statements at December
17, 2004. 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, these options were modified, 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 $1.5 million additional
compensation expense in the first quarter of 2004.
In
September 2004, we completed the September 2004 Offering, in which we sold
17.9
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 $269.9 million from this offering and recognized a gain of $129.4 million
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 this 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 $258.0 million from this offering and recognized a gain of $140.0 million
in
the fourth quarter of 2004, which represented the excess of net proceeds
received over the net book value of the TODCO shares sold in this offering.
In
connection with this offering, we converted all of our remaining TODCO class
B
common stock not sold in this offering into shares of class A common stock.
Each
share of our TODCO class B common stock had five votes per share compared to
one
vote per share of the class A common stock. As a result of the conversion,
our
voting interest in TODCO is proportionate to our ownership interest.
At
December 31, 2004, we held a 22 percent interest in TODCO, represented by 13.3
million shares of class A common stock. 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 reflected as minority interest in our consolidated
statements of operations and balance sheets. We deconsolidated TODCO from our
consolidated statements of operations and balance sheets effective December
17,
2004 and subsequently accounted for our investment in TODCO under the equity
method of accounting.
Following
is an analysis of our Transocean Drilling segment and TODCO segment operating
results, as well as an analysis of income and expense categories that we have
not allocated to our segments. See “—Overview” for a definition of average daily
revenue, revenue earnings day and utilization.
Transocean
Drilling Segment
|
Years
ended
December
31,
|
|||||||||||||
|
2004
|
2003
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except day amounts and percentages)
|
|||||||||||||
|
Revenue
earning days
|
23,427
|
23,712
|
(285
|
)
|
(1
|
)%
|
|||||||
|
Utilization
|
68
|
%
|
69
|
%
|
N/A
|
(1
|
)%
|
||||||
|
Average
daily revenue
|
$
|
91,100
|
$
|
89,400
|
$
|
1,700
|
2
|
%
|
|||||
|
Contract
drilling revenues
|
$
|
2,134.1
|
$
|
2,118.7
|
$
|
15.4
|
1
|
%
|
|||||
|
Other
revenues
|
146.3
|
88.0
|
58.3
|
66
|
%
|
||||||||
|
2,280.4
|
2,206.7
|
73.7
|
3
|
%
|
|||||||||
|
Operating
and maintenance expense
|
(1,432.6
|
)
|
(1,357.3
|
)
|
(75.3
|
)
|
6
|
%
|
|||||
|
Depreciation
|
(432.6
|
)
|
(416.0
|
)
|
(16.6
|
)
|
4
|
%
|
|||||
|
Impairment
loss on long-lived assets
|
−
|
(5.2
|
)
|
5.2
|
N/M
|
||||||||
|
Gain
(loss) from disposal of assets, net
|
13.4
|
(5.7
|
)
|
19.1
|
N/M
|
||||||||
|
Operating
income before general and administrative expense
|
$
|
428.6
|
$
|
422.5
|
$
|
6.1
|
1
|
%
|
|||||
“N/A”
means not applicable
“N/M”
means not meaningful
This
segment’s contract drilling revenues increased by approximately $100.0 million
as a result of revenues for the full year in 2004 from the Discoverer
Enterprise,
which
was inactive for the latter part of the second quarter of 2003 due to a riser
separation incident, and revenues from the Deepwater
Frontier and
the
Deepwater
Pathfinder
resulting from the consolidation of DDII LLC and DD LLC, which occurred late
in
the second and fourth quarters of 2003, respectively. Additionally, a labor
strike in Nigeria and the Peregrine
I
electrical incident during the second quarter of 2003 negatively impacted
revenues during 2003 with no comparable incidents in 2004, which resulted in
a
positive impact of approximately $17.0 million in 2004 over the prior year.
Partially offsetting these increases were decreases of approximately $38.0
million as a result of the strike in Norway and the Trident
20
and
Jim
Cunningham
incidents in the third quarter of 2004. Contract drilling revenues were also
negatively impacted by approximately $59.0 million due to a slight decline
in
utilization and a semisubmersible rig sold in 2004.
Other
revenues for the year ended December 31, 2004 increased $58.3 million primarily
due to a $68.0 million increase in integrated services revenue, partially offset
by a decrease of $11.8 million from client reimbursable revenue and the absence
of revenue from management fees as a result of the consolidation of DDII LLC
and
DD LLC late in the second and fourth quarters, respectively, of 2003.
This
segment’s operating and maintenance expenses increased by approximately $83.0
million primarily from costs associated with higher personal injury claim
losses, integrated services, additional expenses related to the Deepwater
Pathfinder
as a
result of the consolidation of DD LLC late in the fourth quarter of 2003 and
the
Trident
20
and
Jim
Cunningham
incidents in 2004. Expenses also increased approximately $25.0 million due
to
increased expenses primarily related to activity and the reactivation of rigs,
a
loss on retirement of rig equipment and higher provisions for local tax matters
in 2004. Additional increases of $8.0 million resulted from favorable litigation
and turnkey settlements during 2003 with no comparable activity during 2004.
Partially offsetting these increases were decreased operating and maintenance
expenses of approximately $42.0 million primarily related to the settlement
of
the Discoverer
Enterprise
May 2003
riser incident, the favorable insurance settlement related to a prior year
Peregrine
I
riser
incident, the favorable settlement of a turnkey dispute during 2004 and costs
incurred in 2003 related to the restructuring of the Nigeria defined benefit
plan and the Peregrine
I
electrical incident with no comparable activity in 2004.
The
increase in this segment’s depreciation expense resulted primarily from $19.5
million of additional depreciation expense related to the Deepwater
Frontier
and
Deepwater
Pathfinder
as a
result of the late December 2003 payoff of the synthetic lease financing
arrangements and the purchase of tensioner system equipment for the
Discoverer Enterprise.
An
additional increase of approximately $2.0 million resulted from depreciation
on
other asset additions, net of retirements. These increases were partially offset
by a $4.7 million decrease resulting from extending the useful lives of four
rigs from 30 to 32 years to 35 years in the fourth quarter of 2004 and $0.6
million resulting from rigs sold during and subsequent to 2003.
During
2003, we recorded non-cash impairment charges in this segment of $5.2 million
associated with the removal of two rigs from drilling service and the value
assigned to leases on oil and gas properties that we intended to discontinue.
The determination of fair market value was based on an offer from a potential
buyer, in the case of the two rigs, and management’s assessment of fair value,
in the case of the leases on oil and gas properties, where third party
valuations were not available.
During
2004, this segment recognized net gains of $13.4 million related to the sales
of
the semisubmersible rig Sedco
602
and the
sales and disposal of other assets. During the year ended December 31, 2003,
this segment recognized net losses of $5.7 million related to the sales and
disposal of other assets, partially offset by gains related to the sale of
the
jackup rig RBF
160,
the
sale of the Searex
15
and the
settlement of an insurance claim.
Total
Company Results of Operations
|
Years
ended
December
31,
|
|||||||||||||
|
2004
|
2003
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except % change)
|
|||||||||||||
|
General
and Administrative Expense
|
$
|
67.0
|
$
|
65.3
|
$
|
1.7
|
3
|
%
|
|||||
|
Other
(Income) Expense, net
|
|||||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
(9.2
|
)
|
(5.1
|
)
|
(4.1
|
)
|
80
|
%
|
|||||
|
Interest
income
|
(9.3
|
)
|
(18.8
|
)
|
9.5
|
(51
|
)%
|
||||||
|
Interest
expense
|
171.7
|
202.0
|
(30.3
|
)
|
(15
|
)%
|
|||||||
|
Gain
from TODCO Stock Sales
|
(308.8
|
)
|
-
|
(308.8
|
)
|
N/M
|
|||||||
|
Non-cash
TODCO tax sharing agreement charge
|
167.1
|
-
|
167.1
|
N/M
|
|||||||||
|
Loss
on retirement of debt
|
76.5
|
15.7
|
60.8
|
N/M
|
|||||||||
|
Impairment
loss on note receivable from related party
|
-
|
21.3
|
(21.3
|
)
|
N/M
|
||||||||
|
Other,
net
|
(0.4
|
)
|
3.0
|
(3.4
|
)
|
N/M
|
|||||||
|
Income
Tax Expense
|
91.3
|
3.0
|
88.3
|
N/M
|
|||||||||
|
Minority
Interest
|
(3.2
|
)
|
0.2
|
(3.4
|
)
|
N/M
|
|||||||
|
Cumulative
Effect of a Change in Accounting Principle
|
-
|
(0.8
|
)
|
0.8
|
N/M
|
||||||||
“N/M”
means not meaningful
The
increase in general and administrative expense was attributable to increases
of
approximately $10.0 million in stock compensation expense, primarily related
to
the retirement of an executive officer, and professional fees related to
compliance with the Sarbanes-Oxley Act effective for 2004. The increase was
partially offset by decreases attributable to the recognition in 2003 of $8.8
million of expenses relating to the TODCO IPO.
Equity
in
earnings of unconsolidated affiliates increased $5.8 million primarily related
to our 50 percent share of earnings from Overseas Drilling Limited (“ODL”),
which owns the drillship Joides
Resolution, combined
with $6.5 million resulting from the absence of our share of losses from Delta
Towing in 2003 due to TODCO’s consolidation of the joint venture at December 31,
2003 as a result of the adoption of FIN 46. Offsetting these increases was
the
absence of equity in earnings of $8.0 million related to our consolidation
of DD
LLC and DDII LLC in 2003, which resulted from the completion of the buyout
of
ConocoPhillips’ share of the joint ventures.
The
decrease in interest income was primarily related to a decrease in average
cash
balances for 2004 compared to 2003 as cash was utilized for debt reduction
and
capital expenditures, which resulted in a reduction of interest income of $5.9
million. Additional decreases resulted from the absence in 2004 of $3.4 million
of interest earned in 2003 on the notes receivable from Delta Towing, which
was
consolidated by TODCO at December 31, 2003 as a result of the adoption of FIN
46.
The
decrease in interest expense was primarily attributable to reductions in
interest expense of $42.9 million associated with debt that was redeemed,
retired or repurchased during or subsequent to 2003. Partially offsetting these
decreases was the termination of our fixed to floating interest rate swaps
in
the first quarter of 2003, which resulted in a net increase in interest expense
of $4.4 million (see “—Derivative Instruments”) and primarily from borrowings
under revolving credit agreements late in 2003 and in 2004, which resulted
in an
increase in interest expense of $5.8 million. In addition, we received a refund
of interest from a taxing authority that resulted in a reduction of interest
expense of $1.1 million in 2003, with no comparable activity for the same period
in 2004.
During
2004, we recognized a $308.8 million gain from the TODCO Stock Sales (see
“—Significant Events”).
During
2004, we recognized a $167.1 million non-cash charge related to contingent
amounts due from TODCO under a tax sharing agreement between us and TODCO (see
“—Significant Events”).
During
2004, we recognized a $76.5 million loss related to the early retirements of
$774.8 million aggregate principal amount of our debt (see “—Significant
Events”). During 2003, we recognized a $15.7 million loss related to the early
retirements of $888.6 million aggregate principal amount of our debt.
During
2003, we recognized a $21.3 million impairment loss on TODCO’s notes receivable
from Delta Towing.
We
recognized a $3.9 million favorable change in other, net relating to the effect
of foreign currency exchange rate changes on our monetary assets and liabilities
denominated in non-U.S. currencies, partially offset by proceeds received from
the sale of a patent in 2003 with no comparable activity for the same period
in
2004.
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. Income tax expense for the year ended December 31, 2004 was $88.3 million
higher than in the same period in 2003. Excluding other partially offsetting
adjustments to our overall valuation allowance, which were included in the
computation of the tax rate, the year ended December 31, 2004 included a
provision for a valuation allowance of approximately $32 million related to
the
TODCO IPO (see “—Significant Events”). Income tax expense was reduced by
approximately $9 million, which related to changes in estimates of prior year
taxes, and by approximately $13 million related to our U.K. net operating loss
carryforwards and related valuation allowance. The year ended December 31,
2003
included the impact of an approximate $15 million foreign tax benefit attributed
to a favorable resolution of a non-U.S. income tax liability and income tax
benefits of approximately $13 million resulting from non-cash impairments and
loss on debt retirements. The higher income tax expense in 2004 compared to
2003
resulted in an annual effective tax rate adjusted for various discrete items
that was 20 percentage points higher for the year ended December 31, 2004
compared to the same period in 2003.
The
increase in minority interest was primarily attributable to the minority
interest owners’ share of TODCO resulting from the TODCO Stock Sales in 2004
(see “—Significant Events”).
During
2003, we recognized a $0.8 million gain as a cumulative effect of a change
in
accounting principle related to TODCO’s consolidation of Delta Towing at
December 31, 2003 as a result of the early adoption of the FIN 46.
TODCO
Segment
The
results discussed below for the TODCO segment are through December 16, 2004
as a
result of the TODCO Stock Sales and the deconsolidation of TODCO. See
“—Significant Events.” See “—Overview” for a definition of average daily
revenue, revenue earnings day and utilization.
|
Years
ended
December
31,
|
|||||||||||||
|
2004
|
2003
|
Change
|
%
Change
|
||||||||||
|
(In
millions, except day amounts and percentages)
|
|||||||||||||
|
Revenue
earning days (a)
|
10,476
|
10,953
|
(477
|
)
|
(4
|
)%
|
|||||||
|
Utilization
(a)
|
43
|
%
|
41
|
%
|
N/A
|
5
|
%
|
||||||
|
Average
daily revenue (a)
|
$
|
26,900
|
$
|
19,200
|
$
|
7,700
|
40
|
%
|
|||||
|
Contract
drilling revenues
|
$
|
282.3
|
$
|
209.8
|
$
|
72.5
|
35
|
%
|
|||||
|
Other
revenues
|
51.2
|
17.8
|
33.4
|
N/M
|
|||||||||
|
333.5
|
227.6
|
105.9
|
47
|
%
|
|||||||||
|
Operating
and maintenance expense
|
(281.0
|
)
|
(233.9
|
)
|
(47.1
|
)
|
20
|
%
|
|||||
|
Depreciation
|
(92.0
|
)
|
(92.2
|
)
|
0.2
|
N/M
|
|||||||
|
Impairment
loss on long-lived assets
|
−
|
(11.3
|
)
|
11.3
|
N/M
|
||||||||
|
Gain
(loss) from disposal of assets, net
|
5.8
|
(7.7
|
)
|
13.5
|
N/M
|
||||||||
|
Operating
loss before general and administrative expense
|
$
|
(33.7
|
)
|
$
|
(117.5
|
)
|
$
|
83.8
|
71
|
%
|
|||
“N/A”
means not applicable
“N/M”
means not meaningful
|
(a)
|
TODCO
was deconsolidated effective December 17, 2004. Statistics for the
TODCO
segment are through December 16, 2004 for the year ended December
31,
2004.
|
This
segment’s contract drilling revenues increased by $72.5 million due to an
increase in average daily revenue and utilization, which included the operations
of a jackup rig in Venezuela and two jackup rigs in Mexico after the rigs were
transferred from the Gulf of Mexico during the fourth quarter of
2003.
Other
revenues for the year ended December 31, 2004 increased $33.4 million due
primarily to the consolidation of Delta Towing at December 31, 2003 and
increased client reimbursable revenue.
The
increase in this segment’s operating and maintenance expense was primarily due
to $24.5 million of costs associated with the consolidation of Delta Towing
at
December 31, 2003, $14.7 million of operating and maintenance expense related
to
the operations of a jackup rig in Venezuela and two jackup rigs in Mexico after
the rigs were transferred from the Gulf of Mexico and $11.8 million of higher
compensation expense related to stock option and restricted stock grants in
connection with the TODCO IPO. Partially offsetting the above increases were
decreases primarily due to approximately $11.0 million of costs associated
with
the fire incident on inland barge Rig
20
and the
well control incident on inland barge Rig
62
during
2003 with no comparable activity during 2004.
During
2003, we recorded non-cash impairment charges in this segment of $11.3 million
associated with the removal of five jackup rigs from drilling service and the
write down in the value of an investment in a joint venture to fair value.
The
determination of fair market value was based on third party valuations, in
the
case of the jackup rigs, and management’s assessment of fair value, in the case
of the investment in a joint venture, where third party valuations were not
available.
During
2004, this segment recognized net gains of $5.8 million primarily related
to the sale of marine support vessels by Delta Towing, as well as the sales
and
disposal of other assets and the settlement of an October 2000 insurance
claim. During 2003, this segment recognized net losses of $7.7 million primarily
related to loss on retirements.
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, 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 registered in Barbados, 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.
As
the
result of changes in our estimates of certain tax exposures upon the settlement
of income tax audits in various tax jurisdictions during 2005, we recognized
a
decrease of $43.0 million in goodwill related to tax liabilities arising prior
to our December 31, 1999 merger with Sedco Forex Holdings Limited (“Sedco
Forex”) and an income tax benefit of $48.7 million related to post-acquisition
tax liabilities.
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, 2003, 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 $181.8 million.
We decreased the valuation allowance to $48.5 million and $115.3 million, as
of
December 31, 2005 and 2004, respectively. 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 2005 compared to
2004” and “Results of Operations—Historical 2004 compared to 2003.” 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.
Goodwill
impairment—We
perform a test for impairment of our goodwill annually as of October 1 as
prescribed by SFAS 142, Goodwill
and Other Intangible Assets.
Because
our business is cyclical in nature, goodwill could be significantly impaired
depending on when the assessment is performed in the business cycle. The fair
value of our reporting units is based on a blend of estimated discounted cash
flows, publicly traded company multiples and acquisition multiples. Estimated
discounted cash flows are based on projected utilization and dayrates. Publicly
traded company multiples and acquisition multiples are derived from information
on traded shares and analysis of recent acquisitions in the marketplace,
respectively, for companies with operations similar to ours. Changes in the
assumptions used in the fair value calculation could result in an estimated
reporting unit fair value that is below the carrying value, which may give
rise
to an impairment of goodwill. In addition to the annual review, we also test
for
impairment should an event occur or circumstances change that may indicate
a
reduction in the fair value of a reporting unit below its carrying value. As
a
result of these tests for impairment, we had no impairment of goodwill for
the
years ended December 31, 2005, 2004 and 2003.
In
addition, as long as we continue to operate in one reporting segment, we intend
to use market capitalization as the basis for the measurement of the fair value
of our one reporting segment as we believe it is representative of, and the
best
evidence for, the fair value of the reporting unit as a whole.
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 also 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 $38.2 million while a one year decrease
would cause an increase in our annual depreciation expense of approximately
$51.5 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 SFAS 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 87, Employers’
Accounting for Pensions,
and
SFAS 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 $2.0 million. For each one-half
percentage point the discount rate is lowered, pension expense would increase
by
approximately $3.6 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.
Retirement
Plans and Other Postemployment Benefits
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 “Nigeria Plan” and the
“Egypt Plan”) that provide retirement and severance benefits for certain of our
Nigerian and Egyptian employees. The benefits we provide under defined benefit
pension plans are comprised of the U.S. Plans, the Norway Plans, the Nigeria
Plan and the Egypt Plan (collectively, the “Transocean Plans”).
|
Retirement
Plan
|
Supplemental
Retirement
Plan
|
Frozen
Plans
|
Subtotal-
U.S.
Plans
|
Norway
Plans
|
Nigeria
Plan
|
Egypt
Plan
|
Total
Transocean
Plans
|
|||||||||||||||||||||
|
(in
millions)
|
||||||||||||||||||||||||||||
|
Accumulated
Benefit Obligation
|
||||||||||||||||||||||||||||
|
At
December 31, 2005
|
$
|
131.4
|
$
|
4.1
|
$
|
103.3
|
$
|
238.8
|
$
|
38.4
|
$
|
0.7
|
$
|
0.7
|
$
|
278.6
|
||||||||||||
|
At
December 31, 2004
|
115.8
|
5.9
|
109.1
|
230.8
|
38.8
|
0.3
|
-
|
269.9
|
||||||||||||||||||||
|
Projected
Benefit Obligation
|
||||||||||||||||||||||||||||
|
At
December 31, 2005
|
$
|
173.6
|
$
|
6.8
|
$
|
103.3
|
$
|
283.7
|
$
|
49.6
|
$
|
1.0
|
$
|
1.6
|
$
|
335.9
|
||||||||||||
|
At
December 31, 2004
|
154.8
|
8.9
|
109.1
|
272.8
|
53.0
|
0.4
|
-
|
326.2
|
||||||||||||||||||||
|
Fair
Value of Plan Assets
|
||||||||||||||||||||||||||||
|
At
December 31, 2005
|
$
|
111.2
|
$
|
-
|
$
|
93.0
|
$
|
204.2
|
$
|
37.3
|
$
|
-
|
$
|
-
|
$
|
241.5
|
||||||||||||
|
At
December 31, 2004
|
107.3
|
-
|
94.4
|
201.7
|
34.9
|
-
|
-
|
236.6
|
||||||||||||||||||||
|
Funded
Status
|
||||||||||||||||||||||||||||
|
At
December 31, 2005
|
$
|
(62.5
|
)
|
$
|
(6.7
|
)
|
$
|
(10.3
|
)
|
$
|
(79.5
|
)
|
$
|
(12.3
|
)
|
$
|
(1.0
|
)
|
$
|
(1.6
|
)
|
$
|
(94.4
|
)
|
||||
|
At
December 31, 2004
|
(47.5
|
)
|
(8.9
|
)
|
(14.7
|
)
|
(71.1
|
)
|
(18.1
|
)
|
(0.4
|
)
|
-
|
(89.6
|
)
|
|||||||||||||
|
Net
Periodic Benefit Cost (Income)
|
||||||||||||||||||||||||||||
|
Year
Ending December 31, 2005
|
$
|
14.1
|
$
|
3.2
|
$
|
(0.8
|
)
|
$
|
16.5
|
$
|
5.1
|
$
|
0.3
|
$
|
0.3
|
$
|
22.2
|
(a)
|
|
|||||||||
|
Year
Ending December 31, 2004
|
11.3
|
1.7
|
(0.7
|
)
|
12.3
|
4.5
|
0.2
|
-
|
17.0
|
(a)
|
|
|||||||||||||||||
|
Change
in Accumulated Other Comprehensive Income
|
|
|||||||||||||||||||||||||||
|
Year
Ending December 31, 2005
|
$
|
-
|
$
|
(2.8
|
)
|
$
|
(3.3
|
)
|
$
|
(6.1
|
)
|
$
|
-
|
$
|
-
|
$
|
-
|
$
|
(6.1
|
)
|
|
|||||||
|
Year
Ending December 31, 2004
|
-
|
1.5
|
4.8
|
6.3
|
-
|
-
|
-
|
6.3
|
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
Employer
Contributions
|
|
|||||||||||||||||||||||||||
|
Year
Ending December 31, 2005
|
$
|
-
|
$
|
0.7
|
$
|
0.4
|
$
|
1.1
|
$
|
4.5
|
$
|
-
|
$
|
-
|
$
|
5.6
|
|
|||||||||||
|
Year
Ending December 31, 2004
|
5.4
|
5.0
|
0.4
|
10.8
|
2.8
|
0.1
|
-
|
13.7
|
|
|||||||||||||||||||
|
|
||||||||||||||||||||||||||||
|
Weighted-Average
Assumptions - Benefit Obligations
|
|
|||||||||||||||||||||||||||
|
Discount
rate
|
|
|||||||||||||||||||||||||||
|
At
December 31, 2005
|
5.66
|
%
|
5.54
|
%
|
5.38
|
%
|
5.50
|
%
|
20.00
|
%
|
12.00
|
%
|
5.60
|
%
|
(b)
|
|
||||||||||||
|
At
December 31, 2004
|
5.50
|
%
|
5.50
|
%
|
5.50
|
%
|
6.00
|
%
|
20.00
|
%
|
-
|
5.60
|
%
|
(b)
|
|
|||||||||||||
|
Rate
of compensation increase
|
|
|||||||||||||||||||||||||||
|
At
December 31, 2005
|
4.72
|
%
|
4.29
|
%
|
-
|
3.50
|
%
|
15.00
|
%
|
10.00
|
%
|
4.50
|
%
|
(b)
|
|
|||||||||||||
|
At
December 31, 2004
|
5.45
|
%
|
5.45
|
%
|
-
|
3.50
|
%
|
15.00
|
%
|
-
|
5.00
|
%
|
(b)
|
|
||||||||||||||
|
|
||||||||||||||||||||||||||||
|
Weighted-Average
Assumptions - Net Periodic Benefit Cost
|
|
|||||||||||||||||||||||||||
|
Discount
rate
|
|
|||||||||||||||||||||||||||
|
At
December 31, 2005
|
5.50
|
%
|
5.50
|
%
|
5.50
|
%
|
6.00
|
%
|
20.00
|
%
|
12.00
|
%
|
5.63
|
%
|
(b)
|
|
||||||||||||
|
At
December 31, 2004
|
6.00
|
%
|
6.00
|
%
|
6.00
|
%
|
6.00
|
%
|
20.00
|
%
|
-
|
6.01
|
%
|
(b)
|
|
|||||||||||||
|
Expected
long-term rate of return on plan assets
|
|
|||||||||||||||||||||||||||
|
At
December 31, 2005
|
9.00
|
%
|
-
|
9.00
|
%
|
7.00
|
%
|
-
|
-
|
8.70
|
%
|
(c)
|
|
|||||||||||||||
|
At
December 31, 2004
|
9.00
|
%
|
-
|
9.00
|
%
|
7.00
|
%
|
-
|
-
|
8.73
|
%
|
(c)
|
|
|||||||||||||||
|
Rate
of compensation increase
|
|
|||||||||||||||||||||||||||
|
At
December 31, 2005
|
4.75
|
%
|
4.29
|
%
|
-
|
3.50
|
%
|
15.00
|
%
|
10.00
|
%
|
4.52
|
%
|
(b)
|
|
|||||||||||||
|
At
December 31, 2004
|
5.45
|
%
|
5.45
|
%
|
-
|
3.50
|
%
|
15.00
|
%
|
-
|
5.00
|
%
|
(b)
|
|
||||||||||||||
|
(a)
|
Pension
costs were reduced by expected returns on plan assets of $20.5 million
and
$19.6 million for the years ended December 31, 2005 and 2004,
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. No contributions
were made to the funded U.S. Plans during 2005. Contributions of $5.4 million
were made to the funded U.S. Plans during 2004. Contributions of $1.1 million
and $5.4 million to the unfunded U.S. Plans in 2005 and 2004, respectively,
were
to fund benefit payments.
The
$5.6
million and $13.7 million we contributed to the Transocean Plans in 2005 and
2004, respectively, was funded from our cash flows from operations.
Net
periodic benefit cost for these defined benefit pension plans included the
following components (in millions):
|
Years
ended December 31,
|
|||||||
|
2005
|
2004
|
||||||
|
Components
of Net Periodic Benefit Cost (a)
|
|||||||
|
Service
cost
|
$
|
18.1
|
$
|
16.7
|
|||
|
Interest
cost
|
17.6
|
16.7
|
|||||
|
Expected
return on plan assets
|
(20.5
|
)
|
(19.6
|
)
|
|||
|
Amortization
of transition obligation
|
0.3
|
0.3
|
|||||
|
Amortization
of prior service cost
|
0.8
|
0.6
|
|||||
|
Recognized
net actuarial losses
|
3.8
|
2.3
|
|||||
|
SFAS
88 settlements/curtailments
|
2.1
|
-
|
|||||
|
Benefit
cost
|
$
|
22.2
|
$
|
17.0
|
|||
|
(a)
|
Amounts
are before income tax effect.
|
Plan
assets of the funded Transocean Plans have been favorably impacted by a
substantial rise in world equity markets during 2005 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 2005, the market value of the investments in the Transocean Plans
increased by $4.9 million, or 2.1 percent. The increase is due to net investment
gains of $17.5 million, primarily in the funded U.S. Plans, resulting from
the
favorable performance of equity markets in 2005, partially offset by benefit
plan payments of $18.0 million from these plans. We expect to contribute $8.3
million to the Transocean Plans in 2006. These contributions are comprised
of an
estimated $2.7 million to meet minimum funding requirements for the funded
U.S.
Plans, $0.7 million to fund expected benefit payments for the unfunded U.S.
Plans, Nigeria Plan and Egypt Plan and an estimated $4.9 million for the funded
Norway Plans. We expect the required contributions will be funded from cash
flow
from operations. We have generated unrecognized net actuarial losses due to
the
effect of the unfavorable performance in previous years of the plan assets
of
the funded Transocean Plans. As of December 31, 2005, we had cumulative losses
of $74.6 million that remain to be recognized in the calculation of the
market-related value of assets. These unrecognized net actuarial losses may
result in increases in our future pension expense depending on several factors,
including whether such losses at each measurement date exceed certain amounts
in
accordance with SFAS 87, Employers’
Accounting for Pensions.
The
following pension benefits payments are expected to be paid by the Transocean
Plans (in millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
13.1
|
||
|
2007
|
13.5
|
|||
|
2008
|
14.1
|
|||
|
2009
|
14.6
|
|||
|
2010
|
15.1
|
|||
|
2011-2015
|
74.3
|
|||
We
account for the Transocean Plans in accordance with SFAS 87. This statement
requires 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 2004, the effect of the decrease in the discount
rate
offset the increases in the fair value of plan assets resulting in an increase
in the minimum pension liability of $6.3 million. 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 $6.1 million. At December 31,
2005, the minimum pension liability included in other comprehensive income
was
$35.9 million. The minimum pension liability adjustments did not impact our
results of operations during 2003, 2004 or 2005, nor did these adjustments
affect our ability to meet any financial covenants related to our debt
facilities.
Our
expected long-term rates of return on plan assets for the funded U.S. Plans
was
9.0 percent as of December 31, 2005 and 2004. The expected long-term rate of
return on plan assets was developed by reviewing each plan's targeted 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 5.5 percent at December 31, 2005, 6.0 percent at December
31, 2004 and 6.0 percent at December 31, 2003.
We
expect
pension expense related to the Transocean Plans for 2006 to increase by
approximately $0.8 million primarily due to the change in discount rate
assumptions.
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―We have
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):
|
Years
ended December 31,
|
|||||||
|
2005
|
2004
|
||||||
|
Components
of Net Periodic Benefit Cost (a)
|
|||||||
|
Service
cost
|
$
|
1.3
|
$
|
1.0
|
|||
|
Interest
cost
|
2.1
|
2.1
|
|||||
|
Amortization
of prior service cost
|
(2.3
|
)
|
(2.3
|
)
|
|||
|
Recognized
net actuarial losses
|
1.7
|
1.5
|
|||||
|
Benefit
cost
|
$
|
2.8
|
$
|
2.3
|
|||
|
(a)
|
Amounts
are before income tax effect.
|
The
following postretirement benefits payments are expected to be paid by our
postretirement benefits plans (in millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
1.4
|
||
|
2007
|
1.5
|
|||
|
2008
|
1.6
|
|||
|
2009
|
1.7
|
|||
|
2010
|
1.8
|
|||
|
2011-2015
|
10.5
|
|||
Off-Balance
Sheet Arrangement
We
leased
the semisubmersible rig 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 $4.6 million, $12.7 million and $12.5 million of such rent expense
in
the years ended December 31, 2005, 2004 and 2003, respectively. In May 2005,
we
purchased the rig for $42.5 million. The rig was reflected as property and
equipment in our consolidated balance sheet at December 31, 2005.
Effective
December 31, 2003, we adopted and applied the provisions of FIN 46, Consolidation
of Variable Interest Entities,
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.
Related
Party Transactions
ODL—We
own a
50 percent interest in an unconsolidated joint venture company, ODL. ODL owns
the Joides
Resolution,
for
which we provide certain operational and management services. In 2005, we earned
$1.4 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. During 2005
and
prior to entering into the loan agreement, we received $3.0 million in dividend
payments from ODL. As of December 31, 2005, $3.5 million was outstanding under
this loan agreement and was reflected as other long-term liabilities in our
consolidated balance sheet.
Separation
of TODCO
Master
Separation Agreement with TODCO—We
entered into a master separation agreement with TODCO that provides for the
completion of the separation of TODCO’s business from ours. It also governs
aspects of the relationship between us and TODCO following the TODCO IPO. The
master separation agreement provides for cross-indemnities that generally place
financial responsibility on TODCO and its subsidiaries for all liabilities
associated with the businesses and operations falling within the definition
of
TODCO’s business, and that generally place financial responsibility for
liabilities associated with all of our businesses and operations with us,
regardless of the time those liabilities arise.
Under
the
master separation agreement we also agreed to generally release TODCO, and
TODCO
agreed to generally release us, from any liabilities that arose prior to the
closing of the TODCO IPO, including acts or events that occurred in connection
with the separation or the TODCO IPO provided that specified ongoing obligations
and arrangements between TODCO and our company are excluded from the mutual
release.
The
master separation agreement defines the TODCO business to generally mean
contract drilling and similar services for oil and gas wells using jackup,
submersible, barge and platform drilling rigs in the U.S. Gulf of Mexico and
U.S. inland waters; contract drilling and similar services for oil and gas
wells
in and offshore Mexico, Trinidad, Colombia and Venezuela; and TODCO’s joint
venture interest in Delta Towing. Our business is generally defined to include
all of the businesses and activities not defined as the TODCO business and
specifically includes contract drilling and similar services for oil and gas
wells using semisubmersibles and drillships in the U.S. Gulf of Mexico; contract
drilling and similar services for oil and gas wells in geographic regions
outside of the U.S. Gulf of Mexico, U.S. inland waters, Mexico, Colombia,
Trinidad and Venezuela; oil and gas exploration and production activities;
coal
production activities; and the turnkey drilling business that TODCO formerly
operated in the U.S. Gulf of Mexico and offshore Mexico.
Tax
Sharing Agreement with TODCO—Our
wholly owned subsidiary, Transocean Holdings Inc. (“Transocean Holdings”),
entered into a tax sharing agreement with TODCO in connection with the TODCO
IPO. See
“―Outlook-Tax Matters.”
New
Accounting Pronouncements
In
May
2005, the FASB issued SFAS 154, “Accounting
Changes and Error Corrections,” which
requires retrospective application to all prior period financial statements
presented for voluntary changes in accounting principle unless it is
impracticable. This statement replaces Accounting Principles Board Opinion
(“APB”) 20, Accounting
Changes,
and
SFAS 3, Reporting
Accounting Changes in Interim Financial Statements,
though
it carries forward the guidance in those pronouncements with respect to
accounting for changes in estimates, changes in reporting entity and the
correction of errors. SFAS 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
We
adopted SFAS 154 effective January 1, 2006, and we do not expect the adoption
of
this statement to have an impact on our consolidated financial position, results
of operations or cash flows.
In
December 2004, the FASB issued SFAS 123 (revised 2004) (“SFAS
123(R)”), Share-Based
Payment,
which
is a revision of SFAS 123, Accounting
for Stock-Based Compensation.
SFAS
123(R) supersedes APB 25, Accounting
for Stock Issued to Employees,
and
amends SFAS 95, Statement
of Cash Flows.
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. We
adopted SFAS 123(R) effective January 1, 2006.
SFAS
123(R) permits adoption using one of two methods, a modified prospective method
(“Prospective Method”) or a modified retrospective method (“Retrospective
Method”). With the Prospective Method, costs are recognized beginning with the
effective date based on the requirements of SFAS 123(R) for (i) all share-based
payments granted after the effective date of SFAS 123(R), and (ii) all awards
granted to employees prior to the effective date of SFAS 123(R) that remain
unvested on the effective date. The Retrospective Method applies the
requirements of the Prospective Method but further permits entities to restate
all prior periods presented based on the amounts previously recognized under
SFAS 123 for purposes of pro forma disclosures. We elected to adopt SFAS 123(R)
using the Prospective Method.
We
previously adopted the fair-value-based method of accounting for share-based
payments effective January 1, 2003 using the Prospective Method as described
in
SFAS 148, Accounting
for Stock-Based Compensation-Transition and Disclosure.
We
currently use the Black-Scholes-Merton formula to estimate the value of stock
options granted to employees, which is an acceptable share-based award valuation
model, and we have chosen that model for determining fair value of stock awards
granted under SFAS 123(R). Our APB 25 options vested in the third quarter of
2005. As a result, adoption of SFAS 123(R) had no effect on these
options.
Since
we
adopted SFAS 123(R) using the Prospective Method, we do not expect the adoption
to have an 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 is currently required under SFAS 95. While
we
cannot estimate what these amounts will be in the future (because they depend
on, among other things, when employees exercise stock options), we reported
operating cash flows related to tax deduction benefits of $22.1 million for
the
year ended December 31, 2005.
Under
SFAS 123, we recognize the compensation cost over the vesting period up to
the
date of actual retirement. We will continue this practice for awards granted
prior to the adoption of SFAS 123(R). Upon the adoption of SFAS 123(R), we
will
recognize compensation cost for 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”). If we had amortized compensation cost over the
service period, the amount would not have been material in 2005.
|
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, 2005.
At
December 31, 2005 (in millions, except interest rate percentages):
|
Scheduled
Maturity Date (a) (b)
|
Fair
Value
|
||||||||||||||||||||||||
|
2006
|
2007
|
2008
|
2009
|
2010
|
Thereafter
|
Total
|
12/31/05
|
||||||||||||||||||
|
Total
debt
|
|||||||||||||||||||||||||
|
Fixed
rate
|
$
|
400.0
|
$
|
100.0
|
$
|
19.0
|
$
|
−
|
$
|
−
|
$
|
1,069.4
|
$
|
1,588.4
|
$
|
1,865.3
|
|||||||||
|
Average
interest rate
|
1.5
|
%
|
7.5
|
%
|
2.8
|
%
|
−
|
%
|
−
|
%
|
7.4
|
%
|
5.8
|
%
|
|||||||||||
|
(a)
|
Maturity
dates of the face value of our debt assume the put options on the
1.5%
Convertible Debentures, 7.45% Notes and Zero Coupon Convertible Debentures
will be exercised in May 2006, April 2007 and May 2008,
respectively.
|
|
(b)
|
Expected
maturity amounts are based on the face value of debt.
|
At
December 31, 2005, we had no variable rate debt and as such interest expense
had
no exposure to changes in interest rates. However, a large part of our cash
investments would earn commensurately higher rates of return if interest rates
increase. Using December 31, 2005 cash investment levels, a one percentage
point
change in interest rates would result in a corresponding change in interest
income of approximately $3.3 million per year.
The
fair
market value of our debt at December 31, 2004 was $2,702.5 million compared
to
$1,865.3 million at December 31, 2005. The decrease in fair value of $837.2
million was primarily caused by our repurchases and redemptions 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, 2005, we had no open foreign exchange
derivative contracts.
|
Financial
Statements and Supplementary
Data
|
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, 2005. 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, 2005, 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, 2005. 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, 2005.
REPORT
OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM ON INTERNAL CONTROL OVER
FINANCIAL REPORTING
The
Board
of Directors and Shareholders of Transocean
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 December
31, 2005, 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, 2005, 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, 2005, based
on the
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, 2005
and
2004, 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, 2005 and
our
report dated March 8, 2006 expressed an unqualified opinion
thereon.
|
/s/
Ernst & Young LLP
|
|
|
Houston,
Texas
|
|
|
March
8, 2006
|
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, 2005 and 2004, 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, 2005. 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, 2005 and 2004, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2005, 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.
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, 2005, based on criteria
established in Internal Control-Integrated Framework issued by the Committee
of
Sponsoring Organizations of the Treadway Commission and our report dated March
8, 2006 expressed an unqualified opinion thereon.
|
/s/
Ernst & Young LLP
|
|
|
Houston,
Texas
|
|
|
March
8, 2006
|
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In
millions, except per share data)
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Operating
Revenues
|
||||||||||
|
Contract
drilling revenues
|
$
|
2,757.1
|
$
|
2,416.4
|
$
|
2,328.5
|
||||
|
Other
revenues
|
134.6
|
197.5
|
105.8
|
|||||||
|
2,891.7
|
2,613.9
|
2,434.3
|
||||||||
|
Costs
and Expenses
|
||||||||||
|
Operating
and maintenance
|
1,720.6
|
1,713.6
|
1,591.2
|
|||||||
|
Depreciation
|
405.8
|
524.6
|
508.2
|
|||||||
|
General
and administrative
|
74.8
|
67.0
|
65.3
|
|||||||
|
2,201.2
|
2,305.2
|
2,164.7
|
||||||||
|
Impairment
loss on long-lived assets
|
−
|
−
|
(16.5
|
)
|
||||||
|
Gain
(loss) from disposal of assets, net
|
29.0
|
19.2
|
(13.4
|
)
|
||||||
|
Operating
Income
|
719.5
|
327.9
|
239.7
|
|||||||
|
Other
Income (Expense), net
|
||||||||||
|
Equity
in earnings of unconsolidated affiliates
|
10.1
|
9.2
|
5.1
|
|||||||
|
Interest
income
|
19.6
|
9.3
|
18.8
|
|||||||
|
Interest
expense
|
(111.2
|
)
|
(171.7
|
)
|
(202.0
|
)
|
||||
|
Gain
from TODCO Stock Sales
|
165.0
|
308.8
|
−
|
|||||||
|
Non-cash
TODCO tax sharing agreement charge
|
−
|
(167.1
|
)
|
−
|
||||||
|
Loss
on retirement of debt
|
(7.3
|
)
|
(76.5
|
)
|
(15.7
|
)
|
||||
|
Impairment
loss on note receivable from related party
|
−
|
−
|
(21.3
|
)
|
||||||
|
Other,
net
|
6.7
|
0.4
|
(3.0
|
)
|
||||||
|
82.9
|
(87.6
|
)
|
(218.1
|
)
|
||||||
|
Income
Before Income Taxes, Minority Interest and Cumulative Effect of a
Change
in Accounting Principle
|
802.4
|
240.3
|
21.6
|
|||||||
|
Income
Tax Expense
|
86.8
|
91.3
|
3.0
|
|||||||
|
Minority
Interest
|
−
|
(3.2
|
)
|
0.2
|
||||||
|
Income
Before Cumulative Effect of a Change in Accounting
Principle
|
715.6
|
152.2
|
18.4
|
|||||||
|
Cumulative
Effect of a Change in Accounting Principle
|
−
|
−
|
0.8
|
|||||||
|
Net
Income
|
$
|
715.6
|
$
|
152.2
|
$
|
19.2
|
||||
|
Basic
Earnings Per Share
|
||||||||||
|
Income
Before Cumulative Effect of a Change in Accounting
Principle
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
||||
|
Cumulative
Effect of a Change in Accounting Principle
|
−
|
−
|
−
|
|||||||
|
Net
Income
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
||||
|
Diluted
Earnings Per Share
|
||||||||||
|
Income
Before Cumulative Effect of a Change in Accounting
Principle
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
||||
|
Cumulative
Effect of a Change in Accounting Principle
|
−
|
−
|
−
|
|||||||
|
Net
Income
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
||||
|
Weighted
Average Shares Outstanding
|
||||||||||
|
Basic
|
327.1
|
320.9
|
319.8
|
|||||||
|
Diluted
|
339.4
|
325.2
|
321.4
|
|||||||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME
(In
millions)
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Net
Income
|
$
|
715.6
|
$
|
152.2
|
$
|
19.2
|
||||
|
Other
Comprehensive Income (Loss), net of tax
|
||||||||||
|
Amortization
of gain on terminated interest rate swaps
|
(0.3
|
)
|
(0.2
|
)
|
(0.2
|
)
|
||||
|
Change
in unrealized loss on securities available for sale
|
0.3
|
0.1
|
0.2
|
|||||||
|
Change
in share of unrealized loss in unconsolidated joint venture’s interest
rate swaps (net of tax expense of $1.1 for the year ended December
31,
2003)
|
−
|
−
|
2.0
|
|||||||
|
Minimum
pension liability adjustments (net of tax expense (benefit) of $2.1,
$(2.2) and $0.7 for the years ended December 31, 2005, 2004 and 2003,
respectively)
|
4.0
|
(4.1
|
)
|
9.3
|
||||||
|
Other
Comprehensive Income (Loss)
|
4.0
|
(4.2
|
)
|
11.3
|
||||||
|
Total
Comprehensive Income
|
$
|
719.6
|
$
|
148.0
|
$
|
30.5
|
||||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
BALANCE SHEETS
(In
millions, except share data)
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
ASSETS
|
|||||||
|
Cash
and Cash Equivalents
|
$
|
445.4
|
$
|
451.3
|
|||
|
Accounts
Receivable, net
|
|||||||
|
Trade
|
582.5
|
426.5
|
|||||
|
Other
|
17.2
|
15.5
|
|||||
|
Materials
and Supplies, net
|
156.2
|
144.7
|
|||||
|
Deferred
Income Taxes, net
|
23.4
|
19.0
|
|||||
|
Other
Current Assets
|
54.4
|
52.1
|
|||||
|
Total
Current Assets
|
1,279.1
|
1,109.1
|
|||||
|
Property
and Equipment
|
9,791.0
|
9,732.9
|
|||||
|
Less
Accumulated Depreciation
|
3,042.8
|
2,727.7
|
|||||
|
Property
and Equipment, net
|
6,748.2
|
7,005.2
|
|||||
|
Goodwill
|
2,208.9
|
2,251.9
|
|||||
|
Investments
in and Advances to Unconsolidated Affiliates
|
8.1
|
109.2
|
|||||
|
Deferred
Income Taxes
|
−
|
43.8
|
|||||
|
Other
Assets
|
212.9
|
239.1
|
|||||
|
Total
Assets
|
$
|
10,457.2
|
$
|
10,758.3
|
|||
|
LIABILITIES
AND SHAREHOLDERS' EQUITY
|
|||||||
|
Accounts
Payable
|
$
|
254.0
|
$
|
180.8
|
|||
|
Accrued
Income Taxes
|
27.5
|
17.1
|
|||||
|
Debt
Due Within One Year
|
400.0
|
19.4
|
|||||
|
Other
Current Liabilities
|
242.1
|
213.0
|
|||||
|
Total
Current Liabilities
|
923.6
|
430.3
|
|||||
|
Long-Term
Debt
|
1,197.1
|
2,462.1
|
|||||
|
Deferred
Income Taxes, net
|
65.0
|
124.1
|
|||||
|
Other
Long-Term Liabilities
|
286.2
|
345.2
|
|||||
|
Total
Long-Term Liabilities
|
1,548.3
|
2,931.4
|
|||||
|
Commitments
and Contingencies
|
|||||||
|
Minority
Interest
|
3.6
|
4.0
|
|||||
|
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, 324,750,166
and
321,533,998 shares issued and outstanding at December 31, 2005 and
2004,
respectively
|
3.2
|
3.2
|
|||||
|
Additional
Paid-in Capital
|
10,565.3
|
10,695.8
|
|||||
|
Accumulated
Other Comprehensive Loss
|
(20.4
|
)
|
(24.4
|
)
|
|||
|
Retained
Deficit
|
(2,566.4
|
)
|
(3,282.0
|
)
|
|||
|
Total
Shareholders' Equity
|
7,981.7
|
7,392.6
|
|||||
|
Total
Liabilities and Shareholders' Equity
|
$
|
10,457.2
|
$
|
10,758.3
|
|||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF EQUITY
(In
millions)
|
Ordinary
Shares
|
Additional
Paid-in
|
Accumulated
Other
Comprehensive
|
Retained
Earnings
|
Total
|
|||||||||||||||
|
Shares
|
|
Amount
|
Capital
|
Income
(Loss)
|
|
(Deficit)
|
Equity
|
||||||||||||
|
Balance
at December 31, 2002
|
319.2
|
$
|
3.2
|
$
|
10,623.1
|
$
|
(31.5
|
)
|
$
|
(3,453.4
|
)
|
$
|
7,141.4
|
||||||
|
Net
income
|
-
|
-
|
-
|
-
|
19.2
|
19.2
|
|||||||||||||
|
Issuance
of ordinary shares under stock-based compensation plans
|
0.7
|
-
|
14.0
|
-
|
-
|
14.0
|
|||||||||||||
|
Gain
on terminated interest rate swaps
|
-
|
-
|
-
|
(0.2
|
)
|
-
|
(0.2
|
)
|
|||||||||||
|
Fair
value adjustment on marketable securities held for sale
|
−
|
−
|
−
|
0.2
|
−
|
0.2
|
|||||||||||||
|
Other
comprehensive income related to joint venture
|
-
|
-
|
-
|
2.0
|
-
|
2.0
|
|||||||||||||
|
Minimum
pension liability
|
-
|
-
|
-
|
9.3
|
-
|
9.3
|
|||||||||||||
|
Other
|
-
|
-
|
6.7
|
-
|
-
|
6.7
|
|||||||||||||
|
Balance
at December 31, 2003
|
319.9
|
3.2
|
10,643.8
|
(20.2
|
)
|
(3,434.2
|
)
|
7,192.6
|
|||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
152.2
|
152.2
|
|||||||||||||
|
Issuance
of ordinary shares under stock-based compensation plans
|
1.6
|
-
|
38.1
|
-
|
-
|
38.1
|
|||||||||||||
|
Gain
on terminated interest rate swaps
|
-
|
-
|
-
|
(0.2
|
)
|
-
|
(0.2
|
)
|
|||||||||||
|
Fair
value adjustment on marketable securities held for sale
|
−
|
−
|
−
|
0.1
|
−
|
0.1
|
|||||||||||||
|
Minimum
pension liability
|
-
|
-
|
-
|
(4.1
|
)
|
-
|
(4.1
|
)
|
|||||||||||
|
Other
|
-
|
-
|
13.9
|
-
|
-
|
13.9
|
|||||||||||||
|
Balance
at December 31, 2004
|
321.5
|
3.2
|
10,695.8
|
(24.4
|
)
|
(3,282.0
|
)
|
7,392.6
|
|||||||||||
|
Net
income
|
-
|
-
|
-
|
-
|
715.6
|
715.6
|
|||||||||||||
|
Repurchase
of ordinary shares
|
(6.0
|
)
|
(0.1
|
)
|
(399.9
|
)
|
-
|
-
|
(400.0
|
)
|
|||||||||
|
Issuance
of ordinary shares under stock-based compensation plans
|
9.2
|
0.1
|
259.7
|
-
|
-
|
259.8
|
|||||||||||||
|
Gain
on terminated interest rate swaps
|
-
|
-
|
-
|
(0.3
|
)
|
-
|
(0.3
|
)
|
|||||||||||
|
Fair
value adjustment on marketable securities held for sale
|
−
|
-
|
-
|
0.3
|
-
|
0.3
|
|||||||||||||
|
Minimum
pension liability
|
-
|
-
|
-
|
4.0
|
-
|
4.0
|
|||||||||||||
|
Other
|
-
|
-
|
9.7
|
-
|
-
|
9.7
|
|||||||||||||
|
Balance
at December 31, 2005
|
324.7
|
$
|
3.2
|
$
|
10,565.3
|
$
|
(20.4
|
)
|
$
|
(2,566.4
|
)
|
$
|
7,981.7
|
||||||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Cash
Flows from Operating Activities
|
||||||||||
|
Net
income
|
$
|
715.6
|
$
|
152.2
|
$
|
19.2
|
||||
|
Adjustments
to reconcile net income to net cash provided by operating
activities
|
||||||||||
|
Depreciation
|
405.8
|
524.6
|
508.2
|
|||||||
|
Stock-based
compensation expense
|
16.4
|
25.3
|
6.3
|
|||||||
|
Deferred
income taxes
|
27.1
|
18.1
|
(98.5
|
)
|
||||||
|
Equity
in earnings of unconsolidated affiliates
|
(10.1
|
)
|
(9.2
|
)
|
(5.1
|
)
|
||||
|
Net
(gain) loss from disposal of assets
|
(29.0
|
)
|
(19.2
|
)
|
13.4
|
|||||
|
Gain
from TODCO Stock Sales
|
(165.0
|
)
|
(308.8
|
)
|
−
|
|||||
|
Non-cash
TODCO tax sharing agreement charge
|
−
|
167.1
|
−
|
|||||||
|
Loss
on retirement of debt
|
7.3
|
76.5
|
15.7
|
|||||||
|
Impairment
loss on long-lived assets
|
−
|
−
|
16.5
|
|||||||
|
Impairment
loss on note receivable from related party
|
−
|
−
|
21.3
|
|||||||
|
Amortization
of debt-related discounts/premiums, fair value adjustments and issue
costs, net
|
(6.6
|
)
|
(21.2
|
)
|
(24.3
|
)
|
||||
|
Deferred
income, net
|
(7.4
|
)
|
35.3
|
4.4
|
||||||
|
Deferred
expenses, net
|
17.6
|
(22.0
|
)
|
(33.2
|
)
|
|||||
|
Tax
benefit from exercise of options to purchase and vesting of ordinary
shares under stock-based compensation plans
|
22.1
|
5.9
|
0.3
|
|||||||
|
Other
long-term liabilities
|
22.8
|
10.2
|
10.8
|
|||||||
|
Other,
net
|
(17.3
|
)
|
(6.1
|
)
|
8.8
|
|||||
|
Changes
in operating assets and liabilities
|
||||||||||
|
Accounts
receivable
|
(149.8
|
)
|
(29.3
|
)
|
19.8
|
|||||
|
Accounts
payable and other current liabilities
|
87.2
|
4.6
|
6.5
|
|||||||
|
Income
taxes receivable/payable, net
|
(50.6
|
)
|
1.2
|
27.8
|
||||||
|
Other
current assets
|
(21.9
|
)
|
(5.3
|
)
|
7.5
|
|||||
|
Net
Cash Provided by Operating Activities
|
864.2
|
599.9
|
525.4
|
|||||||
|
Cash
Flows from Investing Activities
|
||||||||||
|
Capital
expenditures
|
(181.9
|
)
|
(127.0
|
)
|
(493.8
|
)
|
||||
|
Note
issued to related party
|
−
|
−
|
(46.1
|
)
|
||||||
|
Payments
received from note issued to related party
|
−
|
−
|
46.1
|
|||||||
|
Deepwater
Drilling II L.L.C.’s cash acquired, net of cash paid
|
−
|
−
|
18.1
|
|||||||
|
Deepwater
Drilling L.L.C.’s cash acquired
|
−
|
−
|
18.6
|
|||||||
|
Proceeds
from disposal of assets, net
|
74.1
|
52.9
|
8.4
|
|||||||
|
Proceeds
from TODCO Stock Sales, net
|
271.9
|
683.6
|
−
|
|||||||
|
Reduction
of cash from the deconsolidation of TODCO
|
−
|
(68.6
|
)
|
−
|
||||||
|
Joint
ventures and other investments, net
|
4.5
|
10.4
|
3.3
|
|||||||
|
Net
Cash Provided by (Used in) Investing Activities
|
168.6
|
551.3
|
(445.4
|
)
|
||||||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Continued)
(In
millions)
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Cash
Flows from Financing Activities
|
||||||||||
|
Net
borrowings (repayments) on revolving credit agreement
|
−
|
(250.0
|
)
|
250.0
|
||||||
|
Repayments
on other debt instruments
|
(880.2
|
)
|
(955.3
|
)
|
(1,252.7
|
)
|
||||
|
Cash
from termination of interest rate swaps
|
−
|
−
|
173.5
|
|||||||
|
Repurchase
of ordinary shares
|
(400.0
|
)
|
-
|
-
|
||||||
|
Net
proceeds from issuance of ordinary shares under stock-based compensation
plans
|
219.5
|
30.4
|
12.8
|
|||||||
|
Proceeds
from issuance of ordinary shares upon exercise of warrants
|
10.6
|
−
|
−
|
|||||||
|
Decrease
in restricted cash
|
12.0
|
−
|
−
|
|||||||
|
Financing
costs
|
−
|
−
|
(4.9
|
)
|
||||||
|
Other,
net
|
(0.6
|
)
|
1.0
|
1.1
|
||||||
|
Net
Cash Used in Financing Activities
|
(1,038.7
|
)
|
(1,173.9
|
)
|
(820.2
|
)
|
||||
|
Net
Decrease in Cash and Cash Equivalents
|
(5.9
|
)
|
(22.7
|
)
|
(740.2
|
)
|
||||
|
Cash
and Cash Equivalents at Beginning of Period
|
451.3
|
474.0
|
1,214.2
|
|||||||
|
Cash
and Cash Equivalents at End of Period
|
$
|
445.4
|
$
|
451.3
|
$
|
474.0
|
||||
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
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, 2005, we owned, had partial ownership interests in or operated
90
mobile offshore and barge drilling units. As of this date, our assets consisted
of 32 High-Specification semisubmersibles and drillships (“floaters”), 23 Other
Floaters, 25 Jackup Rigs and 10 Other Rigs (see Note 18).
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
common stock of TODCO in which we sold 13.8 million shares of TODCO class A
common stock, representing 23 percent of TODCO’s total outstanding shares. 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 17.9 million shares of TODCO’s class A common stock
(30 percent of TODCO’s total outstanding shares) in the September 2004 Offering
and 15.0 million shares of TODCO’s class A common stock (25 percent of TODCO’s
total outstanding shares) 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 connection 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, represented by 13.3 million shares
of
class A common stock.
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. 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 12.0
million shares of TODCO’s class A common stock (20 percent of TODCO’s total
outstanding shares) in the May Offering and our remaining 1.3 million shares
of
TODCO’s class A common stock (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.
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
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, 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 (“mutual funds”). The mutual
funds 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 $12.0 million at
December 31, 2004. As a result of the repayment of the project financing (see
Note 8), 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. Interest receivable on delinquent
accounts receivable is included in the accounts receivable trade balance and
recognized as interest income when chargeable and collectibility is reasonably
assured. 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 $15.3 million
and $16.8 million at December 31, 2005 and 2004, 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 the lower of average cost or market less an
allowance for obsolescence. Such allowance was $19.1 million and $20.3 million
at December 31, 2005 and 2004, respectively.
Property
and Equipment—Property
and equipment, consisting primarily of offshore drilling rigs and related
equipment, represented approximately 64 percent of our total assets at December
31, 2005. 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. 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 2005 and 2004, the impact of the change in estimated useful life of
these rigs was a reduction in depreciation expense of $16.1 million ($0.05
per
diluted share) and $4.7 million ($0.01 per diluted share), respectively, which
had no tax effect.
TRANSOCEAN
INC. AND SUBSIDIARIES
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”) 144,
Accounting
for Impairment or Disposal of Long-Lived Assets.
At
December 31, 2005 and 2004, we had assets held for sale in the amounts of $15.9
million and $5.6 million, respectively, that were included in other current
assets (see Notes 6 and 27).
Goodwill—In
accordance with SFAS 142, Goodwill
and Other Intangible Assets,
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.
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 2004 or 2003.
Since the disposition of TODCO, we operate in one reportable 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
October 1, 2005 since it met all necessary carry forward criteria within the
scope of SFAS 142. As a result of these tests for impairment, we had no
impairment of goodwill for the years ended December 31, 2005, 2004 and
2003.
Our
goodwill balance and changes in the carrying amount of goodwill are as follows
(in millions):
|
Balance
at
January
1,
2005
|
Other
(a)
|
Balance
at
December
31,
2005
|
||||||||
|
Transocean
Drilling
|
$
|
2,251.9
|
$
|
43.0
|
$
|
2,208.9
|
||||
|
(a)
|
Primarily
represents net adjustments during 2005 of income tax-related
pre-acquisition contingencies. See Note
16.
|
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. See Note 7.
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Capitalized
Interest—Interest
costs for the construction and upgrade of qualifying assets are capitalized.
No
interest cost was capitalized during the years ended December 31, 2005, 2004
and
2003.
Derivative
Instruments and Hedging Activities—We
account for our derivative instruments and hedging activities in accordance
with
SFAS 133, Accounting
for Derivative Instruments and Hedging Activities.
See
Notes 9 and 10.
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 $(4.5) million, $0.4 million and $(3.5) million for the
years ended December 31, 2005, 2004 and 2003, respectively.
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 16.
Stock-Based
Compensation—Effective
January 1, 2003, we adopted the fair value recognition provisions of SFAS 123,
Accounting
for Stock-Based Compensation, using
the
prospective method proscribed in SFAS 148, Accounting
for Stock-Based Compensation - Transition and Disclosure.
Under
the prospective method, employee stock-based compensation awards granted on
or
subsequent to January 1, 2003 are expensed over the vesting period based on
the
fair value of the underlying awards on the date of grant. The fair value of
the
stock options is determined using the Black-Scholes-Merton option pricing model,
while the fair value of restricted stock grants is determined based on the
market price of our stock on the date of grant. Additionally, stock appreciation
rights are recorded at fair value with the changes in fair value recorded as
compensation expense as incurred. Stock-based compensation awards granted prior
to January 1, 2003, if not subsequently modified, were accounted for under
the
recognition and measurement provisions of Accounting Principles Board Opinion
(“APB”) 25, Accounting
for Stock Issued to Employees
and
related interpretations
(see
“―New Accounting Pronouncements”).
As a
result of the adoption of SFAS 123, compensation expense increased $6.1 million
($4.3 million or $0.01 per diluted share, net of tax) related to our stock-based
compensation awards and modifications, and our Employee Stock Purchase Plan
(“ESPP”) during 2003.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
If
compensation expense for grants to employees under our long-term incentive
plan
prior to January 1, 2003 was recognized using the fair value method of
accounting under SFAS 123 rather than the intrinsic value method under APB
25,
net income and earnings per share would have been reduced to the pro forma
amounts indicated below (in millions, except per share data):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Net
Income as Reported
|
$
|
715.6
|
$
|
152.2
|
$
|
19.2
|
||||
|
Add
back: Stock-based compensation expense included in reported net income,
net of related tax effects
|
12.7
|
18.2
|
4.6
|
|||||||
|
Deduct:
Total stock-based compensation expense determined under the fair
value
method for all awards, net of related tax effects
|
||||||||||
|
Long-Term
Incentive Plan
|
(11.1
|
)
|
(22.4
|
)
|
(18.2
|
)
|
||||
|
ESPP
|
(3.6
|
)
|
(2.6
|
)
|
(2.5
|
)
|
||||
|
Pro
Forma Net Income for basic earnings per share
|
$
|
713.6
|
$
|
145.4
|
$
|
3.1
|
||||
|
Add
back interest expense on the 1.5% convertible debentures
|
6.3
|
-
|
-
|
|||||||
|
Pro
Forma Net Income for diluted earnings per share
|
$
|
719.9
|
$
|
145.4
|
$
|
3.1
|
||||
|
Basic
Earnings Per Share
|
||||||||||
|
As
Reported
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
||||
|
Pro
Forma
|
2.18
|
0.45
|
0.01
|
|||||||
|
Diluted
Earnings Per Share
|
||||||||||
|
As
Reported
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
||||
|
Pro
Forma
|
2.12
|
0.45
|
0.01
|
|||||||
The
above
pro forma amounts are not indicative of future pro forma results. The fair
value
of each option grant or modification under our long-term incentive plan was
estimated on the date of grant or grant modification using the
Black-Scholes-Merton option pricing model with the following weighted-average
assumptions used:
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Dividend
yield
|
-
|
-
|
-
|
|||||||
|
Expected
price volatility range
|
26%-38
|
%
|
38%-42
|
%
|
39%-45
|
%
|
||||
|
Risk-free
interest rate range
|
2.86%-4.57
|
%
|
2.59%-3.71
|
%
|
1.94%-3.16
|
%
|
||||
|
Expected
life of options (in years)
|
4.40
|
4.30
|
4.21
|
|||||||
|
Weighted-average
fair value of options granted or modified
|
$
|
21.92
|
$
|
10.65
|
$
|
7.13
|
||||
The
fair
value of each option grant under the ESPP was estimated using the following
weighted-average assumptions:
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Dividend
yield
|
-
|
-
|
-
|
|||||||
|
Expected
price volatility
|
28
|
%
|
27
|
%
|
41
|
%
|
||||
|
Risk-free
interest rate
|
2.81
|
%
|
1.19
|
%
|
1.09
|
%
|
||||
|
Expected
life of options
|
Less
than one year
|
Less
than one year
|
Less
than one year
|
|||||||
|
Weighted-average
fair value of options granted
|
$
|
7.10
|
$
|
4.10
|
$
|
4.69
|
||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
New
Accounting Pronouncements—In
May
2005, the FASB issued SFAS 154, “Accounting
Changes and Error Corrections,” which
requires retrospective application to all prior period financial statements
presented for voluntary changes in accounting principle unless it is
impracticable. This statement replaces APB 20, Accounting
Changes,
and
SFAS 3, Reporting
Accounting Changes in Interim Financial Statements,
though
it carries forward the guidance in those pronouncements with respect to
accounting for changes in estimates, changes in reporting entity and the
correction of errors. SFAS 154 is effective for accounting changes and
corrections of errors made in fiscal years beginning after December 15, 2005.
We
adopted SFAS 154 effective January 1, 2006. The adoption of this statement
will
have no impact on our consolidated financial position, results of operations
or
cash flows.
In
December 2004, the FASB issued SFAS 123 (revised 2004) (“SFAS
123(R)”), Share-Based
Payment,
which
is a revision of SFAS 123, Accounting
for Stock-Based Compensation.
SFAS
123(R) supersedes APB 25, Accounting
for Stock Issued to Employees,
and
amends SFAS 95, Statement
of Cash Flows.
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. We
adopted SFAS 123(R) effective January 1, 2006.
SFAS
123(R) permits adoption using one of two methods, a modified prospective method
(“Prospective Method”) or a modified retrospective method (“Retrospective
Method”). With the Prospective Method, costs are recognized beginning with the
effective date based on the requirements of SFAS 123(R) for (i) all share-based
payments granted after the effective date of SFAS 123(R), and (ii) all awards
granted to employees prior to the effective date of SFAS 123(R) that remain
unvested on the effective date. The Retrospective Method applies the
requirements of the Prospective Method but further permits entities to restate
all prior periods presented based on the amounts previously recognized under
SFAS 123 for purposes of pro forma disclosures. We elected to adopt SFAS 123(R)
using the Prospective Method.
We
previously adopted the fair-value-based method of accounting for share-based
payments under SFAS 123 effective January 1, 2003 using the modified prospective
method as described in SFAS 148, Accounting
for Stock-Based Compensation-Transition and Disclosure.
We
currently use the Black-Scholes-Merton formula to estimate the value of stock
options granted to employees, which is an acceptable share-based award valuation
model and we have chosen that model for determining fair value of stock awards
granted under SFAS 123(R). Our APB 25 options vested in the third quarter of
2005. As a result, adoption of SFAS 123(R) had no effect on these
options.
Since
we
adopted SFAS 123(R) using the Prospective Method, we do not expect the adoption
to have an 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 is currently required under SFAS 95. While
we
cannot estimate what these amounts will be in the future (because they depend
on, among other things, when employees exercise stock options), we reported
operating cash flows related to tax deduction benefits of $22.1 million, $5.9
million and $0.3 million for the years ended December 31, 2005, 2004 and 2003,
respectively.
Under
SFAS 123, we recognize the compensation cost over the vesting period up to
the
date of actual retirement. We will continue this practice for awards granted
prior to the adoption of SFAS 123(R). Upon the adoption of SFAS 123(R), we
will
recognize compensation cost for 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”). If we had amortized compensation cost over the
service period, the amount would not have been material for all periods
presented.
Reclassifications—Certain
reclassifications have been made to prior period amounts to conform with the
current year presentation.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
3—Accumulated Other Comprehensive Loss
The
components of accumulated other comprehensive loss at December 31, 2005, 2004
and 2003, net of tax, are as follows (in millions):
|
Gain
on
Terminated
Interest
Rate
Swaps
|
Unrealized
Loss
on
Available-
for-Sale
Securities
|
Other
Comprehensive
Loss
Related to
Unconsolidated
Joint
Venture
|
Minimum
Pension
Liability
|
Total
Other
Comprehensive
Income
(Loss)
|
||||||||||||
|
Balance
at December 31, 2002
|
$
|
3.6
|
$
|
(0.6
|
)
|
$
|
(2.0
|
)
|
$
|
(32.5
|
)
|
$
|
(31.5
|
)
|
||
|
Other
comprehensive income (loss)
|
(0.2
|
)
|
0.2
|
2.0
|
9.3
|
11.3
|
||||||||||
|
Balance
at December 31, 2003
|
3.4
|
(0.4
|
)
|
−
|
(23.2
|
)
|
(20.2
|
)
|
||||||||
|
Other
comprehensive income (loss)
|
(0.2
|
)
|
0.1
|
−
|
(4.1
|
)
|
(4.2
|
)
|
||||||||
|
Balance
at December 31, 2004
|
3.2
|
(0.3
|
)
|
−
|
(27.3
|
)
|
(24.4
|
)
|
||||||||
|
Other
comprehensive income (loss)
|
(0.3
|
)
|
0.3
|
−
|
4.0
|
4.0
|
||||||||||
|
Balance
at December 31, 2005
|
$
|
2.9
|
$
|
−
|
$
|
−
|
$
|
(23.3
|
)
|
$
|
(20.4
|
)
|
||||
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 $155.7
million from the TODCO IPO and recognized a gain of $39.4 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 stock
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 $5.6 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 $1.5 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 17.9
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 $269.9 million from the September 2004 Offering and recognized a gain of
$129.4 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 $258.0 million from the December 2004 Offering and recognized a gain of
$140.0 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 2 percent of TODCO’s total outstanding shares, at $23.57 per share
in the June Sale. We received net proceeds of $271.9 million from the 2005
Offering and Sale and recognized a gain in the second quarter of 2005 of $165.0
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
5—Capital Expenditures and Other Asset Acquisitions
Capital
expenditures totaled $181.9 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 semisubmersible rig M.G.
Hulme, Jr., which
we
had previously operated under a lease arrangement (see Note 17).
Capital
expenditures totaled $127.0 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 22).
Capital
expenditures totaled $493.8 million during the year ended December 31, 2003
and
included our acquisition of two Fifth-Generation Deepwater Floaters, the
Deepwater
Pathfinder
and
Deepwater
Frontier,
through
the payoff of synthetic lease financing arrangements totaling $382.8 million.
The remaining $111.0 million related to capital expenditures for existing fleet
and corporate infrastructure. A substantial majority of the capital expenditures
in 2003 related
to the
Transocean Drilling segment.
As
a
result of the R&B Falcon merger, we acquired ownership interests in two
unconsolidated joint ventures, 50 percent in Deepwater Drilling L.L.C. (“DD
LLC”) and 60 percent in Deepwater Drilling II L.L.C. (“DDII LLC”). Subsidiaries
of ConocoPhillips owned the remaining interests in these joint ventures. Each
of
the joint ventures was a lessee in a synthetic lease financing facility entered
into in connection with the construction of the Deepwater
Pathfinder,
in the
case of DD LLC, and the Deepwater
Frontier,
in the
case of DDII LLC. Pursuant to the lease financings, the rigs were owned by
special purpose entities and leased to the joint ventures.
In
May
2003, WestLB AG, one of the lenders in the Deepwater
Frontier
synthetic lease financing facility, assigned its $46.1 million remaining
promissory note receivable to us in exchange for cash of $46.1 million. Also
in
May 2003, but subsequent to the WestLB AG assignment, we purchased
ConocoPhillips’ 40 percent interest in DDII LLC for approximately $5.0 million.
As a result of this purchase, we consolidated DDII LLC late in the second
quarter of 2003. In addition, we acquired certain drilling and other contracts
from ConocoPhillips for approximately $9.0 million in cash. In December 2003,
DDII LLC prepaid the remaining $197.5 million debt and equity principal amounts
owed, plus accrued and unpaid interest, to us and other lenders under the
synthetic lease financing facility. As a result of this prepayment, DDII LLC
became the legal owner of the
Deepwater Frontier.
In
November 2003, we purchased the remaining 25 percent minority interest in the
Caspian Sea Ventures International Limited (“CSVI”) joint venture. CSVI owns the
jackup rig Trident
20 and
is
now a wholly owned subsidiary.
In
December 2003, we purchased ConocoPhillips’ 50 percent interest in DD LLC in
connection with the payoff of the
Deepwater Pathfinder synthetic
lease financing facility. As a result of this purchase, we consolidated DD
LLC
late in the fourth quarter of 2003. Concurrent with the purchase of this
ownership interest, DD LLC prepaid the remaining $185.3 million debt and equity
principal amounts owed, plus accrued and unpaid interest, to the lenders under
the synthetic lease financing facility. As a result of this prepayment, DD
LLC
became the legal owner of the Deepwater
Pathfinder.
Note
6—Asset Dispositions and Retirements
In
January 2005, we completed the sale of the semisubmersible rig Sedco
600
for net
proceeds of $24.9 million, of which $2.5 million was received in 2004, and
recognized a gain of $18.8 million ($0.06 per diluted share), which had no
tax
effect. At December 31, 2004, this asset was held for sale in the amount of
$5.6
million and was included in other current assets in our consolidated balance
sheet. See Note 2.
In
June
2005, we sold the jackup rig Transocean
Jupiter
and a
land rig for net proceeds of $23.5 million and recognized a gain on these sales
of $14.0 million ($9.1 million, or $0.03 per diluted share, net of
tax).
In
December 2005, we entered into an agreement to sell the drillship Peregrine
III
in
connection with our efforts to dispose of non-strategic assets. We received
a
deposit totaling $7.8 million, which was reflected as unearned income and
included in other current liabilities in our consolidated balance sheet at
December 31, 2005. At December 31, 2005, the rig was classified as an asset
held
for sale in the amount of $12.3 million, and was included in other current
assets in our consolidated balance sheet. See Notes 2 and 27.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
During
the year ended December 31, 2005, we sold and disposed of certain other assets
for net proceeds of approximately $18.4 million and we recorded net losses
of
$3.8 million ($4.1 million, or $0.01 per diluted share, net of
tax).
In
June
2004, we completed the sale of the Sedco
602 for
net
proceeds of $28.0 million and recognized a gain of $21.7 million ($0.07 per
diluted share), which had no tax effect, in our Transocean Drilling segment.
During
the year ended December 31, 2004, we settled insurance claims and sold and
disposed of marine support vessels and certain other assets for net proceeds
of
$22.4 million. We recorded net losses of $8.3 million ($3.5 million, or $0.01
per diluted share, net of tax) in our Transocean Drilling segment and net gains
of $5.8 million ($0.02 per diluted share), which had no tax effect, in our
TODCO
segment.
In
January 2003, we completed the sale of the jackup rig RBF
160
for net
proceeds of $13.1 million and recognized a gain of $0.3 million ($0.2 million,
net of tax) in our Transocean Drilling segment. The proceeds were received
in
December 2002.
During
the year ended December 31, 2003, we settled an insurance claim and sold and
disposed of certain other assets for net proceeds of approximately $8.4 million
and recorded net losses of $6.0 million ($4.5 million, or $0.01 per diluted
share, net of tax) in our Transocean Drilling segment and $7.7 million ($8.0
million, or $0.02 per diluted share, net of tax) in our TODCO
segment.
Note
7—Impairment Loss on Long-Lived Assets
During
the year ended December 31, 2003, we recorded non-cash impairment charges of
$5.2 million ($0.02 per diluted share), which had no tax effect, in our
Transocean Drilling segment associated with the removal of two rigs from
drilling service and the value assigned to leases on oil and gas properties
that
we intended to discontinue. The determination of fair market value was based
on
an offer from a potential buyer, in the case of the two rigs, and management’s
assessment of fair value, in the case of the leases on oil and gas properties
for which third party valuations were not available.
During
the year ended December 31, 2003, we recorded non-cash impairment charges of
$11.3 million ($7.4 million, or $0.02 per diluted share, net of tax) in our
TODCO segment associated with the removal of five jackup rigs from drilling
service and the write down in the value of an investment in a joint venture
to
fair value. The determination of fair market value was based on third party
valuations, in the case of the jackup rigs, and management’s assessment of fair
value, in the case of the investment in a joint venture for which third party
valuations were not available.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
8—Debt
Debt,
net
of unamortized discounts, premiums and fair value adjustments, is comprised
of
the following (in millions):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
7.31%
Nautilus Class A1 Amortizing Notes - final maturity May
2005
|
$
|
-
|
$
|
19.4
|
|||
|
6.95%
Senior Notes, due April 2008
|
-
|
263.1
|
|||||
|
6.625%
Notes, due April 2011
|
183.0
|
785.7
|
|||||
|
7.375%
Senior Notes, due April 2018
|
246.9
|
246.9
|
|||||
|
Zero
Coupon Convertible Debentures, due May 2020 (put options exercisable
May 2008 and May 2013)
|
17.5
|
17.0
|
|||||
|
1.5%
Convertible Debentures, due May 2021 (put options exercisable May
2006,
May 2011 and May 2016) (a)
|
400.0
|
400.0
|
|||||
|
8%
Debentures, due April 2027
|
56.8
|
56.8
|
|||||
|
7.45%
Notes, due April 2027 (put options exercisable April 2007)
|
95.3
|
95.0
|
|||||
|
7.5%
Notes, due April 2031
|
597.6
|
597.6
|
|||||
|
Total
Debt
|
1,597.1
|
2,481.5
|
|||||
|
Less
Debt Due Within One Year (a)
|
400.0
|
19.4
|
|||||
|
Total
Long-Term Debt
|
$
|
1,197.1
|
$
|
2,462.1
|
|||
|
(a)
|
The
1.5% Convertible Debentures are classified as debt due within one
year
since the holders can exercise their right to require us to repurchase
the
debentures in May 2006.
|
The
scheduled maturity of our debt assumes the bondholders exercise their rights
to
require us to repurchase the 1.5% Convertible Debentures, 7.45% Notes and Zero
Coupon Convertible Debentures in May 2006, April 2007 and May 2008,
respectively. The scheduled maturities 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):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
400.0
|
||
|
2007
|
100.0
|
|||
|
2008
|
19.0
|
|||
|
2009
|
-
|
|||
|
2010
|
-
|
|||
|
Thereafter
|
1,069.4
|
|||
|
Total
|
$
|
1,588.4
|
||
Revolving
Credit Agreement—
In July
2005, we entered into a $500.0 million, five-year revolving credit agreement
(the “Revolving Credit Agreement”). The Revolving Credit Agreement 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 Agreement
are greater than or equal to 50 percent of the total underlying commitment.
At
December 31, 2005, the applicable margin, facility fee and utilization fee
were
0.225 percent, 0.075 percent and 0.100 percent, respectively. The Revolving
Credit Agreement 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 Agreement, of not
greater than 60 percent. At December 31, 2005, no amount was outstanding under
the Revolving Credit Agreement.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
conjunction with entering into the Revolving Credit Agreement, we terminated
our
existing $800.0 million, five-year revolving credit agreement and recognized
a
loss on the termination of this agreement of $0.8 million, which had no tax
effect, in the third quarter of 2005.
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”). As a
result of the Exchange Offer, approximately $234.5 million, $342.3 million,
$247.8 million, $246.5 million, $76.9 million and $289.8 million principal
amount of TODCO’s outstanding 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior
Notes, respectively, were exchanged for our newly issued 6.5%, 6.75%, 6.95%,
7.375%, 9.125% and 9.5% Senior Notes having the same principal amount, interest
rate, redemption terms and payment and maturity dates. Because the holders
of a
majority in principal amount of each of these series of notes consented to
the
proposed amendments to the applicable indenture pursuant to which the notes
were
issued, some covenants, restrictions and events of default were eliminated
from
the indentures with respect to these series of notes. After the Exchange Offer,
approximately $5.0 million, $7.7 million, $2.2 million, $3.5 million, $10.2
million and $10.2 million principal amount of the outstanding 6.5%, 6.75%,
6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged remain
the obligation of TODCO. At December 31, 2005, $246.5 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). The 7.375% Senior Notes are redeemable at our option at a make-whole
premium. See
“―Retired, Redeemed and Repurchased Debt.”
6.625%
Notes and 7.5% Notes—In
April
2001, we issued $700.0 million aggregate principal amount of 6.625% Notes due
April 2011 and $600.0 million aggregate principal amount of 7.5% Notes due
April
2031. At December 31, 2005, $165.6 million principal amount of the 6.625% Notes
was outstanding (see “—Retired, Redeemed and Repurchased Debt”). At December 31,
2005, $600.0 million principal amount of the 7.5% Notes was outstanding with
a
discounted value of $597.6 million.
1.5%
Convertible Debentures—In
May
2001, we issued $400.0 million aggregate principal amount of 1.5% Convertible
Debentures due May 2021. We have the right to redeem the debentures after five
years 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. 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, 2005, $400.0 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
(see “—Retired, Redeemed and Repurchased Debt”). 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, 2005, $26.4 million
face value of these notes was outstanding with a discounted value of $17.5
million. Should all of the debentures be put to us in May 2008, the debentures
will have a discounted value of $19.0 million.
7.45%
Notes and 8% Debentures—In
April
1997, we issued $100.0 million aggregate principal amount of 7.45% Notes due
April 2027 and $200.0 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, 2005,
$100.0 million and $57.3 million principal amount of these notes was
outstanding, respectively (see “—Retired, Redeemed and Repurchased Debt”).
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Retired,
Redeemed and Repurchased Debt—In
July
2005, we acquired, pursuant to a tender offer, a total of $534.4 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 $590.9 million, plus
accrued and unpaid interest. In the third quarter of 2005, we recognized a
gain
on the redemption of debt of $0.2 million, which had no tax effect and reflected
adjustments for the unamortized fair value adjustment on a previously terminated
interest rate swap. We funded the repurchase with existing cash balances.
In
May
2005, we repaid the remaining principal amount outstanding of the 7.31% Nautilus
Class A1 amortizing note, plus accrued and unpaid interest, in accordance with
its scheduled maturity. We funded the repayment from existing cash balances.
In
March
2005, we redeemed our $247.8 million aggregate principal amount outstanding
6.95% Senior Notes due April 2008 at the make-whole premium price provided
in
the indenture. We redeemed these notes at 108.259 percent of face value, or
$268.2 million, plus accrued and unpaid interest. In the first quarter of 2005,
we recognized a loss on the redemption of debt of $6.7 million ($0.02 per
diluted share), which had no tax effect and reflected adjustments for fair
value
of the debt at the date of the R&B Falcon merger and the unamortized fair
value adjustment on a previously terminated interest rate swap. We funded the
redemption with existing cash balances.
In
December 2004, we acquired, pursuant to a tender offer, a total of $142.7
million, or approximately 71.3 percent, aggregate principal amount of our 8%
Debentures due April 2027 at 130.449 percent of face value, or $186.1 million,
plus accrued and unpaid interest. We recognized a loss on the repurchase of
$45.1 million ($0.14 per diluted share), which had no tax effect, in the fourth
quarter of 2004. We funded the repurchases with existing cash balances.
In
October 2004, we redeemed our $342.3 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 $349.5 million, plus accrued and unpaid interest. In the fourth quarter
of 2004, we recognized a loss on the redemption of $3.3 million ($0.01 per
diluted share), which had no tax effect and reflected adjustments for fair
value
of the debt at the date of the R&B Falcon merger and the unamortized fair
value adjustment on a previously terminated interest rate swap. We funded the
redemption with existing cash on hand, which included proceeds from the
September 2004 Offering.
In
March
2004, we redeemed our $289.8 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 $370.3
million, plus accrued and unpaid interest. In the first quarter of 2004, we
recognized a loss on the redemption of debt of $28.1 million ($0.09 per share),
which had no tax effect and reflected adjustments for fair value of the debt
at
the date of the R&B Falcon merger and the unamortized fair value adjustment
on a previously terminated interest rate swap. We funded the redemption with
existing cash balances, which included proceeds from the TODCO IPO.
In
May
2003, we repurchased and retired the entire $50.0 million principal amount
outstanding 9.41% Nautilus Class A2 Notes due May 2005 and funded the repurchase
from existing cash balances. We recognized a loss on retirement of debt of
$5.5
million ($3.6 million, or $0.01 per diluted share, net of tax), in the second
quarter of 2003.
In
May
2003, holders of our Zero Coupon Convertible Debentures due May 24, 2020 had
the
option to require us to repurchase their debentures. Holders of $838.6 million
aggregate principal amount, or approximately 97 percent, of these debentures
exercised this option, and we repurchased their debentures at a repurchase
price
of $628.57 per $1,000 principal amount. Under the terms of the debentures,
we
had the option to pay for the debentures with cash, our ordinary shares or
a
combination of cash and shares, and we elected to pay the $527.2 million
repurchase price from existing cash balances. We recognized additional expense
of $10.2 million ($0.03 per diluted share), which had no tax effect, as a loss
on retirement of debt in the second quarter of 2003 to fully amortize the
remaining debt issue costs related to the repurchased debentures.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
9—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, 2005 and 2004, we had no open 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.
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, 2005 and 2004.
See Note 10.
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 22. 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, 2005, we had approximately 9,500 employees and we also utilized
approximately 2,100 persons through contract labor providers. As of such date,
approximately 14 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, virtually all are working under
agreements that are subject to salary negotiation in 2006.
Note
10—Interest
Rate Swaps
In
June
2001, we entered into interest rate swap agreements in the aggregate notional
amount of $700.0 million with a group of banks relating to our $700.0 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 $900.0 million relating to our $350.0 million
aggregate principal amount of 6.75% Senior Notes due April 2005, $250.0 million
aggregate principal amount of 6.95% Senior Notes due April 2008 and $300.0
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.
In
January 2003, we terminated all our outstanding interest rate swaps, which
were
designated as fair value hedges, and recorded $173.5 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, 2005, 2004
and
2003, such reduction amounted to $9.1 million ($0.03. per diluted share), $22.7
million ($0.07 per diluted share) and $23.1 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 $13.2 million ($0.08 per diluted share) and $25.5 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 8). As a result of the repurchase of our 6.625%
Notes in July 2005, we recognized $62.0 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 8). There were no tax effects related to
these
reductions. The remaining balance to be amortized at December 31, 2005 of $17.9
million relates to the 6.625% Notes due April 2011.
At
December 31, 2005 and 2004, we had no outstanding interest rate swaps.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
11—Fair
Value of Financial Instruments
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 trade receivables—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.
|
December
31, 2005
|
December
31, 2004
|
||||||||||||
|
Carrying
Amount
|
Fair
Value
|
Carrying
Amount
|
Fair
Value
|
||||||||||
|
(in
millions)
|
(in
millions)
|
||||||||||||
|
Cash
and cash equivalents
|
$
|
445.4
|
$
|
445.4
|
$
|
451.3
|
$
|
451.3
|
|||||
|
Trade
receivables
|
582.5
|
582.5
|
426.5
|
426.5
|
|||||||||
|
Debt
|
1,597.1
|
1,865.3
|
2,481.5
|
2,702.5
|
|||||||||
Note
12—Other
Current Liabilities
Other
current liabilities are comprised of the following (in millions):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Accrued
payroll and employee benefits
|
$
|
120.5
|
$
|
98.1
|
|||
|
Deferred
revenue
|
42.9
|
50.7
|
|||||
|
Unearned
income
|
30.5
|
2.5
|
|||||
|
Accrued
interest
|
19.0
|
30.2
|
|||||
|
Accrued
taxes, other than income
|
17.4
|
14.4
|
|||||
|
Reserves
for contingent liabilities
|
1.6
|
1.2
|
|||||
|
Other
|
10.2
|
15.9
|
|||||
|
Total
Other Current Liabilities
|
$
|
242.1
|
$
|
213.0
|
|||
Note
13—Other
Long-Term Liabilities
Other
long-term liabilities are comprised of the following (in millions):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Reserves
for contingent liabilities
|
$
|
116.4
|
$
|
194.9
|
|||
|
Accrued
pension and early retirement
|
64.9
|
54.0
|
|||||
|
Accrued
retiree life insurance and medical benefits
|
36.3
|
35.4
|
|||||
|
Deferred
revenue
|
16.1
|
19.1
|
|||||
|
Other
|
52.5
|
41.8
|
|||||
|
Total
Other Long-Term Liabilities
|
$
|
286.2
|
$
|
345.2
|
|||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
14—Repurchase
of Ordinary Shares
In
October 2005, our board of directors authorized the repurchase of up to $2
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 December 2005, we repurchased from an investment bank and
retired $400 million of our ordinary shares, which amounted to approximately
6.0
million ordinary shares at $66.50 per share. Total consideration paid to
repurchase the shares of approximately $400 million was recorded in
shareholders’ equity as a reduction in ordinary shares and additional paid-in
capital. Such consideration was funded with existing cash balances.
Note
15—Supplementary
Cash Flow Information
Non-cash
investing activities for the years ended December 31, 2005, 2004 and 2003
included $30.5 million, $9.7 million and $8.9 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 $128.5 million, $201.2 million and $219.0 million
for
the years ended December 31, 2005, 2004 and 2003, respectively. Cash payments
for income taxes, net, were $107.2 million, $75.1 million and $73.4 million
for
the years ended December 31, 2005, 2004 and 2003, respectively.
Note
16—Income
Taxes
We
are a
Cayman Islands company registered in Barbados, 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.
The
components of the provision (benefit) for income taxes are as follows (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Current
provision
|
$
|
59.7
|
$
|
73.2
|
$
|
101.5
|
||||
|
Deferred
provision (benefit)
|
27.1
|
18.1
|
(98.5
|
)
|
||||||
|
Income
tax provision before cumulative effect of a change in accounting
principle
|
$
|
86.8
|
$
|
91.3
|
$
|
3.0
|
||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Significant
components of deferred tax assets and liabilities are as follows (in
millions):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Deferred
Tax Assets
|
|||||||
|
Tax
credit carryforwards
|
$
|
100.5
|
$
|
166.7
|
|||
|
Net
operating loss carryforwards
|
85.1
|
121.0
|
|||||
|
Retirement
and benefit plan accruals
|
19.0
|
3.8
|
|||||
|
Unearned
income
|
13.4
|
5.0
|
|||||
|
Other
accruals
|
12.3
|
15.0
|
|||||
|
Accrued
workers' compensation insurance
|
5.0
|
0.5
|
|||||
|
Incentive
compensation
|
4.0
|
7.1
|
|||||
|
Accrued
personnel taxes
|
2.4
|
0.6
|
|||||
|
Deferred
revenue and other
|
1.8
|
2.2
|
|||||
|
Insurance
accruals
|
1.0
|
9.1
|
|||||
|
Valuation
allowance
|
(48.5
|
)
|
(115.3
|
)
|
|||
|
Total
Deferred Tax Assets
|
196.0
|
215.7
|
|||||
|
Deferred
Tax Liabilities
|
|||||||
|
Depreciation
and amortization
|
(222.1
|
)
|
(255.8
|
)
|
|||
|
Other
liabilities
|
(5.4
|
)
|
(3.7
|
)
|
|||
|
Deferred
drydock costs
|
(5.2
|
)
|
(3.3
|
)
|
|||
|
Asset
held for sale
|
(4.6
|
)
|
-
|
||||
|
Investment
in subsidiaries
|
(0.3
|
)
|
(14.2
|
)
|
|||
|
Total
Deferred Tax Liabilities
|
(237.6
|
)
|
(277.0
|
)
|
|||
|
Net
Deferred Tax Liabilities
|
$
|
(41.6
|
)
|
$
|
(61.3
|
)
|
|
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.
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, 2005, the valuation allowance for non-current
deferred tax assets decreased $66.8 million, which resulted primarily from
the
utilization of the underlying deferred tax assets to offset current year income
and in the settlement of audits, in addition to adjustments related to the
restructuring of certain of our non-U.S. operations. In the year ended December
31, 2004, the valuation allowance decreased $66.5 million.
Our
U.S.
net operating loss carryforwards expire between 2020 and 2025. The tax effect
of
the U.S. net operating loss carryforwards, net of valuation allowances of $0.6
million, was $24.2 million at December 31, 2005. Our U.K. net operating loss
carryforwards do not expire. The tax effect of the U.K. net operating loss
carryforwards was $60.3 million at December 31, 2005. In 2005, we released
the
valuation allowance of $16.8 million on our U.K. net operating loss
carryforwards to record the expected realization of those losses through future
earnings based on improved market conditions and taking into account tax
planning strategies. Our U.S. foreign tax credit carryforwards of $50.2 million,
net of valuation allowances of $46.9 million, will expire between 2009 and
2015.
Our U.S. alternative minimum tax credits of $3.4 million do not
expire.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 years
ended December 31, 2005 and 2004, we recognized benefits of $70.7 million and
$72.9 million, respectively, to record the utilization of the capital loss
carryforwards to offset capital gain income resulting from certain restructuring
transactions. Certain payments from TODCO under the tax sharing agreement
also serve to reduce the capital loss carryforward. Should an opportunity to
utilize the remaining capital loss arise, the total potential tax benefit at
December 31, 2005 was $837.5 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, 2005 was $17.5
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.
On
October 22, 2004, the American Jobs Creation Act of 2004 (the “Act”) was signed
into law. The applicable provisions of the Act did not have a material effect
on
our tax provision in 2005.
Transocean
Inc., a Cayman Islands company, is not subject to income taxes in the Cayman
Islands. For the three years ended December 31, 2005, 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 non-U.S.
assessments. We accrue for income tax contingencies that we believe are probable
exposures. While we cannot predict or provide assurance as to the final outcome,
we do not expect the liability, if any, resulting from existing or future
assessments to have a material adverse effect on our consolidated financial
position, results of operations or cash flows.
During
the fourth quarter of 2005, we entered into a settlement agreement with the
U.S.
Internal Revenue Service (“IRS”) with respect to our 1999 and 2000 U.S. federal
income tax returns, which resulted in a payment of $36.2 million including
interest. The IRS agreed to settle all issues for this period and reduce
its original tax assessment of approximately $195 million, exclusive of
interest, to $25.5 million, exclusive of interest. This settlement did not
result in a material effect on our consolidated financial position, results
of
operations or cash flows.
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 $43.0
million in goodwill during the year ended December 31, 2005. We also recognized
an income tax benefit of $48.7 million during the year ended December 31, 2005
related to post-acquisition tax contingencies. These adjustments resulted from
the resolution of income tax audits in several jurisdictions.
Our
2002
and 2003 U.S. federal income tax returns are currently under examination by
the
IRS and our 2001 U.S. federal income tax returns remain open for examination.
No
examination report has been received at this time. While we cannot predict
or
provide assurance as to the final outcome, we do not expect the liability,
if
any, resulting from the proposed changes to have a material adverse effect
on
our consolidated financial position, results of operations or cash
flows
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
September 2004, the Norwegian tax authorities initiated inquiries related to
a
restructuring transaction undertaken in 2001 and 2002 and a 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. During 2005,
we
have continued to respond to information requests from the Norwegian
authorities. Based on these inquiries, we believe the Norwegian authorities
are
contemplating a tax assessment of approximately $96.4 million on the dividend,
based on exchange rates in effect at December 31, 2005, plus penalty and
interest. No assessment has been made, and we believe such an assessment
would be without merit. While we cannot predict or provide assurance as to
the
final outcome, we do not expect the liability, if any, resulting from the
inquiry to have a material adverse 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 $32.9
million.
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 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 $167.1 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.
We are involved in an arbitration proceeding with TODCO in which we are seeking
payment of these amounts, and TODCO is seeking, in this proceeding as well
as in
a lawsuit, to void the entire tax sharing agreement. We believe TODCO owes
us
the disputed payments and do not believe TODCO’s attempts to void the tax
sharing agreement have merit. See Note 18.
During
the year ended December 31, 2005, we received $32.0 million in payments from
TODCO related to TODCO’s expected utilization of such tax benefits for the 2004
and 2005 tax years. Of the $32.0 million received, $11.4 million and $20.6
million was received for the 2004 tax year and a portion of the 2005 tax year,
respectively. Included in the 2005 payments are $1.7 million relating to stock
options deductions. In 2005, TODCO filed its 2004 U.S. federal and state income
tax returns and we recognized $11.4 million as other income in our consolidated
income statement. The amounts received pertaining to TODCO’s 2005 federal and
state income tax returns, as well as payments received related to stock options
deductions, were 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 2005 federal and state income tax returns and
the
dispute with TODCO is resolved.
Estimated
tax benefits in excess of $300 million remain to be utilized by TODCO under
the
tax sharing agreement, although the ultimate amount and timing of the
utilization is highly contingent on a variety of factors including potential
revisions to the tax benefits upon examination by the IRS, which is currently
reviewing our 2002 and 2003 tax years, the amount of taxable income that TODCO
realizes in future years and the resolution of the dispute with TODCO related
to
the tax sharing agreement.
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),
we
established an initial valuation allowance in the first quarter of 2004 of
$31.0
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
connection with the distribution of Sedco Forex to the Schlumberger Limited
(“Schlumberger”) shareholders in December 1999, Sedco Forex and Schlumberger
entered into a tax separation agreement. In accordance with the terms of the
tax
separation agreement, Schlumberger agreed to indemnify Sedco Forex for any
tax
liabilities incurred directly in connection with the preparation of Sedco Forex
for this distribution. In addition, Schlumberger agreed to indemnify Sedco
Forex
for tax liabilities associated with Sedco Forex operations conducted through
Schlumberger entities prior to the distribution and any tax liabilities
associated with Sedco Forex assets retained by Schlumberger.
We
were
included in the consolidated federal income tax returns filed by a former
parent, Sonat Inc. (“Sonat”) during all periods in which Sonat's ownership was
greater than or equal to 80 percent through 1993 (“Affiliation Years”).
Transocean and Sonat entered into a tax sharing agreement providing for the
manner of determining payments with respect to federal income tax liabilities
and benefits arising in the Affiliation Years. Under the tax sharing agreement,
we will pay to Sonat an amount equal to our share of the Sonat consolidated
federal income tax liability, generally determined on a separate return basis.
In addition, Sonat will pay us for Sonat's utilization of deductions, losses
and
credits that are attributable to us and in excess of that which would be
utilized on a separate return basis.
Note
17—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 $4.6 million, $12.7 million and $12.5 million of such rent expense
for
the years ended December 31, 2005, 2004 and 2003, respectively. In May 2005,
we
purchased the rig for $42.5 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
(“FIN”) 46, Consolidation
of Variable Interest Entities,
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
18—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, 2005, future minimum rental payments related
to noncancellable operating leases are as follows (in millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
18.0
|
||
|
2007
|
12.1
|
|||
|
2008
|
8.7
|
|||
|
2009
|
5.9
|
|||
|
2010
|
4.7
|
|||
|
Thereafter
|
1.4
|
|||
|
Total
|
$
|
50.8
|
||
Rental
expense for all operating leases, including leases with terms of less than
one
year, was approximately $30 million, $40 million and $51 million for the years
ended December 31, 2005, 2004 and 2003, respectively.
Purchase
Obligations—At
December 31, 2005, our purchase obligations as defined by SFAS 47, Disclosure
of Long-Term Obligations (as amended),
related
to our two Sedco
700-series
upgrade shipyard projects are as follows (in millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
108.7
|
|
|
|
2007
|
65.1
|
|
||
|
Total
|
$
|
173.8
|
|
|
Legal
Proceedings¾ Several
of our subsidiaries have been named, along with other defendants, in several
complaints that have been filed in the Circuit Courts of the State of
Mississippi 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 and other unaffiliated
defendant companies, including companies that allegedly manufactured drilling
related products containing asbestos that are the subject of the complaints.
The
number of unaffiliated defendant companies involved in each complaint ranges
from approximately 20 to 70. 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 seek, among other things, awards of unspecified compensatory
and punitive damages. The trial court has ordered that the plaintiffs provide
additional information regarding their employment histories. We have not yet
had
an opportunity to conduct extensive discovery nor have we been able to
definitively 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, however, and have an action to stay execution of a related tax
foreclosure proceeding. We expect that the government will attempt to enforce
the judgment on this assessment and that the amount claimed may exceed the
amounts we believe are at issue. We received a favorable ruling in connection
with a disputed August 1990 assessment and the government has lost what we
expect 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 these 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
Indian Customs Department, Mumbai, filed a "show cause notice" against one
of
our subsidiaries and various third parties in July 1999. The show cause notice
alleged 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 issued its order, which found that we had imported the rig
improperly and intentionally concealed the import from the authorities, and
directed us to pay a redemption fee of approximately $3 million for the rig
in
lieu of confiscation and to pay penalties of approximately $1 million in
addition to the amount of customs duties owed. In February 2000, we filed an
appeal with the Customs, Excise and Service Tax Appellate Tribunal (“CESTAT”)
together with an application to have the confiscation of the rig stayed pending
the outcome of the appeal. In March 2000, the CESTAT ruled on the stay
application, directing that the confiscation be stayed pending the appeal.
The
CESTAT issued its order on our appeal on February 2, 2001, and while it found
that the rig was imported in 1988 without proper documentation or payment of
duties, the redemption fee and penalties were reduced to less than $0.1 million
in view of the ambiguity surrounding the import practice at the time and the
lack of intentional concealment by us. The CESTAT further sustained our position
regarding the value 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 in view of the prevailing practice of the Customs Department, thus
limiting our exposure as to custom duties to approximately $6 million. Although
CESTAT did not grant us the benefit of a customs duty exemption due to the
absence of the required documentation, CESTAT left it open for our subsidiary
to
seek such documentation from the Ministry of Petroleum. Following the CESTAT
order, we tendered payment of redemption, penalty and duty in the amount
specified by the order by offset against a $0.6 million deposit and $10.7
million guarantee previously made by us. The Customs Department attempted to
draw the entire guarantee, alleging the actual duty payable is approximately
$22
million based on an interpretation of the CESTAT order that we believe is
incorrect. This action was stopped by an interim ruling of the High Court,
Mumbai on writ petition filed by us. We and the Customs Department both filed
appeals with the Supreme Court of India against the order of the CESTAT, and
both appeals were admitted. The Supreme Court has dismissed the Customs
Department appeal and affirmed the CESTAT order 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 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.
In
October 2001, TODCO was notified by the U.S. Environmental Protection Agency
("EPA") that the EPA had identified a subsidiary as a potentially responsible
party in connection with the Palmer Barge Line superfund site located in Port
Arthur, Texas. Based upon the information provided by the EPA and a review
of
TODCO's internal records to date, TODCO disputes its designation as a
potentially responsible party. Pursuant to the master separation agreement
with
TODCO, we are responsible and will indemnify TODCO for any losses TODCO incurs
in connection with this action. 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
August
2003, a judgment of approximately $9.5 million was entered by the Labor Division
of the Provincial Court of Luanda, Angola, against us and one of our labor
contractors, Hull Blyth, in favor of certain former workers on several of our
drilling rigs. The workers were employed by Hull Blyth to work on several
drilling rigs while the rigs were located in Angola. When the drilling contracts
concluded and the rigs left Angola, the workers' employment ended. The workers
brought suit claiming that they were not properly compensated when their
employment ended. In addition to the monetary judgment, the Labor Division
ordered the workers to be hired by us. We believe that this judgment is without
sufficient legal foundation and have appealed the matter to the Angola Supreme
Court. We further believe that Hull Blyth has an obligation to protect us from
any judgment. 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
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.
We
have a
dispute with TODCO concerning payment to us under our tax sharing agreement
with
TODCO for the tax benefit that TODCO derives from exercises of options to
purchase our ordinary shares held by employees of TODCO. An arbitration
proceeding was initiated in January 2006, and the parties are in the process
of
appointing an arbitrator. We are 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. TODCO is seeking to avoid such payment and is asking that the entire
tax
sharing agreement be voided. TODCO also filed suit in Houston in the district
court of the State of Texas in January 2006 seeking to set aside the arbitration
provision and to void the entire tax sharing agreement. We believe TODCO owes
us
approximately $10.7 million based on options exercised through December 31,
2005, and we do not believe TODCO’s attempts to void the tax sharing agreement
have merit. We do not expect the outcome of this matter 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, 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.
Self
Insurance—We
are
self-insured for the deductible portion of our insurance coverage. In the
opinion of management, adequate accruals have been made based on known and
estimated exposures up to the deductible portion of our insurance coverages.
Management believes that claims and liabilities in excess of the amounts accrued
are adequately insured.
Letters
of Credit and Surety Bonds—We
had
letters of credit outstanding totaling $313.8 million and $182.2 million at
December 31, 2005 and 2004, 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
$8.0 million and $7.6 million at December 31, 2005 and 2004, respectively.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
19—Stock-Based
Compensation Plans
Long-Term
Incentive Plan—We
have
a long-term incentive plan for key employees and outside directors (the
“Incentive Plan”). Prior to 2003, we accounted for our Incentive Plan under APB
25 and related interpretations. Effective January 1, 2003, we have adopted
the
fair value recognition provisions of SFAS 123 using the prospective method.
Under the prospective method and in accordance with the provisions of SFAS
148
(see Note 2), the recognition provisions are applied to all employee awards
granted, modified, or settled after January 1, 2003.
Under
the
Incentive Plan, awards can be granted in the form of stock options, nonvested
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 vest
in
three equal annual installments from the date of grant. Performance-based awards
issued to date under the Incentive Plan have a two-year performance cycle with
the number of options, shares or deferred units earned being determined
following the completion of the performance cycle (the “determination date”) at
which time one-third of the options, shares or deferred units are vested.
Additional vesting occurs December 31 of the two subsequent years following
the
determination date.
As
of
December 31, 2005, we were authorized under the Incentive Plan to grant up
to
(i) 22.9 million ordinary shares to employees; (ii) 0.6 million shares to
outside directors; and (iii) 6.0 million restricted shares to employees. On
December 31, 1999, all unvested stock options and SARs and all nonvested
restricted shares granted after April 1996 became fully vested as a result
of
the Sedco Forex merger. At December 31, 2005, there were approximately 9.2
million and 0.2 million total shares available to employees and outside
directors, respectively, for future grants under the Incentive Plan, assuming
the 1.5 million performance-based stock options, unvested restricted share
and
deferred unit awards that could be issued at December 31, 2005 are ultimately
issued at the maximum amount.
Prior
to
the Sedco Forex merger, key employees of Sedco Forex were granted stock options
at various dates under the Schlumberger stock option plans. For all of the
stock
options granted under such plans, the exercise price of each option equaled
the
market price of Schlumberger stock on the date of grant, each option's maximum
term was 10 years and the options generally vested in 20 percent increments
over
five years. Fully vested Schlumberger options held by Sedco Forex employees
at
the date of the spin-off will lapse in accordance with their provisions.
Non-vested Schlumberger options were terminated and fully vested stock options
to purchase our ordinary shares were granted under a new plan.
Prior
to
the R&B Falcon merger, certain employees and outside directors of R&B
Falcon and its subsidiaries were granted stock options under various plans.
As a
result of the R&B Falcon merger, we assumed all outstanding R&B Falcon
stock options and converted them into options to purchase our ordinary shares.
As
a
result of the TODCO IPO (see Note 4), all unvested stock options to purchase
our
ordinary shares held by TODCO employees were fully vested.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Time-Based
Vesting Awards
The
following table summarizes time-based vesting stock option
activity:
|
Number
of Shares
Under
Option
|
Weighted-Average
Exercise
Price
|
||||||
|
Outstanding
at December 31, 2002
|
15,377,586
|
$
|
28.03
|
||||
|
Granted
|
314,860
|
20.95
|
|||||
|
Exercised
|
(149,361
|
)
|
10.97
|
||||
|
Forfeited
|
(267,684
|
)
|
35.47
|
||||
|
Outstanding
at December 31, 2003
|
15,275,401
|
27.92
|
|||||
|
Exercised
|
(1,153,857
|
)
|
18.59
|
||||
|
Forfeited
|
(149,845
|
)
|
35.74
|
||||
|
Outstanding
at December 31, 2004
|
13,971,699
|
28.60
|
|||||
|
Granted
|
53,450
|
41.38
|
|||||
|
Exercised
|
(7,695,838
|
)
|
28.01
|
||||
|
Forfeited
|
(16,604
|
)
|
34.47
|
||||
|
Outstanding
at December 31, 2005
|
6,312,707
|
$
|
29.43
|
||||
|
Exercisable
at December 31, 2003
|
13,091,737
|
$
|
27.53
|
||||
|
Exercisable
at December 31, 2004
|
13,195,638
|
$
|
28.77
|
||||
|
Exercisable
at December 31, 2005
|
6,127,710
|
$
|
29.16
|
||||
The
following table summarizes information about time-based vesting stock options
outstanding at December 31, 2005:
|
Weighted-Average
|
Options
Outstanding
|
Options
Exercisable
|
|||||||||||||||||
|
Range
of
Exercise
Prices
|
Remaining
Contractual
Life
|
Number
Outstanding
|
Weighted-Average
Exercise
Price
|
Number
Exercisable
|
Weighted-Average
Exercise
Price
|
||||||||||||||
|
$12.12
- $19.86
|
3.21
|
years |
1,382,982
|
$
|
15.13
|
1,368,982
|
$
|
15.08
|
|||||||||||
|
$20.12
- $33.69
|
4.81
|
years |
2,589,541
|
$
|
26.23
|
2,422,903
|
$
|
26.58
|
|||||||||||
|
$34.63
- $81.78
|
4.47
|
years |
2,340,184
|
$
|
41.41
|
2,335,825
|
$
|
41.38
|
|||||||||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
following table summarizes time-based vesting nonvested restricted ordinary
shares activity under the Incentive Plan:
|
Number
of Nonvested
Restricted
Ordinary
Shares
|
Weighted-Average
Price
|
||||||
|
Outstanding
at December 31, 2002
|
35,341
|
$
|
34.50
|
||||
|
Granted
|
21,000
|
20.65
|
|||||
|
Distributed
|
(14,981
|
)
|
35.27
|
||||
|
Outstanding
at December 31, 2003
|
41,360
|
27.19
|
|||||
|
Granted
|
8,281
|
28.12
|
|||||
|
Distributed
|
(21,519
|
)
|
30.52
|
||||
|
Forfeited
|
(1,547
|
)
|
32.60
|
||||
|
Outstanding
at December 31, 2004
|
26,575
|
24.58
|
|||||
|
Granted
|
35,230
|
49.01
|
|||||
|
Distributed
|
(14,359
|
)
|
25.51
|
||||
|
Forfeited
|
(506
|
)
|
49.42
|
||||
|
Outstanding
at December 31, 2005
|
46,940
|
$
|
42.36
|
||||
The
following table summarizes time-based vesting SARs activity under the Incentive
Plan:
|
Number
of Shares
Under
Option
|
Weighted-Average
Exercise
Price
|
||||||
|
Outstanding
at December 31, 2002
|
145,364
|
$
|
32.61
|
||||
|
Forfeited
|
(9,946
|
)
|
34.01
|
||||
|
Outstanding
at December 31, 2003
|
135,418
|
32.51
|
|||||
|
Exercised
|
(666
|
)
|
28.80
|
||||
|
Forfeited
|
(2,427
|
)
|
35.52
|
||||
|
Outstanding
at December 31, 2004
|
132,325
|
32.47
|
|||||
|
Exercised
|
(80,782
|
)
|
35.60
|
||||
|
Forfeited
|
(567
|
)
|
28.80
|
||||
|
Outstanding
at December 31, 2005
|
50,976
|
$
|
35.43
|
||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
following table summarizes time-based vesting deferred units activity under
the
Incentive Plan. 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.
|
Number
of Units
|
Weighted-Average
Price
|
||||||
|
Granted
|
20,538
|
$
|
27.17
|
||||
|
Forfeited
|
(2,282
|
)
|
27.17
|
||||
|
Outstanding
at December 31, 2004
|
18,256
|
27.17
|
|||||
|
Granted
|
18,600
|
45.02
|
|||||
|
Outstanding
at December 31, 2005
|
36,856
|
$
|
36.18
|
||||
Performance-Based
Awards
There
was
no performance-based award activity prior to 2003. None of these awards were
exercisable at December 31, 2003 and 2004. The following table summarizes
performance-based stock option activity under the Incentive Plan:
|
Number
of Shares
Under
Option
|
Weighted-Average
Exercise
Price
|
||||||
|
Granted
|
725,350
|
$
|
21.20
|
||||
|
Forfeited
|
(39,019
|
)
|
21.20
|
||||
|
Outstanding
at December 31, 2003
|
686,331
|
21.20
|
|||||
|
Granted
|
544,273
|
28.12
|
|||||
|
Forfeited
|
(13,290
|
)
|
21.20
|
||||
|
Outstanding
at December 31, 2004
|
1,217,314
|
24.29
|
|||||
|
Granted
|
324,714
|
56.34
|
|||||
|
Exercised
|
(91,423
|
)
|
21.20
|
||||
|
Forfeited
|
(197,480
|
)
|
21.99
|
||||
|
Outstanding
at December 31, 2005
|
1,253,125
|
$
|
33.19
|
||||
|
Exercisable
at December 31, 2005
|
74,590
|
$
|
21.20
|
||||
The
following table summarizes information about performance-based stock options
outstanding at December 31, 2005:
|
Options
Outstanding
|
Options
Exercisable
|
||||||||||||||||||
|
Year
of Grant
|
Remaining
Contractual
Life
|
Number
Outstanding
|
Exercise
Price
|
Number
Exercisable
|
Exercise
Price
|
||||||||||||||
|
2003
|
7.52
|
years |
406,629
|
$
|
21.20
|
74,590
|
$
|
21.20
|
|||||||||||
|
2004
|
8.55
|
years |
521,782
|
$
|
28.12
|
-
|
$
|
28.12
|
|||||||||||
|
2005
|
9.53
|
years |
324,714
|
$
|
56.34
|
-
|
$
|
56.34
|
|||||||||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
During
2005, 2004 and 2003, we granted performance-based nonvested restricted ordinary
shares and deferred unit awards that are earnable based on the achievement
of
certain performance targets. The number of shares to be issued is quantified
upon completion of the performance period at the determination date. At December
31, 2005, 2004 and 2003, the maximum number of nonvested restricted ordinary
shares and deferred units that could be issued at the determination date was
1.5
million, 1.5 million and 0.8 million, respectively. The following table
summarizes performance-based nonvested restricted ordinary share awards
activity:
|
Number
of Nonvested
Restricted
Ordinary
Shares
|
Weighted-Average
Price
|
||||||
|
Granted
|
890,073
|
$
|
21.20
|
||||
|
Forfeited
|
(55,655
|
)
|
21.20
|
||||
|
Outstanding
at December 31, 2003
|
834,418
|
21.20
|
|||||
|
2003
performance-based nonvested restricted ordinary shares converted
to
deferred units
|
(56,936
|
)
|
21.20
|
||||
|
Granted
|
645,604
|
28.12
|
|||||
|
Forfeited
|
(45,066
|
)
|
22.74
|
||||
|
Outstanding
at December 31, 2004
|
1,378,020
|
24.39
|
|||||
|
Granted
|
377,772
|
57.90
|
|||||
|
Distributed
|
(272,916
|
)
|
21.20
|
||||
|
Forfeited
|
(240,047
|
)
|
22.93
|
||||
|
Outstanding
at December 31, 2005
|
1,242,829
|
$
|
35.56
|
||||
The
following table summarizes the performance-based nonvested deferred
units:
|
Number
of Nonvested
Restricted
Ordianry
Shares
|
Weighted-Average
Price
|
||||||
|
2003
performance-based nonvested restricted ordinary shares converted
to
deferred units
|
56,936
|
$
|
21.20
|
||||
|
Granted
|
54,747
|
28.12
|
|||||
|
Outstanding
at December 31, 2004
|
111,683
|
24.59
|
|||||
|
|
|||||||
|
Granted
|
10,189
|
57.90
|
|||||
|
Distributed
|
(15,219
|
)
|
21.20
|
||||
|
Forfeited
|
(15,315
|
)
|
22.93
|
||||
|
Outstanding
at December 31, 2005
|
91,338
|
$
|
29.15
|
||||
Employee
Stock Purchase Plan—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 $25,000 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, 2005, 1,139,089 ordinary shares were available for issuance
pursuant to the ESPP after taking into account the shares to be issued for
the
2005 plan year.
Note
20—Retirement
Plans, Other Postemployment Benefits and Other Benefit Plans
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
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 “Nigeria Plan” and the
“Egypt Plan”) that provide retirement and severance benefits for certain of our
Nigerian and Egyptian employees. The defined benefit pension benefits we provide
are comprised of the U.S. Plans, the Norway Plans, the Nigeria Plan and the
Egypt Plan (collectively, the “Transocean Plans”). For all plans, we 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 and funded status
is shown in the table below (in millions):
|
December
31,
|
||||||||||
|
2005
|
2004
|
|||||||||
|
Change
in projected benefit obligation
|
||||||||||
|
Projected
benefit obligation at beginning of year
|
$
|
327.6
|
(a)
|
|
$
|
295.5
|
||||
|
Service
cost
|
18.0
|
16.7
|
||||||||
|
Interest
cost
|
17.6
|
16.7
|
||||||||
|
Actuarial
losses (gains)
|
(3.5
|
)
|
13.9
|
|||||||
|
Foreign
currency exchange rate changes
|
(3.7
|
)
|
5.7
|
|||||||
|
Settlements
/ curtailments
|
(2.1
|
)
|
-
|
|||||||
|
Plan
amendments
|
-
|
(4.5
|
)
|
|||||||
|
Benefits
paid
|
(18.0
|
)
|
(17.8
|
)
|
||||||
|
Projected
benefit obligation at end of year
|
$
|
335.9
|
$
|
326.2
|
||||||
|
Change
in plan assets
|
||||||||||
|
Fair
value of plan assets at beginning of year
|
$
|
236.6
|
$
|
214.4
|
||||||
|
Actual
return on plan assets
|
17.5
|
22.6
|
||||||||
|
Employer
contributions
|
5.6
|
13.7
|
||||||||
|
Actuarial
losses
|
2.5
|
-
|
||||||||
|
Foreign
currency exchange rate changes
|
(2.7
|
)
|
3.7
|
|||||||
|
Benefits
paid
|
(18.0
|
)
|
(17.8
|
)
|
||||||
|
Fair
value of plan assets at end of year
|
$
|
241.5
|
$
|
236.6
|
||||||
|
Funded
status
|
$
|
(94.4
|
)
|
$
|
(89.6
|
)
|
||||
|
Unrecognized
transition (asset) obligation
|
(3.0
|
)
|
2.5
|
|||||||
|
Unrecognized
net actuarial loss
|
74.6
|
80.5
|
||||||||
|
Unrecognized
prior service cost
|
(2.2
|
)
|
(2.0
|
)
|
||||||
|
Accrued
pension liability
|
$
|
(25.0
|
)
|
$
|
(8.6
|
)
|
||||
|
Amounts
recognized in the consolidated balance sheets consist
of:
|
||||||||||
|
Prepaid
benefit cost
|
$
|
3.4
|
$
|
3.2
|
||||||
|
Accrued
benefit liability
|
(64.7
|
)
|
(54.0
|
)
|
||||||
|
Intangible
asset
|
0.4
|
0.2
|
||||||||
|
Accumulated
other comprehensive income
|
35.9
|
42.0
|
||||||||
|
Net
amount recognized
|
$
|
(25.0
|
)
|
$
|
(8.6
|
)
|
||||
|
(a)
|
Change
in beginning balance is due to the addition of the Egypt Plan’s January 1,
2005 beginning balance of $1.4
million.
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
accumulated benefit obligation for all defined benefit pension plans was $278.6
million and $269.9 million at December 31, 2005 and 2004,
respectively.
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):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Projected
benefit obligation
|
$
|
326.7
|
$
|
316.2
|
|||
|
Fair
value of plan assets
|
231.5
|
225.1
|
|||||
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):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Accumulated
benefit obligation
|
$
|
261.1
|
$
|
252.5
|
|||
|
Fair
value of plan assets
|
219.0
|
213.7
|
|||||
Net
periodic benefit cost included the following components (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Components
of Net Periodic Benefit Cost (a)
|
||||||||||
|
Service
cost
|
$
|
18.1
|
$
|
16.7
|
$
|
16.6
|
||||
|
Interest
cost
|
17.6
|
16.7
|
18.2
|
|||||||
|
Expected
return on plan assets
|
(20.5
|
)
|
(19.6
|
)
|
(19.7
|
)
|
||||
|
Amortization
of transition obligation
|
0.3
|
0.3
|
0.3
|
|||||||
|
Amortization
of prior service cost
|
0.8
|
0.6
|
1.3
|
|||||||
|
Recognized
net actuarial losses
|
3.8
|
2.3
|
0.4
|
|||||||
|
SFAS
88 settlements/curtailments
|
2.1
|
-
|
4.7
|
|||||||
|
Benefit
cost
|
$
|
22.2
|
$
|
17.0
|
$
|
21.8
|
||||
|
Increase
(decrease) in minimum pension liability included in other comprehensive
income (in millions)
|
$
|
(6.1
|
)
|
$
|
6.3
|
$
|
(10.0
|
)
|
||
|
(a)
|
Amounts
are before income tax effect.
|
Weighted-average
assumptions used to determine benefit obligations:
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Discount
rate
|
5.60
|
%
|
5.60
|
%
|
|||
|
Rate
of compensation increase
|
4.50
|
%
|
5.00
|
%
|
|||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Weighted-average
assumptions used to determine net periodic benefit cost:
|
December
31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Discount
rate
|
5.63
|
%
|
6.01
|
%
|
6.65
|
%
|
||||
|
Expected
long-term rate of return in plan assets
|
8.70
|
%
|
8.73
|
%
|
8.73
|
%
|
||||
|
Rate
of compensation increase
|
4.52
|
%
|
5.00
|
%
|
5.24
|
%
|
||||
The
defined benefit pension obligations and the related benefit costs are accounted
for in accordance with SFAS 87, Employers’
Accounting for Pensions.
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. As of December 31, 2005, 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. 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.
Our
pension plan weighted-average asset allocations for funded Transocean Plans
by
asset category are as follows:
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Equity
securities
|
55.5
|
%
|
55.2
|
%
|
|||
|
Debt
securities
|
31.3
|
%
|
31.1
|
%
|
|||
|
Other
|
13.2
|
%
|
13.7
|
%
|
|||
|
Total
|
100.0
|
%
|
100.0
|
%
|
|||
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.
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We
contributed $5.6 million to our defined benefit pension plans in 2005. Such
contributions were funded from our cash flows from operations. Contributions
of
$1.1 million were made to the unfunded U.S. Plans during 2005. No contributions
were made to the funded U. S. Plans during 2005.
We
expect
to contribute a total of $8.3 million to the Transocean Plans in 2006. These
contributions are comprised of an estimated $2.7 million to meet the minimum
funding requirements for the funded U.S. Plans, $0.7 million to fund expected
benefit payments for the unfunded U.S. Plans, Nigeria Plan and Egypt Plan and
an
estimated $4.9 million for the funded Norway Plans.
The
following pension benefits payments are expected to be paid by the Transocean
Plans (in millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
13.1
|
||
|
2007
|
13.5
|
|||
|
2008
|
14.1
|
|||
|
2009
|
14.6
|
|||
|
2010
|
15.1
|
|||
|
2011-2015
|
74.3
|
|||
Nigeria
Plan—During
2003, we terminated all Nigerian employees, which resulted in the payment of
all
accrued benefits under the Nigeria Plan. Approximately 80 of these employees
were made redundant during 2003, while the remaining employees not considered
redundant were rehired under a new plan. In accordance with the provisions
of
SFAS 88, Employers’
Accounting for Settlements and Curtailments of Defined Benefit Pension Plans
and
Termination Benefits,
this
resulted in a partial plan curtailment and a plan settlement. We paid
approximately $17.0 million in severance benefits under the Nigeria Plan during
2003 as a result of these events. In accordance with SFAS 88, we accounted
for
these events as a plan restructuring and recorded a net settlement expense
of
$10.4 million, as well as a $4.6 million liability. This liability will reduce
future pension expense related to the Nigeria Plan as it will be recognized
over
the expected service term of the related employees. Pension expense for the
Nigeria Plan was $0.2 million in 2004 and represented a 98.7 percent decrease
as
compared to the 2003 plan expenses (excluding the settlement related expenses
discussed above).
Postretirement
Benefits Other Than Pensions (“OPEB”)—We
have several
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 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 $23.0 million in plan benefit obligations.
One
of
our OPEB plans is a retiree life insurance plan. Effective January 1, 2003,
the
plan was amended such that participants who retire after December 31, 2002
no
longer receive postretirement benefits provided under this plan. As such, we
recorded a curtailment gain of $0.6 million related to this amendment in
2003.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
change in benefit obligation, change in plan assets and funded status are shown
in the table below (in millions):
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Change
in benefit obligation
|
|||||||
|
Benefit
obligation at beginning of year
|
$
|
37.5
|
$
|
62.0
|
|||
|
Service
cost
|
1.3
|
1.0
|
|||||
|
Interest
cost
|
2.1
|
2.1
|
|||||
|
Actuarial
(gains) losses
|
2.1
|
(2.9
|
)
|
||||
|
Participants’
contributions
|
0.6
|
0.4
|
|||||
|
Plan
amendments
|
-
|
(23.0
|
)
|
||||
|
Benefits
paid
|
(2.5
|
)
|
(2.1
|
)
|
|||
|
Benefit
obligation at end of year
|
41.1
|
37.5
|
|||||
|
Change
in plan assets
|
|||||||
|
Fair
value of plan assets at beginning of year
|
-
|
-
|
|||||
|
Employer
contributions
|
1.9
|
1.7
|
|||||
|
Participants’
contributions
|
0.6
|
0.4
|
|||||
|
Benefits
paid
|
(2.5
|
)
|
(2.1
|
)
|
|||
|
Fair
value of plan assets at end of year
|
-
|
-
|
|||||
|
Funded
status
|
(41.1
|
)
|
(37.5
|
)
|
|||
|
Unrecognized
net actuarial gain
|
24.2
|
23.7
|
|||||
|
Unrecognized
prior service cost
|
(19.4
|
)
|
(21.6
|
)
|
|||
|
Postretirement
benefit liability
|
$
|
(36.3
|
)
|
$
|
(35.4
|
)
|
|
Amounts
recognized in the consolidated balance sheets for the years ended December
31,
2005 and 2004 consisted of accrued benefit costs totaling $36.3 million and
$35.4 million, respectively. There were no prepaid benefit costs recognized
for
the years ended December 31, 2005 and 2004.
Net
periodic benefit cost included the following components (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Components
of Net Periodic Benefit Cost
|
||||||||||
|
Service
cost
|
$
|
1.3
|
$
|
1.0
|
$
|
2.0
|
||||
|
Interest
cost
|
2.1
|
2.1
|
3.4
|
|||||||
|
Amortization
of prior service cost
|
(2.3
|
)
|
(2.3
|
)
|
0.3
|
|||||
|
SFAS
88 settlements/curtailments
|
-
|
-
|
(0.6
|
)
|
||||||
|
Recognized
net actuarial losses
|
1.7
|
1.5
|
1.3
|
|||||||
|
Benefit
Cost
|
$
|
2.8
|
$
|
2.3
|
$
|
6.4
|
||||
Weighted-average
discount rates used to determine benefit obligations were 5.37% and 5.50% for
the years ended December 31, 2005 and 2004, respectively.
Weighted-average
assumptions used to determine net periodic benefit cost were as
follows:
|
December
31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Discount
rate
|
5.50
|
%
|
6.00
|
%
|
6.50
|
%
|
||||
|
Expected
long-term rate of return in plan assets
|
-
|
-
|
-
|
|||||||
|
Rate
of compensation increase
|
-
|
-
|
-
|
|||||||
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Assumed
health care cost trend rates were as follows:
|
December
31,
|
|||||||
|
2005
|
2004
|
||||||
|
Health
care cost trend rate assumed for next year
|
9
|
%
|
11
|
%
|
|||
|
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
|
2009
|
2009
|
|||||
The
assumed health care cost trend rate has 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-
Percentage
Point
Increase
|
One-
Percentage
Point
Decrease
|
||||||
|
Effect
on total service and interest cost components in 2005
|
$
|
0.6
|
$
|
(0.6
|
)
|
||
|
Effect
on postretirement benefit obligations as of December 31,
2005
|
$
|
5.3
|
$
|
(5.7
|
)
|
||
Our
OPEB
obligations and the related benefit costs are accounted for in accordance with
SFAS 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 9% percent for 2005 reducing 1.0 percent per year to an
ultimate trend rate of 5.0 percent per year for 2009 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.
The
following postretirement benefits payments are expected to be paid (in
millions):
|
Years
ending
December
31,
|
||||
|
2006
|
$
|
1.4
|
||
|
2007
|
1.5
|
|||
|
2008
|
1.6
|
|||
|
2009
|
1.7
|
|||
|
2010
|
1.8
|
|||
|
2011-2015
|
10.5
|
|||
In
December 2003, the Medicare Prescription Drug, Improvement and Modernization
Act
of 2003 (the “Medicare Act”) was signed into law. The Medicare Act introduced
two new features to Medicare that employers must consider in determining the
effect of the Medicare Act on their accumulated postretirement benefit
obligation (“APBO”) and net periodic post retirement benefit cost: (i) a subsidy
based on 28 percent of an individual beneficiary’s annual prescription drug
costs between $250 and $5,000, and (ii) the opportunity for a retiree to obtain
a prescription drug benefit under Medicare that is at least actuarially
equivalent to Medicare Part D.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
May
2004, the FASB issued FASB Staff Position (“FSP”) 106-2, Accounting
and Disclosure Requirements Related to the Medicare Prescription Drug,
Improvement and Modernization Act of 2003.
We
adopted FSP 106-2, effective July 1, 2004, accounting for these new features
in
the Medicare Act prospectively as an actuarial gain to be amortized into income
over the average remaining service period of the plan participants. The adoption
of these requirements did not have a material impact on our consolidated
financial position, results of operations or cash flows for the years ended
December 31, 2005 and 2004.
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 $20.8 million, $20.3 million and $21.8
million of expense related to our defined contribution plans for the years
ended
December 31, 2005, 2004 and 2003, 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, 2005,
2004 or 2003.
In
2005,
the Plan was amended to effectively freeze the Plan as of December 31,
2004.
Note
21—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. See Note 23.
As
a
result of the R&B Falcon merger, we had ownership interests in two
unconsolidated joint ventures, 50 percent in DD LLC and 60 percent in DDII
LLC.
Subsidiaries of ConocoPhillips owned the remaining interests in these joint
ventures. We purchased ConocoPhillips’ interests in DDII LLC and DD LLC in late
May 2003 and late December 2003, respectively, at which time both DDII LLC
and
DD LLC became wholly owned subsidiaries. See Note 5.
As
a
result of the R&B Falcon merger, TODCO had a 25 percent ownership interest
in Delta Towing Holdings, LLC (“Delta Towing”), a joint venture established for
the purpose of owning and operating inland and shallow water marine support
vessel equipment. Delta Towing was considered a variable interest entity as
its
equity was not sufficient to absorb its expected losses. As a result of our
adoption of FIN 46 effective December 31, 2003, TODCO evaluated the expected
losses it would absorb from Delta Towing. Because TODCO had the largest
percentage of investment at risk through the notes issued by Delta Towing to
TODCO, TODCO would absorb the majority of the joint venture’s expected losses;
therefore, TODCO was deemed to be the primary beneficiary of Delta Towing for
accounting purposes. As such, TODCO consolidated Delta Towing effective December
31, 2003 and the consolidation resulted in an increase in net assets and a
corresponding gain as a cumulative effect of a change in accounting principle
of
approximately $0.8 million, which had no tax effect. As a result of the 2004
Offerings, Delta Towing was deconsolidated in connection with the
deconsolidation of TODCO at December 17, 2004. See Notes 4 and 23.
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
22—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), 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).
Operating
revenues and income before income taxes, minority interest and cumulative effect
of a change in accounting principle by segment were as follows (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Operating
Revenues
|
||||||||||
|
Transocean
Drilling
|
$
|
2,891.7
|
$
|
2,280.4
|
$
|
2,206.7
|
||||
|
TODCO
(a)
|
-
|
333.5
|
227.6
|
|||||||
|
Total
Operating Revenues
|
$
|
2,891.7
|
$
|
2,613.9
|
$
|
2,434.3
|
||||
|
Operating
Income (Loss) Before General and Administrative Expense
|
||||||||||
|
Transocean
Drilling
|
$
|
794.3
|
$
|
428.6
|
$
|
422.5
|
||||
|
TODCO
(a) (b)
|
-
|
(33.7
|
)
|
(117.5
|
)
|
|||||
|
794.3
|
394.9
|
305.0
|
||||||||
|
Unallocated
general and administrative expense
|
(74.8
|
)
|
(67.0
|
)
|
(65.3
|
)
|
||||
|
Unallocated
other income (expense), net (c)
|
82.9
|
(87.6
|
)
|
(218.1
|
)
|
|||||
|
Income
Before Income Taxes, Minority Interest and
|
||||||||||
|
Cumulative
Effect of a Change in Accounting Principle (c)
|
$
|
802.4
|
$
|
240.3
|
$
|
21.6
|
||||
|
(a)
|
The
year ended December 31, 2004 includes results from the TODCO segment
to
December 17, 2004, the effective date of the TODCO
deconsolidation.
|
|
(b)
|
The
years ended December 31, 2004 and 2003 include $32.3 million and
$14.9
million, respectively, of operating and maintenance expense that
TODCO
classifies as general and administrative
expense.
|
|
(c)
|
The
year ended December 31, 2005 included gains from the TODCO Stock
Sales of
$165.0 million. The year ended December 31, 2004 includes gains from
the
TODCO Stock Sales of $308.8 million and a non-cash charge of $167.1
million related to contingent amounts due from TODCO under a tax
sharing
agreement between us and TODCO. See Notes 4 and
16.
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Depreciation
expense by segment was as follows (in millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Transocean
Drilling
|
$
|
405.8
|
$
|
432.6
|
$
|
416.0
|
||||
|
TODCO
|
-
|
92.0
|
92.2
|
|||||||
|
Total
Depreciation Expense
|
$
|
405.8
|
$
|
524.6
|
$
|
508.2
|
||||
Total
capital expenditures by segment were as follows (in millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Transocean
Drilling
|
$
|
181.9
|
$
|
118.2
|
$
|
481.8
|
||||
|
TODCO
|
-
|
8.8
|
12.0
|
|||||||
|
Total
Capital Expenditures
|
$
|
181.9
|
$
|
127.0
|
$
|
493.8
|
||||
Operating
revenues and long-lived assets by country were as follows (in
millions):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Operating
Revenues
|
||||||||||
|
United
States
|
$
|
647.7
|
$
|
856.0
|
$
|
752.8
|
||||
|
Brazil
|
265.3
|
278.0
|
316.7
|
|||||||
|
India
|
296.4
|
270.8
|
119.6
|
|||||||
|
United
Kingdom
|
335.4
|
208.8
|
211.6
|
|||||||
|
Other
Countries (a)
|
1,346.9
|
1,000.3
|
1,033.6
|
|||||||
|
Total
Operating Revenues
|
$
|
2,891.7
|
$
|
2,613.9
|
$
|
2,434.3
|
||||
|
As
of December 31,
|
|||||||
|
2005
|
2004
|
||||||
|
Long-Lived
Assets
|
|||||||
|
United
States
|
$
|
2,311.2
|
$
|
2,396.5
|
|||
|
Brazil
|
761.9
|
865.3
|
|||||
|
Nigeria
|
980.3
|
811.1
|
|||||
|
Other
Countries (a)
|
2,694.8
|
2,932.3
|
|||||
|
Total
Long-Lived Assets
|
$
|
6,748.2
|
$
|
7,005.2
|
|||
|
(a)
|
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
For
the
year ended December 31, 2005, Chevron and BP accounted for approximately 12.1
percent and 11.7 percent, respectively, of our operating revenues. For the
year
ended December 31, 2004, BP, Petrobras and Chevron accounted for approximately
10.3 percent, 10.2 percent and 9.9 percent, respectively, of our operating
revenues, of which the majority was reported in the Transocean Drilling segment.
For the year ended December 31, 2003, Petrobras, BP and Shell accounted for
approximately 11.8 percent, 11.1 percent and 10.7 percent, respectively, 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.
Note
23—Related
Party Transactions
DD
LLC and DDII LLC—Prior
to
our purchase of ConocoPhillips’ interest in DD LLC and DDII LLC (see Note 5), we
were party to drilling services agreements with DD LLC and DDII LLC for the
operations of the Deepwater
Pathfinder
and
Deepwater
Frontier,
respectively. For the year ended December 31, 2003, we earned $1.6 million
and
$1.3 million for such services to DD LLC and DDII LLC, respectively, which
was
reflected in other revenues in our consolidated statement of operations.
Delta
Towing—Immediately
prior to the closing of the R&B Falcon merger, TODCO formed a joint venture
to own and operate its U.S. inland marine support vessel business (the “Marine
Business”). In connection with the formation of the joint venture, the Marine
Business was transferred by a subsidiary of TODCO to Delta Towing in exchange
for a 25 percent equity interest, and certain secured notes payable from Delta
Towing. The secured notes consisted of (i) an $80.0 million principal amount
note bearing interest at eight percent per annum due January 30, 2024 (the
“Tier
1 Note”), (ii) a contingent $20.0 million principal amount note bearing interest
at eight percent per annum with an expiration date of January 30, 2011 (the
“Tier 2 Note”) and (iii) a contingent $44.0 million principal amount note
bearing interest at eight percent per annum with an expiration date of January
30, 2011 (the “Tier 3 Note”). The 75 percent equity interest holder in the joint
venture also loaned Delta Towing $3.0 million in the form of a Tier 1 Note.
Until January 2011, Delta Towing must use 100 percent of its excess cash flow
towards the payment of principal and interest on the Tier 1 Notes. After January
2011, 50 percent of its excess cash flows are to be applied towards the payment
of principal and unpaid interest on the Tier 1 Notes. Interest is due and
payable quarterly without regard to excess cash flow.
Delta
Towing was obligated to repay at least (i) $8.3 million of the aggregate
principal amount of the Tier 1 Note no later than January 2004, (ii) $24.9
million of the aggregate principal amount no later than January 2006 and (iii)
$62.3 million of the aggregate principal amount no later than January 2008.
After the Tier 1 Note has been repaid, Delta Towing must apply 75 percent of
its
excess cash flow towards payment of the Tier 2 Note. Upon the repayment of
the
Tier 2 Note, Delta Towing must apply 50 percent of its excess cash to repay
principal and interest on the Tier 3 Note. Any amounts not yet due under the
Tier 2 and Tier 3 Notes at the time of their expiration will be waived. The
Tier
1, 2 and 3 Notes are secured by mortgages and liens on the vessels and other
assets of Delta Towing.
TODCO
valued its Tier 1, 2 and 3 Notes at $80 million immediately prior to the closing
of the R&B Falcon merger, the effect of which was to fully reserve the Tier
2 and 3 Notes. For the year ended December 31, 2003, we earned interest income
on the outstanding balance of $3.1 million on the Tier 1 Note. In December
2001,
the note agreement was amended to provide for a $4.0 million, three-year
revolving credit facility (the “Delta Towing Revolver”) from the Company.
Amounts drawn under the Delta Towing Revolver accrued interest at eight percent
per annum, with interest payable quarterly. For the year ended December 31,
2003, TODCO recognized $0.3 million of interest income on the Delta Towing
Revolver.
Delta
Towing defaulted on the notes in January 2003 by failing to make its scheduled
quarterly interest payment and remained in default as a result of its continued
failure to make its quarterly interest payments. As a result of TODCO’s
continued evaluation of the collectibility of the notes, TODCO recorded an
impairment of the notes receivable of $21.3 million ($13.8 million, or $0.04
per
diluted share, net of tax) in June 2003 based on Delta Towing’s discounted cash
flows over the terms of the notes, which deteriorated in the second quarter
of
2003 as a result of the continued decline in Delta Towing’s business outlook. As
permitted in the note agreement in the event of default, TODCO began offsetting
a portion of the amount owed to Delta Towing against the interest due under
the
notes. Additionally, in 2003, TODCO established a reserve of $1.6 million for
interest income earned during the year ended December 31, 2003 on the notes
receivable.
As
part
of the formation of the joint venture on January 31, 2001, TODCO entered into
an
agreement with Delta Towing under which TODCO committed to charter certain
vessels for a period of one year ending January 31, 2002 and committed to
charter for a period of 2.5 years from the date of delivery 10 crewboats then
under construction, all of which had been placed into service as of December
31,
2002. During the year ended December 31, 2003, TODCO incurred charges of $11.7
million, which was reflected in operating and maintenance expense.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
As
a
result of the adoption of FIN 46 and a determination that TODCO was the primary
beneficiary for accounting purposes of Delta Towing, TODCO consolidated Delta
Towing effective December 31, 2003 and intercompany transactions and accounts
were eliminated, including the above described notes. Consolidation of Delta
Towing resulted in an increase in net assets and a corresponding gain as a
cumulative effect of a change in accounting principle of approximately $0.8
million, which had no tax effect. In connection with the deconsolidation of
TODCO, Delta Towing was deconsolidated effective December 17, 2004 (see Note
4).
ODL—In
conjunction with the management and operation of the Joides
Resolution
on
behalf of ODL, we earned $1.4 million, $2.4 million and $1.2 million for the
years ended December 31, 2005, 2004 and 2003, respectively. Such amounts are
included in other revenues in our consolidated statements of operations. At
December 31, 2005 and 2004, we had receivables due from ODL of $1.7 million
and
$1.1 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. During 2005
and
prior to entering into the loan agreement, we received $3.0 million in dividend
payments from ODL. As of December 31, 2005, $3.5 million was outstanding under
this loan agreement and was reflected as other long-term liabilities in our
consolidated balance sheet.
TODCO—We
entered into a transition services agreement under which we provide 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 Notes 1 and 4), 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
are 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
$1.1 million of costs related to service fees that TODCO billed to us in 2005.
At December 31, 2005 and 2004, we had payables related to the agreements for
the
separation of TODCO of $0.5 million and $0.3 million, respectively, which was
included in accounts payable in our consolidated balance sheet. At December
31,
2005 and 2004, we had a long-term payable related to our indemnification of
certain TODCO non-U.S. income tax liabilities of $11.2 million, for each period,
which was included in other long-term liabilities in our consolidated balance
sheet. Although the ultimate amount of the indemnification could vary and we
cannot predict or provide assurance as to the final outcome, we do not expect
the liability, if any, resulting from the indemnification to have a material
adverse effect on our consolidated financial position, results of operations
or
cash flows.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
24—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):
|
Years
ended December 31,
|
||||||||||
|
2005
|
2004
|
2003
|
||||||||
|
Numerator
for Basic Earnings per Share
|
||||||||||
|
Income
Before Cumulative Effect of a Change in Accounting
Principle
|
$
|
715.6
|
$
|
152.2
|
$
|
18.4
|
||||
|
Cumulative
Effect of a Change in Accounting Principle
|
−
|
−
|
0.8
|
|||||||
|
Net
Income for basic earnings per share
|
$
|
715.6
|
$
|
152.2
|
$
|
19.2
|
||||
|
Numerator
for Diluted Earnings per Share
|
||||||||||
|
Net
Income
|
$
|
715.6
|
$
|
152.2
|
$
|
18.4
|
||||
|
Cumulative
Effect of a Change in Accounting Principle
|
−
|
−
|
0.8
|
|||||||
|
Add
back interest expense on the 1.5% convertible debentures
|
6.3
|
−
|
−
|
|||||||
|
Net
Income for diluted earnings per share
|
$
|
721.9
|
$
|
152.2
|
$
|
19.2
|
||||
|
Denominator
for Diluted Earnings per Share
|
||||||||||
|
Weighted-average
shares outstanding for basic earnings per share
|
327.1
|
320.9
|
319.8
|
|||||||
|
Effect
of dilutive securities:
|
||||||||||
|
Employee
stock options and unvested stock grants
|
4.0
|
2.6
|
1.1
|
|||||||
|
Warrants
to purchase ordinary shares
|
2.8
|
1.7
|
0.5
|
|||||||
|
1.5%
Convertible debentures
|
5.5
|
−
|
−
|
|||||||
|
Adjusted
weighted-average shares and assumed conversions for diluted earnings
per
share
|
339.4
|
325.2
|
321.4
|
|||||||
|
Basic
Earnings Per Share
|
||||||||||
|
Net
Income
|
$
|
2.19
|
$
|
0.47
|
$
|
0.06
|
||||
|
Diluted
Earnings Per Share
|
||||||||||
|
Net
Income
|
$
|
2.13
|
$
|
0.47
|
$
|
0.06
|
||||
Ordinary
shares subject to issuance pursuant to the conversion features of the Zero
Coupon Convertible Debentures (see Note 8) are not included in the calculation
of adjusted weighted-average shares and assumed conversions for diluted earnings
per share because the effect of including those shares is anti-dilutive for
all
periods presented. 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 years ended December 31, 2004 and 2003
because the effect of including those shares is anti-dilutive.
Note
25—Stock
Warrants
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. At December 31, 2005, there were 229,000 warrants outstanding
to
purchase 4,007,500 ordinary shares.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
26—Quarterly
Results (Unaudited)
Shown
below are selected unaudited quarterly data (in millions, except per share
data):
|
First
|
Second
|
Third
|
Fourth
|
||||||||||
|
2005
|
|||||||||||||
|
Operating
Revenues
|
$
|
630.5
|
$
|
727.4
|
$
|
762.6
|
$
|
771.2
|
|||||
|
Operating
Income (a)
|
143.3
|
184.8
|
203.5
|
187.9
|
|||||||||
|
Net
Income (a) (b)
|
91.8
|
301.8
|
170.4
|
151.6
|
|||||||||
|
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
|
323.6
|
326.1
|
328.9
|
329.8
|
|||||||||
|
Shares
for diluted earnings per share
|
331.0
|
338.0
|
340.8
|
336.1
|
|||||||||
|
2004
|
|||||||||||||
|
Operating
Revenues
|
$
|
652.0
|
$
|
633.2
|
$
|
651.8
|
$
|
676.9
|
|||||
|
Operating
Income (c)
|
96.8
|
103.8
|
71.1
|
56.2
|
|||||||||
|
Net
Income (Loss) (c) (d)
|
22.7
|
48.0
|
154.9
|
(73.4
|
)
|
||||||||
|
Basic
Earnings (Loss) Per Share
|
$
|
0.07
|
$
|
0.15
|
$
|
0.48
|
$
|
(0.23
|
)
|
||||
|
Diluted
Earnings (Loss) Per Share
|
$
|
0.07
|
$
|
0.15
|
$
|
0.47
|
$
|
(0.23
|
)
|
||||
|
Weighted
Average Shares Outstanding
|
|||||||||||||
|
Shares
for basic earnings per share
|
320.6
|
320.8
|
320.9
|
321.2
|
|||||||||
|
Shares
for diluted earnings per share
|
324.1
|
324.1
|
330.5
|
321.2
|
|||||||||
|
(a)
|
First
quarter 2005 included gain on sale of an asset of $18.8 million (see
Note
6). Second quarter 2005 included gain on sale of assets of $14.0
million
(see Note 6).
|
|
(b)
|
First
quarter 2005 included a loss on retirement of debt of $6.7 million
(see
Note 8). Second quarter 2005 included gains from TODCO Stock Sales
of
$165.0 million (see Note 4). Fourth quarter of 2005 included a net
income
tax benefit of $15.8 million related to various tax adjustments (see
Note
16).
|
|
(c)
|
First
quarter 2004 included expense for stock option vesting resulting
from the
TODCO IPO of $7.1 million (see Note 4).
|
|
(d)
|
First
quarter 2004 included a gain on the TODCO IPO of $39.4 million, a
tax
valuation allowance of $31.0 million and a loss on retirement of
debt of
$28.1 million (see Note 8). Second quarter 2004 included a gain on
sale of
an asset of $21.6 million (see Note 6). Third quarter 2004 included
a gain
on the September 2004 Offering of $129.4 million (see Note 4). Fourth
quarter 2004 included a gain on the December 2004 Offering of $140.0
million (see Note 4), loss on retirement of debt of $48.4 million
(see
Note 8) and a non-cash charge of $167.1 million related to contingent
amounts due from TODCO under a tax sharing agreement between us and
TODCO
(see Notes 4 and 16).
|
Note
27—Subsequent
Events (Unaudited)
Asset
Dispositions—
In
February 2006, we completed the sale of the drillship Peregrine
III
for net
proceeds of $78.7 million, of which $7.8 million was received in December 2005,
and expect to recognize a pre-tax gain on the sale of approximately $62 million.
The deposit received in December 2005 was reflected as unearned income and
included in other current liabilities in our consolidated balance
sheet.
Expansion
of Drilling Fleet— We have been awarded a contract for the
construction of an enhanced Enterprise-class drillship
with an estimated total capital expenditure of approximately $650 million.
Construction is expected to begin in 2006 and continue into 2009.
|
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.
|
Controls
and Procedures
|
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, 2005 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.
Pursuant
to our efforts relating to Section 404 of the Sarbanes-Oxley Act, we made
certain changes to our internal controls over financial reporting during the
quarter ended December 31, 2005 that we believe better align these controls
with
the Section 404 requirements. However, there were no changes in these internal
controls during that quarter 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.
|
Other
Information
|
None
|
Directors
and Executive Officers of the
Registrant
|
|
Executive
Compensation
|
|
Security
Ownership of Certain Beneficial Owners and
Management
and Related Shareholder
Matters
|
|
Certain
Relationships and Related
Transactions
|
|
Principal
Accounting Fees and
Services
|
The
information required by Items 10, 11, 12, 13 and 14 is incorporated herein
by
reference to our definitive proxy statement for our 2006 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, 2005. 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.”
|
Exhibits
and Financial Statement Schedules
|
|
(a)
|
Index
to Financial Statements, Financial Statement Schedules and Exhibits
|
|
(1)
|
Financial
Statements
|
|
Page
|
|
|
Included
in Part II of this report:
|
|
|
Management’s
Report on Internal Control Over Financial Reporting
|
60
|
|
Report
of Independent Registered Public Accounting Firm on Internal Control
over
Financial Reporting
|
61
|
|
Report
of Independent Registered Public Accounting Firm
|
62
|
|
Consolidated
Statements of Operations
|
63
|
|
Consolidated
Statements of Comprehensive Income
|
64
|
|
Consolidated
Balance Sheets
|
65
|
|
Consolidated
Statements of Equity
|
66
|
|
Consolidated
Statements of Cash Flows
|
67
|
|
Notes
to Consolidated Financial Statements
|
69
|
Financial
statements of unconsolidated subsidiaries are not presented herein because
such
subsidiaries do not meet the significance test.
|
(2)
|
Financial
Statement Schedules
|
Transocean
Inc. and Subsidiaries
Schedule
II - Valuation and Qualifying Accounts
(In
millions)
|
Additions
|
||||||||||||||||||||||
|
Balance
at
Beginning
of
Period
|
Charged
to
Costs
and
Expenses
|
Charged
to
Other
Accounts
Describe
|
Deductions
Describe
|
Balance
at
End
of
Period
|
||||||||||||||||||
|
Year
Ended December 31, 2003
|
||||||||||||||||||||||
|
Reserves
and allowances deducted from asset accounts:
|
||||||||||||||||||||||
|
Allowance
for doubtful accounts receivable
|
$
|
20.8
|
$
|
24.4
|
$
|
-
|
$
|
16.1
|
(a)
|
|
$
|
29.1
|
||||||||||
|
|
||||||||||||||||||||||
|
Allowance
for obsolete materials and supplies
|
18.6
|
0.9
|
0.2
|
(e)
|
|
2.2
|
(b)
(c) (d)
|
|
17.5
|
|||||||||||||
|
|
|
|||||||||||||||||||||
|
Year
Ended December 31, 2004
|
|
|
||||||||||||||||||||
|
Reserves
and allowances deducted from asset accounts:
|
||||||||||||||||||||||
|
Allowance
for doubtful accounts receivable
|
29.1
|
10.2
|
0.2
|
(f)
(g)
|
|
22.7
|
(a)
|
|
16.8
|
|||||||||||||
|
|
|
|||||||||||||||||||||
|
Allowance
for obsolete materials and supplies
|
17.5
|
3.2
|
(0.4
|
)
|
(h)
(i)
|
|
-
|
|
20.3
|
|||||||||||||
|
|
|
|||||||||||||||||||||
|
Year
Ended December 31, 2005
|
|
|
||||||||||||||||||||
|
Reserves
and allowances deducted from asset accounts:
|
||||||||||||||||||||||
|
Allowance
for doubtful accounts receivable
|
16.8
|
15.8
|
(1.2
|
)
|
(j)
|
|
16.1
|
(a)
|
|
15.3
|
||||||||||||
|
|
||||||||||||||||||||||
|
Allowance
for obsolete materials and supplies
|
$
|
20.3
|
$
|
0.4
|
$
|
-
|
$
|
1.7
|
(b)
(k) (l)
|
|
$
|
19.0
|
||||||||||
|
(a)
|
Uncollectible
accounts receivable written off, net of
recoveries.
|
|
(b)
|
Obsolete
materials and supplies written off, net of
scrap.
|
|
(c)
|
Amount
includes $0.8 related to sale of
rigs/inventory.
|
|
(d)
|
Amount
includes $0.9 related to adjustments to the
provision.
|
|
(e)
|
Amount
includes $0.2 related to adjustments to the
provision.
|
|
(f)
|
Amount
includes $0.2 related to TODCO
deconsolidation.
|
|
(g)
|
Amount
includes $0.4 related to adjustments to the
provision.
|
|
(h)
|
Amount
includes $0.3 related to TODCO
deconsolidation.
|
|
(i)
|
Amount
includes $0.1 related to sale of
rigs/inventory.
|
|
(j)
|
Amount
includes $1.3 related to adjustments to the
provision.
|
|
(k)
|
Amount
includes $0.2 related to sale of
rigs/inventory.
|
|
(l)
|
Amount
includes $0.7 related to adjustments to the
provision.
|
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.
|
(3)
|
Exhibits
|
The
following exhibits are filed in connection with this Report:
|
Number
|
Description
|
|
2.1
|
Agreement
and Plan of Merger dated as of August 19, 2000 by and among Transocean
Inc., Transocean Holdings Inc., TSF Delaware Inc. and R&B Falcon
Corporation (incorporated by reference to Annex A to the Joint Proxy
Statement/Prospectus dated October 30, 2000 included in a 424(b)(3)
prospectus filed by the Company on November 1, 2000)
|
|
2.2
|
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
October
30, 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
October
30, 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)
|
|
4.1
|
Indenture
dated as of April 15, 1997 between the Company and Texas Commerce
Bank
National Association, as trustee (incorporated by reference to Exhibit
4.1
to the Company's Form 8-K dated April 29, 1997)
|
|
4.2
|
First
Supplemental Indenture dated as of April 15, 1997 between the Company
and
Texas Commerce Bank National Association, as trustee, supplementing
the
Indenture dated as of April 15, 1997 (incorporated by reference to
Exhibit
4.2 to the Company's Form 8-K dated April 29, 1997)
|
|
4.3
|
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)
|
|
4.5
|
Fourth
Supplemental Indenture dated as of May 11, 2001 between the Company
and
The Chase Manhattan Bank (incorporated by reference to Exhibit 4.3
to the
Company's Quarterly Report on Form 10-Q for the quarter ended
March 31, 2001)
|
|
4.6
|
Form
of 7.45% Notes due April 15, 2027 (incorporated by reference to Exhibit
4.3 to the Company's Form 8-K dated April 29, 1997)
|
|
4.7
|
Form
of 8.00% Debentures due April 15, 2027 (incorporated by reference
to
Exhibit 4.4 to the Company's Form 8-K dated April 19,
1997)
|
|
4.8
|
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)
|
|
4.9
|
Form
of 1.5% Convertible Debenture due May 15, 2021 (incorporated by reference
to Exhibit 4.2 to the Company's Current Report on Form 8-K dated
May 8,
2001)
|
|
4.10
|
Form
of 6.625% Note due April 15, 2011 (incorporated by reference to Exhibit
4.3 to the Company's Current Report on Form 8-K dated March 30,
2001)
|
|
4.11
|
Form
of 7.5% Note due April 15, 2031 (incorporated by reference to Exhibit
4.3
to the Company's Current Report on Form 8-K dated March 30,
2001)
|
|
4.12
|
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)
|
|
4.13
|
Officers'
Certificate establishing the terms of the 7.375% Notes due 2018
(incorporated by reference to Exhibit 4.14 to the Company's Annual
Report
on Form 10-K for the fiscal year ended December 31,
2001)
|
|
4.14
|
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 November
18, 2005)
|
|
4.17
|
Registration
Rights Agreement dated April 22, 1999 between R&B Falcon and American
Stock Transfer & Trust Company (incorporated by reference to Exhibit
4.2 to R&B Falcon's Registration Statement No. 333-81181 on Form S-3
dated June 21, 1999)
|
|
4.18
|
Supplement
to Registration Rights Agreement dated January 31, 2001 between Transocean
Sedco Forex Inc. and R&B Falcon Corporation (incorporated by reference
to Exhibit 4.30 to the Company's Annual Report on Form 10-K for
the year ended December 31, 2000)
|
|
4.19
|
Revolving
Credit Agreement dated December 16, 2003 among Transocean Inc., the
lenders party thereto, Suntrust Bank, as administrative agent, Citibank,
N.A. and Bank of America, N.A., as co-syndication agents, The Royal
Bank
of Scotland plc and Bank One, NA, as co-documentation agents, Wells
Fargo
Bank, N.A. and UBS Loan Finance LLC, as managing agents, The Bank
of New
York, Den Norske Bank ASA and HSBC Bank USA, as co-agents, and Citigroup
Global Markets Inc. and Suntrust Capital Markets, Inc., as co-lead
arrangers (incorporated by reference to Exhibit 4.25 to our Annual
Report
on Form 10-K for the year ended December 31, 2003)
|
|
4.20
|
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)
|
|
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)
|
|
*10.2
|
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)
|
|
*10.6
|
Form
of Employment Agreement dated May 14, 1999 between J. Michael Talbert,
Robert L. Long, Eric B. Brown and Barbara S. Wood, individually,
and the
Company (incorporated by reference to Exhibit 10.1 to the Company's
Form
10-Q for the quarter ended June 30, 1999)
|
|
*10.7
|
Deferred
Compensation Plan of Transocean Offshore Inc., as amended and restated
effective January 1, 2000 (incorporated by reference to Exhibit 10.10
to
the Company's Annual Report on Form 10-K for the year ended December
31,
1999)
|
|
*10.8
|
Amendment
to Transocean Inc. Deferred Compensation Plan (incorporate by reference
to
Exhibit 10.1 to our Current Report on Form 8-K filed on December
29,
2005)
|
|
*10.9
|
Sedco
Forex Employees Option Plan of Transocean Sedco Forex Inc. effective
December 31, 1999 (incorporated by reference to Exhibit 4.5 to the
Company's Registration Statement on Form S-8 (Registration No. 333-94569)
filed January 12, 2000)
|
|
*10.10
|
Employment
Agreement dated September 22, 2000 between J. Michael Talbert and
Transocean Offshore Deepwater Drilling Inc. (incorporated by reference
to
Exhibit 10.1 to the Company's Form 10-Q for the quarter ended September
30, 2000)
|
|
*10.11
|
Agreement
dated October 10, 2002 by and among Transocean Inc., Transocean Offshore
Deepwater Drilling Inc. and J. Michael Talbert (incorporated by reference
to Exhibit 99.2 to the Company’s Current Report on Form 8-K dated October
10, 2002)
|
|
*10.12
|
Employment
Agreement dated September 17, 2000 between Robert L. Long and Transocean
Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit
10.3 to the Company's Form 10-Q for the quarter ended September 30,
2000)
|
|
*10.13
|
Agreement
dated May 9, 2002 by and among Transocean Offshore Deepwater Drilling
Inc.
and Robert L. Long (incorporated by reference to Exhibit 99.4 to
the
Company’s Current Report on Form 8-K dated October 10,
2002)
|
|
*10.14
|
Employment
Agreement dated September 20, 2000 between Eric B. Brown and Transocean
Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit
10.6 to the Company's Form 10-Q for the quarter ended September 30,
2000)
|
|
*10.15
|
Employment
Agreement dated October 4, 2000 between Barbara S. Wood and Transocean
Offshore Deepwater Drilling Inc. (incorporated by reference to Exhibit
10.7 to the Company's Form 10-Q for the quarter ended September 30,
2000)
|
|
*10.16
|
Employment
Agreement dated July 15, 2002 by and among R&B Falcon Corporation,
R&B Falcon Management Services, Inc. and Jan Rask (incorporated by
reference to Exhibit 10.1 to the Company’s Form 10-Q for the quarter ended
June 30, 2002)
|
|
*10.17
|
Amendment
No. 1 dated December 12, 2003 to the Employment Agreement dated July
15,
2002 by and among Jan Rask, R&B Falcon Management Services, Inc. and
R&B Falcon Corporation (incorporated by reference to Exhibit 10.8 to
TODCO’s Registration Statement No. 333-101921 on Form S-1 dated February
3, 2004)
|
|
*10.18
|
1992
Long-Term Incentive Plan of Reading & Bates Corporation (incorporated
by reference to Exhibit B to Reading & Bates' Proxy Statement dated
April 27, 1992)
|
|
*10.19
|
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)
|
|
*10.20
|
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)
|
|
*10.21
|
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)
|
|
*10.22
|
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)
|
|
*10.23
|
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)
|
|
*10.24
|
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)
|
|
*10.25
|
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)
|
|
10.26
|
Memorandum
of Agreement dated November 28, 1995 between Reading and Bates, Inc.,
a
subsidiary of Reading & Bates Corporation, and Deep Sea Investors,
L.L.C. (incorporated by reference to Exhibit 10.110 to Reading &
Bates' Annual Report on Form 10-K for 1995)
|
|
10.27
|
Amended
and Restated Bareboat Charter dated July 1, 1998 to Bareboat Charter
M. G.
Hulme, Jr. dated November 28, 1995 between Deep Sea Investors, L.L.C.
and Reading & Bates Drilling Co., a subsidiary of Reading & Bates
Corporation (incorporated by reference to Exhibit 10.177 to R&B
Falcon's Annual Report on Form 10-K for the year ended December 31,
1998)
|
|
10.28
|
Master
Separation Agreement dated February 4, 2004 by and among Transocean
Inc.,
Transocean Holdings Inc. and TODCO (incorporated by reference to
Exhibit
99.2 to the Company’s Current Report on Form 8-K dated March 2,
2004)
|
|
10.29
|
Tax
Sharing Agreement dated February 4, 2004 between Transocean Holdings
Inc.
and TODCO (incorporated by reference to Exhibit 99.3 to the Company’s
Current Report on Form 8-K dated March 2, 2004)
|
|
*10.30
|
Executive
Severance Benefit of Transocean Inc. effective February 9, 2005
(incorporated by reference to Exhibit 10.1 to our Current Report
on Form
8-K filed on February 15, 2005)
|
|
*10.31
|
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)
|
|
*10.32
|
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)
|
|
*10.33
|
Form
of 2004 Director Deferred Unit Award (incorporated by reference to
Exhibit
10.4 to our Current Report on Form 8-K filed on February 15,
2005)
|
|
*10.34
|
Performance
Award and Cash Bonus Plan of Transocean Inc. (incorporated by reference
to
Exhibit 10.5 to our Current Report on Form 8-K filed on February
15,
2005)
|
|
*10.35
|
Description
of Annual Cash Bonuses for Certain Executive Officers (incorporated
by
reference to Item 1.01 of the Company’s Current Report on Form 8-K filed
on February 14, 2006)
|
|
*10.36
|
Description
of Director Compensation (incorporated by reference to Item 1.01
of the
Company’s Current Report on Form 8-K filed on February 15,
2005)
|
| *10.37 | Description of Director Compensation (incorporated by reference to Item 1.01 of the Company's Current Report on Form 8-K filed on February 14, 2006) |
|
†*10.38
|
Description
of Base Salaries of Certain Executive Officers
|
|
*10.39
|
Executive
Change of Control Severance Benefit (incorporated by reference to
Exhibit
10.1 to our Current Report on Form 8-K filed on July 19,
2005)
|
|
†21
|
Subsidiaries
of the Company
|
|
†23.1
|
Consent
of Ernst & Young LLP
|
|
†24
|
Powers
of Attorney
|
|
†31.1
|
CEO
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
|
|
†31.2
|
CFO
Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of
2002
|
|
†32.1
|
CEO
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
|
†32.2
|
CFO
Certification Pursuant to Section 906 of the Sarbanes-Oxley Act of
2002
|
*Compensatory
plan or arrangement.
†Filed
herewith.
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.
SIGNATURES
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of
1934, the registrant has duly caused this report to be signed on its behalf
by
the undersigned; thereunto duly authorized, on March 9, 2006.
|
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 9, 2006.
|
Signature
|
Title
|
|
|
*
|
Chairman
of the Board of Directors
|
|
|
J.
Michael Talbert
|
||
|
/s/
Robert L. Long
|
President
and Chief Executive Officer
|
|
|
Robert
L. Long
|
(Principal
Executive Officer)
|
|
|
/s/
Gregory L. Cauthen
|
Senior
Vice President and Chief Financial Officer
|
|
|
Gregory
L. Cauthen
|
(Principal
Financial Officer)
|
|
|
/s/
David A. Tonnel
|
Vice
President and Controller
|
|
|
David
A. Tonnel
|
(Principal
Accounting Officer)
|
|
|
*
|
Director
|
|
|
Victor
E. Grijalva
|
||
|
*
|
Director
|
|
|
Judy
J. Kelly
|
||
|
*
|
Director
|
|
|
Arthur
Lindenauer
|
||
|
*
|
Director
|
|
|
Martin
B. McNamara
|
||
|
*
|
Director
|
|
|
Roberto
Monti
|
|
Signature
|
Title
|
|
|
*
|
Director
|
|
|
Richard
A. Pattarozzi
|
||
|
*
|
Director
|
|
|
Kristian
Siem
|
||
|
*
|
Director
|
|
|
Robert
M. Sprague
|
||
|
*
|
Director
|
|
|
Ian
C. Strachan
|
|
By
|
/s/
William E. Turcotte
|
|
|
William
E. Turcotte
|
||
|
(Attorney-in-Fact)
|
-
119
-
BASE
SALARIES FOR CERTAIN EXECUTIVE OFFICERS
|
Executive
Officer
|
Base
Salary
|
|||
|
|
|
|||
|
Robert
L. Long
|
$
|
750,000
|
||
|
President
and Chief Executive Officer
|
||||
|
|
||||
|
Jean
P. Cahuzac
|
$
|
435,000
|
||
|
Executive
Vice President, Chief Operating Officer
|
||||
|
|
||||
|
Gregory
L. Cauthen
|
$
|
360,000
|
||
|
Senior
Vice President and Chief Financial Officer
|
||||
|
|
||||
|
Eric
B. Brown
|
$
|
315,000
|
||
|
Senior
Vice President, General Counsel and Corporate Secretary
|
||||
|
|
||||
|
Steven
L. Newman
|
$
|
265,000
|
||
|
Senior
Vice President, Human Resources, Information Process Solutions
and
Treasury
|
||||
Exhibit
21
SUBSIDIARIES
OF TRANSOCEAN INC.*
|
Name
|
Jurisdiction
|
|
|
Agua
Profundas Limitada (60%)
|
Angola
|
|
|
Arcade
Drilling AS
|
Norway
|
|
|
Blegra
Asset Management Limited
|
Cyprus
|
|
|
Blegra
Financing Limited
|
Cyprus
|
|
|
Cariba
Ships Corporation N.V.
|
Netherlands
Antilles
|
|
|
Caspian
Sea Ventures International Ltd.
|
British
Virgin Islands
|
|
|
Cliffs
Drilling do Brasil Servicos de Petroleo S/C Ltda.
|
Brazil
|
|
|
Deepwater
Drilling II L.L.C.
|
Delaware
|
|
|
Deepwater
Drilling L.L.C.
|
Delaware
|
|
|
Falcon
Atlantic Ltd.
|
Cayman
Islands
|
|
|
Hellerup
Finance International Ltd.
|
Ireland
|
|
|
International
Chandlers, Inc.
|
Texas
|
|
|
NRB
Drilling Services Limited (60%)
|
Nigeria
|
|
|
Overseas
Drilling Ltd. (50%)
|
Liberia
|
|
|
PT
Hitek Nusantara Offshore Drilling (80%)
|
Indonesia
|
|
|
PT
Transocean Indonesia
|
Indonesia
|
|
|
R&B
Falcon (A) Pty Ltd
|
Australia
|
|
|
R&B
Falcon (Caledonia) Ltd.
|
England
|
|
|
R&B
Falcon (Ireland) Limited
|
Ireland
|
|
|
R&B
Falcon (U.K.) Ltd.
|
England
|
|
|
R&B
Falcon B.V.
|
Netherlands
|
|
|
R&B
Falcon Deepwater (UK) Limited
|
England
|
|
|
R&B
Falcon Drilling (International & Deepwater) Inc. LLC
|
Delaware
|
|
|
R&B
Falcon Drilling Co. LLC
|
Oklahoma
|
|
|
R&B
Falcon Drilling Limited, LLC
|
Oklahoma
|
|
|
R&B
Falcon Exploration Co. LLC
|
Oklahoma
|
|
|
R&B
Falcon International Energy Services B.V.
|
Netherlands
|
|
|
R&B
Falcon Offshore Limited, LLC
|
Oklahoma
|
|
|
R&B
Falcon, Inc. LLC
|
Oklahoma
|
|
|
RB
Mediterranean Ltd.
|
Cayman
Islands
|
|
|
RBF
(Nigeria) Limited
|
Nigeria
|
|
|
RBF
Drilling Co. LLC
|
Oklahoma
|
|
|
RBF
Drilling Services, Inc. LLC
|
Oklahoma
|
|
|
RBF
Exploration LLC
|
Delaware
|
|
|
RBF
Finance Co.
|
Delaware
|
|
|
RBF
Rig Corporation, LLC
|
Oklahoma
|
|
|
RBF
Servicos Angola, Limitada
|
Angola
|
|
|
Reading
& Bates Coal Co., LLC
|
Nevada
|
|
|
Reading
& Bates-Demaga Perfuracoes Ltda.
|
Brazil
|
|
|
SDS
Offshore Ltd.
|
U.K.
|
|
Sedco
Forex Corporation
|
Delaware
|
|
|
Sedco
Forex Holdings Limited
|
British
Virgin Islands
|
|
|
Sedco
Forex International Drilling, Inc.
|
Panama
|
|
|
Sedco
Forex International Services, S.A.
|
Panama
|
|
|
Sedco
Forex International, Inc.
|
Panama
|
|
|
Sedco
Forex of Nigeria Limited (60%)
|
Nigeria
|
|
|
Sedco
Forex Offshore International N.V. (Limited)
|
Netherlands
Antilles
|
|
|
Sedco
Forex Technology, Inc.
|
Panama
|
|
|
Sedneth
Panama S.A.
|
Panama
|
|
|
Sefora
Maritime Ltd.
|
British
Virgin Islands
|
|
|
Services
Petroliers Sedco Forex
|
France
|
|
|
Shore
Services, LLC
|
Texas
|
|
|
Sonat
Brasocean Servicos de Perfuracoes Ltda.
|
Brazil
|
|
|
Sonat
Offshore do Brasil Perfuracoes Maritimos Ltda.
|
Brazil
|
|
|
Sonat
Offshore S.A.
|
Panama
|
|
|
T.I.
Internationa Mexicol S. de R.L. de C.V.
|
Mexico
|
|
|
Transocean
Alaskan Ventures Inc.
|
Delaware
|
|
|
Transocean
Asie Services Sdn Bhd.
|
Malaysia
|
|
|
Transocean
Brasil Ltda.
|
Brazil
|
|
|
Transocean
CGR LLC
|
Delaware
|
|
|
Transocean
Canada Co.
|
Nova
Scotia
|
|
|
Transocean
Cunningham LLC
|
Delaware
|
|
|
Transocean
Deepwater Frontier Limited
|
Cayman
Islands
|
|
|
Transocean
Deepwater Inc.
|
Delaware
|
|
|
Transocean
Deepwater Nautilus Limited
|
Cayman
Islands
|
|
|
Transocean
Deepwater Pathfinder Limited
|
Cayman
Islands
|
|
|
Transocean
Discoverer 534 LLC
|
Delaware
|
|
|
Transocean
Drilling (Nigeria) Ltd.
|
Nigeria
|
|
|
Transocean
Drilling (U.S.A.) Inc.
|
Texas
|
|
|
Transocean
Drilling Ltd.
|
U.K.
|
|
|
Transocean
Drilling Services Inc.
|
Delaware
|
|
|
Transocean
Eastern Pte Ltd
|
Singapore
|
|
|
Transocean
Enterprise Inc.
|
Delaware
|
|
|
Transocean
Europe Holdings Ltd
|
Cayman
Islands
|
|
|
Transocean
Europe Ventures Holdings Ltd
|
Cayman
Islands
|
|
|
Transocean
Holdings Inc
|
Delaware
|
|
|
Transocean
I AS
|
Norway
|
|
|
Transocean
International Drilling Limited
|
Cayman
Islands
|
|
|
Transocean
International Drilling, Inc.
|
Delaware
|
|
|
Transocean
International Resources Limited
|
British
Virgin Islands
|
|
|
Transocean
Investimentos Ltda.
|
Brazil
|
|
|
Transocean
Investments S.a.r.l.
|
Luxembourg
|
|
|
Transocean
Jupiter LLC
|
Delaware
|
|
|
Transocean
LR34 LLC
|
Delaware
|
|
Transocean
(Mediterranean & Red Sea) Drilling Limited
|
Cayman
Islands
|
|
|
Transocean
Management Inc.
|
Delaware
|
|
|
Transocean
Mediterranean LLC
|
Delaware
|
|
|
Transocean
Offshore Canada Services Ltd.
|
Alberta
|
|
|
Transocean
Offshore (Cayman) Inc.
|
Cayman
Islands
|
|
|
Transocean
Offshore (North Sea) Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore (U.K.) Inc.
|
Delaware
|
|
|
Transocean
Offshore Caribbean Sea, L.L.C.
|
Delaware
|
|
|
Transocean
Offshore D.V. Inc
|
Delaware
|
|
|
Transocean
Offshore Deepwater Drilling Inc.
|
Delaware
|
|
|
Transocean
Offshore Deepwater Holdings Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore Drilling Limited
|
U.K.
|
|
|
Transocean
Offshore Drilling Services, LLC
|
Delaware
|
|
|
Transocean
Offshore Europe Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore Holdings Ltd
|
Cayman
Islands
|
|
|
Transocean
Offshore International Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore International Ventures Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore Limited
|
Cayman
Islands
|
|
|
Transocean
Offshore Nigeria Ltd.
|
Nigeria
|
|
|
Transocean
Offshore Norway Inc.
|
Delaware
|
|
|
Transocean
Offshore Services Ltd.
|
Cayman
Islands
|
|
|
Transocean
Offshore USA Inc.
|
Delaware
|
|
|
Transocean
Offshore Ventures Inc.
|
Delaware
|
|
|
Transocean
Payroll Services SRL
|
Barbados
|
|
|
Transocean
Richardson LLC
|
Delaware
|
|
|
Transocean
Sedco Forex Ventures Limited
|
Cayman
Islands
|
|
|
Transocean
Services AS
|
Norway
|
|
|
Transocean
Services UK Ltd.
|
U.K.
|
|
|
Transocean
Seven Seas LLC
|
Delaware
|
|
|
Transocean
Support Services Limited
|
Cayman
Islands
|
|
|
Transocean
Support Services Nigeria Ltd.
|
Nigeria
|
|
|
Transocean
Support Services Pvt. Ltd.
|
India
|
|
|
Transocean
Technical Services Inc.
|
Panama
|
|
|
Transocean
Treasury Services SRL
|
Barbados
|
|
|
Transocean
UK Limited
|
U.K.
|
|
|
Transocean-Nabors
Drilling Technology LLC (50%)
|
Delaware
|
|
|
Triton
Drilling Limited
|
Cayman
Islands
|
|
|
Triton
Drilling Mexico LLC
|
Delaware
|
|
|
Triton
Financing LLC
|
Hungary
|
|
|
Triton
Holdings Limited
|
British
Virgin Islands
|
|
|
Triton
Hungary Asset Management Kft
|
Hungary
|
|
|
Triton
Industries, Inc.
|
Panama
|
|
|
Triton
Management Services Kft.
|
Hungary
|
|
|
Triton
Offshore Leasing Services Limited
|
Labuan,
Malaysia
|
|
|
Wilrig
Drilling (Canada) Inc.
|
Canada
|
|
|
Wilrig
Offshore (UK) Ltd.
|
U.K.
|
*Subsidiaries
(50% or greater ownership) are owned 100% unless otherwise
indicated.
Exhibit
23.1
Consent
of Independent Registered Public Accounting Firm
We
consent to the incorporation by reference in the following Registration
Statements of Transocean Inc.:
|
(1)
|
Registration
Statement (Form S-3 No. 333-58604),
|
|
(2)
|
Registration
Statement (Form S-4 No. 333-46374 as amended by Post-effective Amendments
on Form S-8 and Form S-3),
|
|
(3)
|
Registration
Statement (Form S-4 No. 333-54668 as amended by Post-Effective Amendments
on Form S-8 and Form S-3),
|
|
(4)
|
Registration
Statement (Form S-8 No. 33-64776),
|
|
(5)
|
Registration
Statement (Form S-8 No. 33-66036),
|
|
(6)
|
Registration
Statement (Form S-8 No. 333-12475),
|
|
(7)
|
Registration
Statement (Form S-8 No. 333-58211),
|
|
(8)
|
Registration
Statement (Form S-8 No. 333-58203),
|
|
(9)
|
Registration
Statement (Form S-8 No. 333-94543),
|
|
(10)
|
Registration
Statement (Form S-8 No. 333-94569),
|
|
(11)
|
Registration
Statement (Form S-8 No. 333-94551),
|
|
(12)
|
Registration
Statement (Form S-8 No. 333-75532),
|
|
(13)
|
Registration
Statement (Form S-8 No. 333-75540),
|
|
(14)
|
Registration
Statement (Form S-8 No. 333-106026),
|
|
(15)
|
Registration
Statement (Form S-8 No. 333-115456),
and
|
|
(16)
|
Registration
Statement (Form S-8 No. 333-130282);
|
of
our
reports dated March 8, 2006, with respect to the consolidated financial
statements and schedule of Transocean Inc. and Subsidiaries, Transocean Inc.
management’s assessment of the effectiveness of internal control over financial
reporting, and the effectiveness of internal control over financial reporting
of
Transocean Inc., included in this Annual Report (Form 10-K) for the year ended
December 31, 2005.
/s/
Ernst
& Young LLP
Houston,
Texas
March
8,
2006
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
J. Michael Talbert
|
|
|
Name:
|
J.
Michael Talbert
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Victor E. Grijalva
|
|
|
Name:
|
Victor
E. Grijalva
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Judy J. Kelly
|
|
|
Name:
|
Judy
J. Kelly
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Arthur Lindenauer
|
|
|
Name:
|
Arthur
Lindenauer
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Martin B. McNamara
|
|
|
Name:
|
Martin
B. McNamara
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Roberto Monti
|
|
|
Name:
|
Roberto
Monti
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Richard A. Pattarozzi
|
|
|
Name:
|
Richard
A. Pattarozzi
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Kristian Siem
|
|
|
Name:
|
Kristian
Siem
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Robert M. Sprague
|
|
|
Name:
|
Robert
M. Sprague
|
TRANSOCEAN
INC.
Power
of Attorney
WHEREAS,
TRANSOCEAN INC., a Cayman Islands company (the “Company”), intends to file with
the Securities and Exchange Commission (the “Commission”) pursuant to the
Securities Exchange Act of 1934, as amended, and the rules and regulations
of
the Commission promulgated thereunder, an Annual Report on Form 10-K for the
fiscal year ended December 31, 2005 of the Company, together with any and all
exhibits, documents and other instruments and documents necessary, advisable
or
appropriate in connection therewith, including any amendments thereto (the
“Form
10-K”);
NOW,
THEREFORE, the undersigned, in his capacity as a director or officer or both,
as
the case may be, of the Company, does hereby appoint Robert L. Long, Gregory
L.
Cauthen, Eric B. Brown, William E. Turcotte and David Tonnel, and each of them
severally, his true and lawful attorney or attorneys with power to act with
or
without the other, and with full power of substitution and resubstitution,
to
execute in his name, place and stead, in his capacity as director, officer
or
both, as the case may be, of the Company, the Form 10-K and any and all
amendments thereto, including any and all exhibits and other instruments and
documents said attorney or attorneys shall deem necessary, appropriate or
advisable in connection therewith, and to file the same with the Commission
and
to appear before the Commission in connection with any matter relating thereto.
Each of said attorneys shall have full power and authority to do and perform
in
the name and on behalf of the undersigned, in any and all capacities, every
act
whatsoever necessary or desirable to be done in the premises, as fully and
to
all intents and purposes as the undersigned might or could do in person, the
undersigned hereby ratifying and approving the acts that said attorneys and
each
of them, or their or his substitutes or substitute, may lawfully do or cause
to
be done by virtue hereof.
IN
WITNESS WHEREOF, the undersigned has executed this power of attorney as of
the
9th day of February, 2006.
|
By:
|
/s/
Ian C. Strachan
|
|
|
Name:
|
Ian
C. Strachan
|
Exhibit
31.1
CEO
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF
2002
I,
Robert
L. Long, certify that:
|
1.
|
I
have reviewed this annual report on Form 10-K of Transocean
Inc.,
|
|
2.
|
Based
on my knowledge, this annual report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to
make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
annual report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this annual report, fairly present in all material respects
the financial condition, results of operations and cash flows of
the
registrant as of, and for, the periods presented in this annual
report;
|
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and we
have:
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is
being prepared;
|
|
b)
|
designed
such internal control over financial reporting, or caused such internal
control over financial reporting to be designed under our supervision,
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;
and
|
|
c)
|
evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the
end of
the period covered by this annual report based on such evaluation;
and
|
|
d)
|
disclosed
in this annual report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely
to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting,
to
the registrant’s auditors and the audit committee of registrant’s board of
directors (or persons performing the equivalent
function):
|
|
a)
|
all
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
Date:
March 9, 2006
|
/s/
Robert L. Long
|
|
|
Robert
L. Long
|
||
|
President
and Chief Executive Officer
|
Exhibit
31.2
CFO
CERTIFICATION PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF
2002
I,
Gregory L. Cauthen, certify that:
|
1.
|
I
have reviewed this annual report on Form 10-K of Transocean
Inc.,
|
|
2.
|
Based
on my knowledge, this annual report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to
make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
annual report;
|
|
3.
|
Based
on my knowledge, the financial statements, and other financial information
included in this annual report, fairly present in all material respects
the financial condition, results of operations and cash flows of
the
registrant as of, and for, the periods presented in this annual
report;
|
|
4.
|
The
registrant’s other certifying officer and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal
control over financial reporting (as defined in Exchange Act Rules
13a-15(f) and 15d-15(f)) for the registrant and we
have:
|
|
a)
|
designed
such disclosure controls and procedures, or caused such disclosure
controls and procedures to be designed under our supervision, to
ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this annual report
is
being prepared;
|
|
b)
|
designed
such internal control over financial reporting, or caused such
internal
control over financial reporting to be designed under our supervision,
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;
and
|
|
c)
|
evaluated
the effectiveness of the registrant’s disclosure controls and procedures
and presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures, as of
the end of
the period covered by this annual report based on such evaluation;
and
|
|
d)
|
disclosed
in this annual report any change in the registrant’s internal control over
financial reporting that occurred during the registrant’s most recent
fiscal quarter (the registrant’s fourth fiscal quarter in the case of an
annual report) that has materially affected, or is reasonably likely
to
materially affect, the registrant’s internal control over financial
reporting; and
|
|
5.
|
The
registrant’s other certifying officer and I have disclosed, based on our
most recent evaluation of internal control over financial reporting,
to
the registrant’s auditors and the audit committee of registrant’s board of
directors (or persons performing the equivalent
function):
|
|
a)
|
all
significant deficiencies and material weaknesses in the design or
operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrant’s ability to record,
process, summarize and report financial information;
and
|
|
b)
|
any
fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant’s internal control
over financial reporting.
|
|
Date:
March 9, 2006
|
/s/
Gregory L. Cauthen
|
|
|
Gregory
L. Cauthen
|
||
|
Senior
Vice President and Chief Financial Officer
|
Exhibit
32.1
CERTIFICATION
PURSUANT TO SECTION 906 OF
THE
SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)
OF
SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE)
Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
Section 1350, Chapter 63 of Title 18, United States Code), I, Robert L. Long,
President and Chief Executive Officer of Transocean Inc., a Cayman Islands
company (the “Company”), hereby certify, to my knowledge, that:
|
(1)
|
the
Company’s Annual Report on Form 10-K for the year ended December 31, 2005
(the “Report”) fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934;
and
|
|
(2)
|
information
contained in the Report fairly presents, in all material respects,
the
financial condition and results of operations of the
Company.
|
|
Dated:
|
March
9, 2006
|
/s/
Robert L. Long
|
|||
|
Name:
|
Robert
L. Long
|
||||
|
President
and Chief Executive Officer
|
The
foregoing certification is being furnished solely pursuant to Section 906 of
the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter
63
of Title 18, United States Code) and is not being filed as part of the Report
or
as a separate disclosure document.
A
signed
original of this written statement required by Section 906 has been provided
to
Transocean Inc. and will be retained by Transocean Inc. and furnished to the
Securities and Exchange Commission or its staff upon request.
Exhibit
32.2
CERTIFICATION
PURSUANT TO SECTION 906 OF
THE
SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b)
OF
SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE)
Pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of
Section 1350, Chapter 63 of Title 18, United States Code), I, Gregory L.
Cauthen, Senior Vice President and Chief Financial Officer of Transocean Inc.,
a
Cayman Islands company (the “Company”), hereby certify, to my knowledge,
that:
|
(1)
|
the
Company’s Annual Report on Form 10-K for the year ended December 31, 2005
(the “Report”) fully complies with the requirements of Section 13(a) or
15(d) of the Securities Exchange Act of 1934;
and
|
|
(2)
|
information
contained in the Report fairly presents, in all material respects,
the
financial condition and results of operations of the
Company.
|
|
Dated:
|
March
9, 2006
|
/s/
Gregory L. Cauthen
|
|||
|
Name:
|
Gregory
L. Cauthen
|
||||
|
Senior
Vice President and Chief Financial Officer
|
The
foregoing certification is being furnished solely pursuant to Section 906 of
the
Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter
63
of Title 18, United States Code) and is not being filed as part of the Report
or
as a separate disclosure document.
A
signed
original of this written statement required by Section 906 has been provided
to
Transocean Inc. and will be retained by Transocean Inc. and furnished to the
Securities and Exchange Commission or its staff upon request.