Transocean 10-K 12-31-2004
UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
_________________
FORM
10-K
| [X] |
|
ANNUAL
REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF
1934 |
For the fiscal year ended December 31, 2004
| [ ] |
|
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 (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 [ ]
Indicate
by check mark if disclosure of delinquent filers pursuant to Item 405 of
Regulation S-K is not contained herein, and will not be contained, to the best
of registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. [ ]
Indicate
by check mark whether the registrant is an accelerated filer. Yes [x] No [
]
As of
June 30, 2004, 320,819,763 ordinary shares were outstanding and the aggregate
market value of such shares held by non-affiliates was approximately $9.3
billion (based on the reported closing market price of the ordinary shares on
such date of $28.94 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, 2005, 324,073,235 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, 2004, for its 2004
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, 2004
| Item |
|
Page |
| |
PART
I |
|
|
ITEM
1. |
|
3 |
| |
|
3 |
| |
|
4 |
| |
|
9 |
| |
|
10 |
| |
|
10 |
| |
|
10 |
| |
|
10 |
| |
|
11 |
| |
|
11 |
| |
|
12 |
|
ITEM
2. |
|
12 |
|
ITEM
3. |
|
12 |
|
ITEM
4. |
|
14 |
| |
|
14 |
| |
|
|
| |
PART
II |
|
|
ITEM
5. |
|
16 |
|
ITEM
6. |
|
18 |
|
ITEM
7. |
|
19 |
|
ITEM
7A. |
|
55 |
|
ITEM
8. |
|
56 |
|
ITEM
9. |
|
107 |
|
ITEM
9A. |
|
107 |
|
ITEM
9B. |
|
107 |
| |
|
|
| |
PART
III |
|
|
ITEM
10. |
|
107 |
|
ITEM
11. |
|
107 |
|
ITEM
12. |
|
107 |
|
ITEM
13. |
|
107 |
|
ITEM
14. |
|
107 |
| |
|
|
| |
PART
IV |
|
|
ITEM
15. |
|
108 |
PART
I
Transocean
Inc. (together with its subsidiaries and predecessors, unless the context
requires otherwise, “Transocean,” the “Company,” “we,” “us” or “our”) is a
leading international provider of offshore contract drilling services for oil
and gas wells. As of February 28, 2005, we owned, had partial ownership
interests in or operated 93 mobile offshore and barge drilling units. As of this
date, our fleet included 32 High-Specification semisubmersibles and drillships
(“floaters”), 24 Other Floaters, 26 Jackup Rigs and 11 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.”
The
discussion of our business excludes TODCO (together with its subsidiaries and
predecessors, unless the context requires otherwise, “TODCO”), a publicly traded
company and a former wholly-owned subsidiary in which we now have a 22 percent
interest and account for under the equity method of accounting. See “—Background
of Transocean.” TODCO’s results of operations are included in our consolidated
financial statements until December 17, 2004, when TODCO was deconsolidated. Any
discussion of our consolidated financial results through December 16, 2004
includes TODCO.
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 and the TODCO segment, respectively. In preparation for
the initial public offering discussed below, we transferred all assets and
businesses 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
TODCO Offering” and “December TODCO Offering” and, together with the TODCO IPO,
the “TODCO Offerings”). We sold 17.9 million shares of TODCO class A common
stock (30 percent of TODCO’s total outstanding shares) in the September TODCO
Offering and 15.0 million shares of TODCO class A common stock (25 percent of
TODCO’s total outstanding shares) in the December TODCO Offering. Prior to the
December TODCO 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 TODCO Offering, we converted
all of our remaining TODCO class B common stock not sold in the TODCO Offerings
into shares of class A common stock. After the TODCO Offerings, we hold 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
sheets. As a result of the conversion of the TODCO class B common stock into
class A common stock, we no longer have a majority voting interest in TODCO and
no longer consolidate TODCO in our financial statements but account for our
remaining investment under the equity method of accounting.
Beginning
December 17, 2004, we recorded our 22 percent interest in TODCO’s net income as
equity in earnings in our consolidated statement of operations. Our current
intention is to dispose of our remaining interest in TODCO, which could be
achieved through a number of possible transactions including additional public
offerings, open market sales, sales to one or more third parties, a spin-off to
our shareholders, split-off offerings to our shareholders that would allow for
the opportunity to exchange our ordinary shares for shares of TODCO class A
common stock or a combination of these transactions.
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 21 to our consolidated financial statements
included in Item 8 of this report. For information about the risks and
uncertainties relating to our business, see “Item 7. Management’s Discussion and
Analysis of Financial Condition and Results of Operations—Risk
Factors.”
We
principally use three types of drilling rigs:
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
February 28, 2005, our fleet of 93 rigs included:
| |
· |
32
High-Specification Floaters, which are comprised of:
|
|
- |
13
Fifth-Generation Deepwater
Floaters; |
|
- |
15
Other Deepwater Floaters; and |
|
- |
four
Other High-Specification
Floaters; |
| |
· |
11
Other Rigs, which are comprised
of: |
|
- |
four
barge drilling rigs; |
|
- |
one
platform drilling rig; |
|
- |
one
mobile offshore production unit;
and |
As of
February 28, 2005, our fleet was located in the U.S. Gulf of Mexico (13 units),
Trinidad (one unit), Canada (one unit), Brazil (nine units), North Europe (17
units), the Mediterranean and Middle East (eight units), the Caspian Sea (one
unit), Africa (14 units), India (11 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 segment
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 last construction cycle (approximately 1996 - 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 are equipped
for dual-activity drilling, which is a well-construction technology we developed
and patented that allows for drilling tasks associated with a single well to be
accomplished in a parallel rather than sequential manner by utilizing two
complete drilling systems under a single derrick. The dual-activity
well-construction process is designed to reduce critical path activity and
improve 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 rough water conditions than drillships. Our
three Express-class semisubmersibles 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 as “operating” 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 “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. 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
fleet as of February 28, 2005:
| |
|
Year |
Water |
Drilling |
|
|
|
| |
|
Entered |
Depth |
Depth |
|
|
|
| |
|
Service/ |
Capacity |
Capacity |
|
|
Estimated |
Name |
Type |
Upgraded(a) |
(in
feet) |
(in
feet) |
Location |
Customer |
Expiration
(b) |
|
Fifth-Generation
Deepwater Floaters (13) |
|
|
|
|
|
|
|
|
Deepwater
Discovery (c) |
HSD |
2000 |
10,000 |
30,000 |
Ivory
Coast |
Vanco |
March
2005 |
|
Deepwater
Expedition (c) |
HSD |
1999 |
10,000 |
30,000 |
Brazil |
Petrobras |
October
2005 |
|
Deepwater
Frontier (c) |
HSD |
1999 |
10,000 |
30,000 |
Brazil |
Petrobras |
March
2006 |
|
Deepwater
Millennium (c) |
HSD |
1999 |
10,000 |
30,000 |
U.S.
Gulf |
Anadarko |
June
2005 |
| |
|
|
|
|
U.S.
Gulf |
Anadarko |
December
2005 |
|
Deepwater
Pathfinder (c) |
HSD |
1998 |
10,000 |
30,000 |
Nigeria |
Devon |
April
2006 |
|
Discoverer
Deep Seas (c) (f) |
HSD |
2001 |
10,000 |
35,000 |
U.S.
Gulf |
ChevronTexaco |
January
2006 |
| |
|
|
|
|
U.S.
Gulf |
ChevronTexaco |
January
2007 |
|
Discoverer
Enterprise (c) (f) |
HSD |
1999 |
10,000 |
35,000 |
U.S.
Gulf |
BP |
December
2007 |
|
Discoverer
Spirit (c) (f) |
HSD |
2000 |
10,000 |
35,000 |
U.S.
Gulf |
Unocal |
September
2005 |
| |
|
|
|
|
U.S.
Gulf |
Shell |
March
2007 |
|
Deepwater
Horizon (c) |
HSS |
2001 |
10,000 |
30,000 |
U.S.
Gulf |
BP |
September
2005 |
|
Cajun
Express (c) (g) |
HSS |
2001 |
8,500 |
35,000 |
U.S.
Gulf |
Dominion |
May
2005 |
| |
|
|
|
|
U.S.
Gulf |
ChevronTexaco |
June
2007 |
|
Deepwater
Nautilus (d) |
HSS |
2000 |
8,000 |
30,000 |
U.S.
Gulf |
Shell |
September
2005 |
| |
|
|
|
|
U.S.
Gulf |
Shell |
September
2006 |
|
Sedco
Energy (c) (g) |
HSS |
2001 |
7,500 |
25,000 |
Nigeria |
ChevronTexaco |
March
2005 |
|
Sedco
Express (c) (g) |
HSS |
2001 |
7,500 |
25,000 |
Brazil |
- |
Shipyard |
| |
|
|
|
|
Angola |
BP |
May
2008 |
|
Other
Deepwater Floaters (15) |
|
|
|
|
|
|
|
|
Deepwater
Navigator (c) |
HSD |
2000 |
7,200 |
25,000 |
Brazil |
Petrobras |
March
2005 |
|
Discoverer
534 (c) |
HSD |
1975/1991 |
7,000 |
25,000 |
India |
Reliance |
March
2005 |
|
Discoverer
Seven Seas (c) |
HSD |
1976/1997 |
7,000 |
25,000 |
India |
ONGC |
February
2007 |
|
Transocean
Marianas |
HSS |
1979/1998 |
7,000 |
25,000 |
U.S.
Gulf |
Murphy |
April
2005 |
| |
|
|
|
|
U.S.
Gulf |
BP |
November
2005 |
|
Sedco
707 (c) |
HSS |
1976/1997 |
6,500 |
25,000 |
Brazil |
Petrobras |
November
2005 |
|
Jack
Bates |
HSS |
1986/1997 |
5,400 |
30,000 |
Australia |
Woodside |
September
2005 |
|
Peregrine
I (c) |
HSD |
1982/1996 |
5,200 |
25,000 |
Brazil |
Cold
stacked |
- |
|
Sedco
709 (c) |
HSS |
1977/1999 |
5,000 |
25,000 |
Ivory
Coast |
CNR |
April
2005 |
|
M.
G. Hulme, Jr. (e) |
HSS |
1983/1996 |
5,000 |
25,000 |
Nigeria |
Warm
stacked |
- |
|
Transocean
Richardson |
HSS |
1988 |
5,000 |
25,000 |
Ivory
Coast |
CNR |
December
2005 |
|
Jim
Cunningham |
HSS |
1982/1995 |
4,600 |
25,000 |
Egypt |
BG |
August
2005 |
|
Transocean
Leader |
HSS |
1987/1997 |
4,500 |
25,000 |
Norway |
Statoil |
February
2006 |
|
Transocean
Rather |
HSS |
1988 |
4,500 |
25,000 |
U.K.
North Sea |
BP |
October
2005 |
| |
|
|
|
|
U.K.
North Sea |
BP |
December
2005 |
| |
|
|
|
|
U.K.
North Sea |
BP |
February
2006 |
|
Sovereign
Explorer |
HSS |
1984 |
4,500 |
25,000 |
Venezuela |
Statoil |
March
2005 |
| |
|
|
|
|
Trinidad |
BG |
August
2005 |
|
Sedco
710 (c) |
HSS |
1983/2001 |
4,500 |
25,000 |
Brazil |
Petrobras |
October
2006 |
| |
|
|
|
|
|
|
|
Other
High-Specification Floaters (4) |
|
|
|
|
|
|
|
Henry
Goodrich |
HSS |
1985 |
2,000 |
30,000 |
Canada |
Terra
Nova |
August
2005 |
|
Paul
B. Loyd, Jr. |
HSS |
1990 |
2,000 |
25,000 |
U.K.
North Sea |
BP |
March
2005 |
| |
|
|
|
|
U.K.
North Sea |
BP |
March
2007 |
|
Transocean
Arctic |
HSS |
1986 |
1,650 |
25,000 |
Norwegian
N. Sea |
Statoil |
March
2006 |
|
Polar
Pioneer |
HSS |
1985 |
1,500 |
25,000 |
Norwegian
N. Sea |
Statoil |
July
2006 |
_______________________________________
“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 the contract for
each rig is likely to expire. 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) |
The
M. G. Hulme, Jr. is leased from its owner, an unrelated third
party, under an operating lease as a result of a sale/leaseback
transaction in November 1995. We have exercised the purchase option to
reacquire the rig in the fourth quarter of 2005 (see “―Item 7.
Management’s Discussion and Analysis of Financial Condition and Results of
Operations―Acquisitions and Dispositions”). |
| (f) |
Enterprise-class
rig. |
Other
Floaters (24)
The
following table provides certain information regarding our Other Floater
drilling rigs as of February 28, 2005:
| |
|
Year |
Water |
Drilling |
|
|
|
| |
|
Entered |
Depth |
Depth |
|
|
|
| |
|
Service/ |
Capacity |
Capacity |
|
|
Estimated |
Name |
Type |
Upgraded(a) |
(in
feet) |
(in
feet) |
Location |
Customer |
Expiration
(b) |
|
Peregrine
III (c) |
OD |
1976 |
4,200 |
25,000 |
U.S.
Gulf |
Cold
stacked |
- |
|
Sedco
700 |
OS |
1973/1997 |
3,600 |
25,000 |
Equatorial
Guinea |
Amerada
Hess |
January
2006 |
|
Transocean
Amirante |
OS |
1978/1997 |
3,500 |
25,000 |
U.S.
Gulf |
ENI |
August
2005 |
| |
|
|
|
|
U.S.
Gulf |
Remington |
February
2006 |
|
Transocean
Legend |
OS |
1983 |
3,500 |
25,000 |
Enroute
to Singapore |
Warm
stacked |
- |
|
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 |
July
2006 |
|
Falcon
100 |
OS |
1974/1999 |
2,400 |
25,000 |
U.S.
Gulf |
LLOG |
July
2005 |
| |
|
|
|
|
U.S.
Gulf |
LLOG |
January
2006 |
|
Sedco
703 |
OS |
1973/1995 |
2,000 |
25,000 |
Australia |
ENI |
March
2005 |
| |
|
|
|
|
Australia |
OMV |
May
2005 |
|
Sedco
711 |
OS |
1982 |
1,800 |
25,000 |
U.K.
North Sea |
Shell |
December
2005 |
|
Transocean
John Shaw |
OS |
1982 |
1,800 |
25,000 |
U.K.
North Sea |
Nexen |
May
2005 |
| |
|
|
|
|
U.K.
North Sea |
KerrMcGee |
August
2005 |
|
Sedco
714 |
OS |
1983/1997 |
1,600 |
25,000 |
U.K.
North Sea |
BG |
March
2005 |
| |
|
|
|
|
U.K.
North Sea |
BG |
April
2005 |
| |
|
|
|
|
U.K.
North Sea |
BG |
May
2005 |
| |
|
|
|
|
U.K.
North Sea |
ADTI |
August
2005 |
|
Sedco
712 |
OS |
1983 |
1,600 |
25,000 |
U.K.
North Sea |
Oilexco |
March
2006 |
|
Actinia |
OS |
1982 |
1,500 |
25,000 |
India |
Reliance |
August
2005 |
|
Sedco
601 |
OS |
1983 |
1,500 |
25,000 |
Indonesia |
Santos |
March
2005 |
| |
|
|
|
|
Indonesia |
Santos |
April
2005 |
| |
|
|
|
|
Indonesia |
Santos |
June
2005 |
| |
|
|
|
|
Indonesia |
Santos |
July
2005 |
|
Sedco
702 |
OS |
1973/1992 |
1,500 |
25,000 |
Australia |
Cold
stacked |
- |
|
Sedneth
701 |
OS |
1972/1993 |
1,500 |
25,000 |
Angola |
ChevronTexaco |
March
2005 |
|
Transocean
Prospect |
OS |
1983/1992 |
1,500 |
25,000 |
U.K.
North Sea |
Cold
stacked |
- |
|
Transocean
Searcher |
OS |
1983/1988 |
1,500 |
25,000 |
Norwegian
N. Sea |
Statoil |
May
2005 |
|
Transocean
Winner |
OS |
1983 |
1,500 |
25,000 |
Norwegian
N. Sea |
Cold
stacked |
- |
|
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 |
August
2005 |
|
Sedco
704 |
OS |
1974/1993 |
1,000 |
25,000 |
U.K.
North Sea |
Venture |
March
2005 |
| |
|
|
|
|
U.K.
North Sea |
Venture |
June
2006 |
|
Sedco
706 |
OS |
1976/1994 |
1,000 |
25,000 |
U.K.
North Sea |
Total |
September
2005 |
_______________________________________
“OD”
means other drillship.
“OS”
means other 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 the contract for
each rig is likely to expire. 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. |
Jackup
Rigs (26)
The
following table provides certain information regarding our Jackup Rig fleet as
of February 28, 2005:
| |
Year
Entered |
Water
Depth |
Drilling
Depth |
|
|
|
| |
Service/ |
Capacity |
Capacity |
|
|
Estimated |
Name |
Upgraded(a) |
(in
feet) |
(in
feet) |
Location |
Customer |
Expiration
(b) |
|
Trident
IX |
1982 |
400 |
21,000 |
Vietnam |
JVPC |
September
2005 |
| |
|
|
|
Vietnam |
JVPC |
September
2006 |
|
Trident
17 |
1983 |
355 |
25,000 |
Vietnam |
Petronas
Carigali |
April
2006 |
|
Trident
20 |
2000 |
350 |
25,000 |
Caspian
Sea |
Petronas
Carigali |
July
2005 |
|
Harvey
H. Ward |
1981 |
300 |
25,000 |
Malaysia |
Talisman |
July
2005 |
|
J.
T. Angel |
1982 |
300 |
25,000 |
Indonesia |
BP |
October
2005 |
|
Roger
W. Mowell |
1982 |
300 |
25,000 |
Malaysia |
Talisman |
November
2005 |
|
Ron
Tappmeyer |
1978 |
300 |
25,000 |
India |
ONGC |
November
2006 |
|
D.
R. Stewart |
1980 |
300 |
25,000 |
Italy |
ENI |
March
2005 |
| |
|
|
|
Italy |
ENI |
March
2006 |
|
Randolph
Yost |
1979 |
300 |
25,000 |
India |
ONGC |
November
2006 |
|
C.
E. Thornton |
1974 |
300 |
25,000 |
India |
ONGC |
October
2007 |
|
F.
G. McClintock |
1975 |
300 |
25,000 |
India |
ONGC |
December
2007 |
|
Shelf
Explorer |
1982 |
300 |
25,000 |
Indonesia |
Kodeco |
July
2005 |
|
Transocean
III |
1978/1993 |
300 |
20,000 |
Egypt |
Zeitco |
July
2005 |
|
Transocean
Nordic |
1984 |
300 |
25,000 |
India |
Reliance |
March
2005 |
| |
|
|
|
India |
ONGC |
April
2007 |
|
Trident
II |
1977/1985 |
300 |
25,000 |
India |
ONGC |
May
2006 |
|
Trident
IV-A |
1980/1999 |
300 |
25,000 |
Egypt |
IEOC |
March
2005 |
| |
|
|
|
Italy |
ENI |
July
2005 |
|
Trident
VIII |
1981 |
300 |
21,000 |
Nigeria |
Conoil |
August
2005 |
| |
|
|
|
Nigeria |
Conoil |
January
2008 |
|
Trident
XII |
1982/1992 |
300 |
25,000 |
India |
ONGC |
November
2006 |
|
Trident
XIV |
1982/1994 |
300 |
20,000 |
Angola |
ChevronTexaco |
April
2005 |
|
Trident
15 |
1982 |
300 |
25,000 |
Thailand |
Unocal |
February
2006 |
|
Trident
16 |
1982 |
300 |
25,000 |
Thailand |
ChevronTexaco |
April
2005 |
|
George
H. Galloway |
1984 |
300 |
25,000 |
Italy |
ENI |
July
2005 |
|
Transocean
Comet |
1980 |
250 |
20,000 |
Egypt |
GUPCO |
October
2005 |
|
Transocean
Mercury |
1969/1998 |
250 |
20,000 |
Egypt |
Geisum |
May
2005 |
|
Trident
VI |
1981 |
220 |
21,000 |
India |
Reliance |
March
2005 |
| |
|
|
|
Vietnam |
VSP |
March
2006 |
|
Transocean
Jupiter |
1981/1997 |
170 |
16,000 |
United
Arab Emirates |
Cold
stacked |
- |
______________________________
| |
(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 the contract for
each rig is likely to expire. 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 four drilling barges, four tenders, a platform
drilling rig, 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 West Africa and Southeast Asia.
Operating
revenues and long-lived assets by country are as follows (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Operating
Revenues |
|
|
|
|
|
|
|
|
United
States |
|
$ |
856 |
|
$ |
753 |
|
$ |
753 |
|
|
Brazil |
|
|
278 |
|
|
317 |
|
|
283 |
|
|
India |
|
|
271 |
|
|
120 |
|
|
101 |
|
|
United
Kingdom |
|
|
209 |
|
|
212 |
|
|
346 |
|
|
Other
Countries (a) |
|
|
1,000 |
|
|
1,032 |
|
|
1,191 |
|
|
Total
Operating Revenues |
|
$ |
2,614 |
|
$ |
2,434 |
|
$ |
2,674 |
|
| |
|
As
of December 31, |
|
| |
|
2004 |
|
2003 |
|
Long-Lived
Assets |
|
|
|
|
|
|
United
States |
|
$ |
2,397 |
|
$ |
3,209 |
|
|
Brazil |
|
|
865 |
|
|
1,277 |
|
|
Nigeria |
|
|
811 |
|
|
439 |
|
|
Other
Countries (a) |
|
|
2,932 |
|
|
3,085 |
|
|
Total
Long-Lived Assets |
|
$ |
7,005 |
|
$ |
8,010 |
|
______________________
(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 1, 2005, 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. 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, or by exercising a right of first refusal. 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.
During
the past five years, we have engaged 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, ChevronTexaco and ONGC. Our largest unaffiliated clients in
2004 were BP, Petrobras and ChevronTexaco, with each accounting for
approximately 10 percent of our 2004 operating revenues. No other unaffiliated
client accounted for 10 percent or more of our 2004 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.
Certain
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.
Although
significant capital expenditures may be required to comply with these
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, 2005, we had approximately 8,600 employees and we also utilized
approximately 2,200 persons through contract labor providers. As of such date,
approximately 15 percent of our employees and contract labor worldwide worked
under collective bargaining agreements, most of whom worked in Norway, U.K. and
Nigeria. Of these represented individuals, 100 percent are working under
agreements that are subject to salary negotiation in 2005. 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.
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, the Middle East, India and Asia. We lease most of these
facilities.
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. Based on a recent decision of the Mississippi Supreme
Court, we anticipate that the trial courts may grant motions requiring each
plaintiff to name the specific defendant or defendants against whom such
plaintiff makes a claim and the time period and location of asbestos exposure so
that the cases may be properly severed. We have not yet had an opportunity to
conduct any discovery nor have we been able to determine the number of
plaintiffs, if any, 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 actions to have a
material adverse effect on our current consolidated financial position, results
of operations and cash flows.
In 1990
and 1991, two of our subsidiaries were served with various assessments
collectively valued at approximately $6.8 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 $5.9 million. We are continuing to challenge the
assessment, however, and have an action to stay execution of a related tax
foreclosure proceeding. We have received a favorable ruling in connection with a
disputed August 1990 assessment but the government has appealed that ruling. We
also are awaiting a ruling from the Taxpayer's Council in connection with an
October 1990 assessment. If our defenses are ultimately unsuccessful, we believe
that the Brazilian government-controlled oil company, Petrobras, has a
contractual obligation to reimburse us for municipal tax payments required to be
paid by them. We do not expect the liability, if any, resulting from these
assessments to have a material adverse effect on our current consolidated
financial position, results of operations and 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
Gold (Control) Appellate Tribunal ("CEGAT") together with an application to have
the confiscation of the rig stayed pending the outcome of the appeal. In March
2000, the CEGAT ruled on the stay application, directing that the confiscation
be stayed pending the appeal. The CEGAT 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
CEGAT 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 CEGAT did not grant us the benefit of a
customs duty exemption due to the absence of required documentation, CEGAT left
it open for our subsidiary to seek such documentation from the Ministry of
Petroleum. Following the CEGAT 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 CEGAT
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 CEGAT, and both appeals were admitted. The Supreme Court has recently
dismissed the Customs Department appeal and affirmed the CEGAT order but the
Customs Department has not agreed with our interpretation of that order. 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 current consolidated financial position, results of operations and
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 current
consolidated financial position, results of operations and 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 current consolidated financial
position, results of operations and cash flows.
One of
our subsidiaries is involved in an action with respect to customs penalties
relating to the semisubmersible drilling rig Sedco 710. 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 and sought a penalty and assessment against the Schlumberger entity. 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 $61 million. We believe that the amount of the assessment, even if
it were appropriate, should only be approximately $6 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 current consolidated financial position, results of
operations and 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 lawsuits to have a
material adverse effect on our current consolidated financial position, results
of operations and 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.
ITEM 4. 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 2004.
| |
|
Age
as of |
|
Officer |
Office |
March 1,
2005 |
|
Robert
L. Long |
President
and Chief Executive Officer |
59 |
|
Jean
P. Cahuzac |
Executive
Vice President and Chief Operating Officer |
51 |
|
Eric
B. Brown |
Senior
Vice President, General Counsel and Corporate Secretary |
53 |
|
Gregory
L. Cauthen |
Senior
Vice President and Chief Financial Officer |
47 |
|
Steven
L. Newman |
Senior
Vice President, Human Resources, Information Process Solutions and
Treasury |
40 |
|
David
A. Tonnel |
Vice
President and Controller |
35 |
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.
PART
II
|
|
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 |
| |
|
|
|
|
|
2003 |
First
Quarter |
$24.36 |
|
$19.87 |
| |
Second
Quarter |
25.90 |
|
18.40 |
| |
Third
Quarter |
22.43 |
|
18.50 |
| |
Fourth
Quarter |
24.85 |
|
18.49 |
| |
|
|
|
|
|
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 |
On
February 28, 2005, the last reported sales price of our ordinary shares on the
NYSE Composite Tape was $48.48 per share. On such date, there were 16,312
holders of record of our ordinary shares and 324,073,235 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. As we approach our targeted debt levels, we
will begin to explore alternative uses for our excess cash, which could include
quarterly dividends or an extraordinary dividend, among other
possibilities.
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, 2005, 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.
|
|
| |
|
|
|
|
|
|
|
|
|
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) |
|
October 2004 |
|
— |
|
— |
|
N/A |
|
N/A |
|
November 2004 |
|
— |
|
— |
|
N/A |
|
N/A |
|
December 2004 |
|
45 |
|
$42.51 |
|
N/A |
|
N/A |
|
Total |
|
45 |
|
$42.51 |
|
N/A |
|
N/A |
_________________
|
(1) |
The
issuer purchase during the period covered by this report represents 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
connection with the vesting of restricted share awards under our Long-Term
Incentive Plan, we generally withhold shares to satisfy withholding taxes
upon vesting. |
ITEM 6. Selected Financial
Data
The
selected financial data as of December 31, 2004 and 2003 and for each of the
three years in the period ended December 31, 2004 has been derived from the
audited consolidated financial statements included elsewhere herein. The
selected financial data as of December 31, 2002, 2001 and 2000, and for the
years ended December 31, 2001 and 2000 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’s results of operations and financial condition in our
consolidated financial statements through December 16, 2004. Immediately
following the closing of the December TODCO Offering and in connection with the
conversion of our remaining shares of TODCO’s class B common stock to TODCO’s
class A common stock, our ownership and voting interest declined to
approximately 22 percent. We deconsolidated TODCO effective December 17, 2004
and subsequently accounted for our investment in TODCO under the equity method
of accounting.
| |
|
Years
ended December 31, |
|
| |
|
2004
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
| |
|
(In
millions, except per share data) |
|
| |
|
|
|
Statement
of Operations |
|
|
|
|
|
|
|
|
|
|
|
|
Operating
revenues |
|
$ |
2,614 |
|
$ |
2,434 |
|
$ |
2,674 |
|
$ |
2,820 |
|
$ |
1,230 |
|
|
Operating
income (loss) |
|
|
328 |
|
|
240 |
|
|
(2,310 |
) |
|
550 |
|
|
133 |
|
|
Income
(loss) before cumulative effect of changes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in
accounting principles |
|
|
152 |
|
|
18 |
|
|
(2,368 |
) |
|
253 |
|
|
109 |
|
|
Income
(loss) before cumulative effect of changes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
in
accounting principles per share |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(7.42 |
) |
$ |
0.82 |
|
$ |
0.52 |
|
|
Diluted |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(7.42 |
) |
$ |
0.80 |
|
$ |
0.51 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
Sheet Data (at end of period) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
assets |
|
$ |
10,758 |
|
$ |
11,663 |
|
$ |
12,665 |
|
$ |
17,048 |
|
$ |
6,359 |
|
|
Total
debt |
|
|
2,481 |
|
|
3,658 |
|
|
4,678 |
|
|
5,024 |
|
|
1,453 |
|
|
Total
equity |
|
|
7,393 |
|
|
7,193 |
|
|
7,141 |
|
|
10,910 |
|
|
4,004 |
|
|
Dividends
per share |
|
$ |
− |
|
$ |
− |
|
$ |
0.06 |
|
$ |
0.12 |
|
$ |
0.12 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other
Financial Data |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash
provided by operating activities |
|
$ |
604 |
|
$ |
525 |
|
$ |
939 |
|
$ |
560 |
|
$ |
196 |
|
|
Cash
provided by (used in) investing activities |
|
|
549 |
|
|
(445 |
) |
|
(45 |
) |
|
(26 |
) |
|
(493 |
) |
|
Cash
provided by (used in) financing activities |
|
|
(1,176 |
) |
|
(820 |
) |
|
(533 |
) |
|
285 |
|
|
166 |
|
|
Capital
expenditures |
|
|
127 |
|
|
494 |
|
|
141 |
|
|
506 |
|
|
575 |
|
|
Operating
margin |
|
|
13 |
% |
|
10 |
% |
|
N/M |
|
|
20 |
% |
|
11 |
% |
_________________________
“N/M”
means not meaningful due to loss on impairments of long-lived
assets.
ITEM 7. 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 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 February 28, 2005, we owned, had partial ownership
interests in or operated 93 mobile offshore and barge drilling units. As of this
date, our fleet included 32 High-Specification semisubmersibles and drillships
(“floaters”), 24 Other Floaters, 26 Jackup Rigs and 11 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, |
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
| |
|
(In
millions, except dayrates and percentages) |
|
|
Average
dayrate (a) |
|
$ |
71,300 |
|
$ |
67,200 |
|
$ |
4,100 |
|
|
Utilization (b) |
|
|
58 |
% |
|
57 |
% |
|
N/A |
|
|
Statement
of Operations (c) |
|
|
|
|
|
|
|
|
|
|
|
Operating
revenue |
|
$ |
2,613.9 |
|
$ |
2,434.3 |
|
$ |
179.6 |
|
|
Operating
and maintenance expense |
|
|
1,726.3 |
|
|
1,610.4 |
|
|
115.9 |
|
|
Operating
income |
|
|
327.9 |
|
|
239.7 |
|
|
88.2 |
|
|
Net
income |
|
|
152.2 |
|
|
19.2 |
|
|
133.0 |
|
|
Balance
Sheet Data (at end of period) (c) |
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
|
451.3 |
|
|
474.0 |
|
|
(22.7 |
) |
|
Total
Assets |
|
|
10,758.3 |
|
|
11,662.6 |
|
|
(904.3 |
) |
|
Total
Debt |
|
|
2,481.5 |
|
|
3,658.1 |
|
|
(1,176.6 |
) |
______________________
“N/A”
means not applicable.
| (a) |
Average
dayrate 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. See “―Significant
Events.” |
We begin
2005 with an improving outlook for our fleet, especially among our 13
Fifth-Generation Deepwater Floaters, where capacity constraints are visible for
the next 12 to 24 months. As a result, the prospect for improving utilization
and dayrates among our fleet of drillships, semisubmersibles and jackups is
encouraging. We expect our industry to experience higher costs in 2005 relative
to levels seen in the recent past, due in part to higher personnel costs
required to support the increased level of offshore drilling activity, although
we anticipate revenue increases to outpace these increased costs.
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 (see “—Historical 2003
compared to 2002—Significant Events”). 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
TODCO initial public offering (“TODCO IPO”), a TODCO offering in September 2004
(the “September TODCO Offering”) and a TODCO offering in December 2004 (the
“December TODCO Offering" and, together with the TODCO IPO and the September
TODCO Offering, the “TODCO Offerings”). These gains 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 TODCO Offerings and 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. 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. As a result of the deconsolidation of TODCO (see
“―Significant Events”), we now operate in one business segment, the Transocean
Drilling segment. We provide services with different types of drilling equipment
in several geographic regions. The location of our rigs and the allocation of
resources to build or upgrade rigs is 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 last construction cycle (approximately 1996 - 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 this segment’s 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
Transocean
Drilling Segment
Operational
Incidents—In May 2003, we announced that a drilling riser had separated on
our deepwater drillship Discoverer Enterprise and that the rig had
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. See “—Historical 2004 Compared to 2003.”
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. See “—Historical 2004
Compared to 2003.”
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. See “—Historical 2004
Compared to 2003.”
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 expect to recognize 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 of
$21.7 million.
TODCO
Segment
Delta
Towing—As a result of the adoption of the Financial Accounting Standards
Board’s (“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, operating revenue
and operating and maintenance expense increased during the twelve months ended
December 31, 2004 by $29.3 million and $24.5 million, respectively.
TODCO
Offerings and Deconsolidation
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, 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 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
businesses unrelated to TODCO’s 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, taking into account prudent and feasible tax planning
strategies as required by the FASB’s Statement of Financial Accounting Standards
(“SFAS”) 109, Accounting for Income Taxes. 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 TODCO 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,
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 this offering.
In
December 2004, we completed the December TODCO 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,
which had no tax effect, 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.
As of
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. The deconsolidation was reflected in our December 31, 2004
consolidated balance sheet as a reduction to all assets, liabilities and
minority interest with the exception of an increase to investments in and
advances to unconsolidated subsidiaries. The following table reflects the
increase (decrease) in each line item of our balance sheet at December 17, 2004
that resulted from the deconsolidation of TODCO (in millions):
|
Assets |
|
|
|
|
|
Liabilities
and Equity |
|
|
|
|
|
Cash
and cash equivalents (a) |
|
$ |
(68.6 |
) |
|
Accounts
payable |
|
$ |
(20.3 |
) |
|
Accounts
receivable, trade |
|
|
(67.3 |
) |
|
Accrued
income taxes |
|
|
(14.9 |
) |
|
Materials
and supplies, net |
|
|
(4.1 |
) |
|
Debt
due within one year |
|
|
(8.2 |
) |
|
Deferred
incomes taxes, net |
|
|
(5.4 |
) |
|
Other
current liabilities |
|
|
(38.0 |
) |
|
Other
current assets |
|
|
(3.0 |
) |
|
Total
current liabilities |
|
|
(81.4 |
) |
|
Total
current assets |
|
|
(148.4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term
debt |
|
|
(15.2 |
) |
|
Property
and equipment |
|
|
(921.0 |
) |
|
Deferred
income taxes, net |
|
|
(164.6 |
) |
|
Less
accumulated depreciation |
|
|
(350.2 |
) |
|
Other
long-term liabilities |
|
|
4.4 |
|
|
Property
and equipment, net |
|
|
(570.8 |
) |
|
Total
long-term liabilities |
|
|
(175.4 |
) |
|
Investment
in and advances to unconsolidated subsidiaries |
|
|
105.0 |
|
|
|
|
|
|
|
|
Other
assets |
|
|
(23.8 |
) |
|
Minority
interest |
|
|
(381.2 |
) |
|
Total
assets |
|
$ |
(638.0 |
) |
|
Total
liabilities and minority interest |
|
$ |
(638.0 |
) |
__________________________
(a) Included
in net cash flows provided by (used in) investing activities in our consolidated
statements of cash flows.
Our
current intention is to dispose of our remaining interest in TODCO, which could
be achieved through a number of possible transactions including additional
public offerings, open market sales, sales to one or more third parties, a
spin-off to our shareholders, split-off offerings to our shareholders that would
allow for the opportunity to exchange our ordinary shares for shares of TODCO
class A common stock or a combination of these transactions.
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, which had no tax effect, 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
based on when TODCO files its annual tax returns.
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 had no tax effect, and
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 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 TODCO 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, which
had no tax effect. 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.
In
February 2005, we called 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 expect to redeem these notes at 109.92 percent of
face value or $272.4 million, plus accrued and unpaid interest. The redemption
is expected to be completed by March 21, 2005. We expect to recognize a loss on
the redemption of approximately $10.8 million, which reflects 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 plan to fund the redemption with existing cash on hand.
Outlook
Drilling
Market—Oil prices have remained strong, and, although a decline from
current levels could occur, we expect prices to remain relatively high in
historical terms. 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 improve, with new and
expected contracts resulting in declining rig availability among this fleet
during 2005. We are increasingly confident that most of the available time in
2005 will be contracted, although some intermittent idle time remains a
possibility, especially for some of the Other Deepwater Floaters in this fleet.
We have signed a number of new contracts or extensions for our
High-Specification Floaters that reflect the increased activity in this sector.
Recent awards during the last part of 2004 and early 2005 include a 12 month
program for the Transocean Rather in the North Sea, with the rig
relocating from West Africa, a 240 day program for the Transocean
Marianas in the Gulf of Mexico as well as a number of short-term contracts
on the Deepwater Millennium, Discoverer 534, Deepwater
Discovery and Sedco Energy. In addition, we entered into contracts
for the Discoverer Spirit and Deepwater Nautilus in February
2005 for 18 month and 12 month programs, respectively, to begin at the
conclusion of their current contracts in approximately September 2005. Rates
have been generally trending higher, especially for the highest specification
rigs. We continue to believe that, over the long-term, deepwater exploration and
development drilling opportunities in the Gulf of Mexico, West Africa, India and
other market sectors represent a significant source of future deepwater rig
demand, although the risk of project delays remains, especially in West Africa.
We continue to see a strong customer preference for using fifth-generation
equipment in these deepwater areas, which may lead to a near term shortage of
these highest specification rigs.
The
outlook for activity for the non-U.S. jackup market sector is expected to remain
strong, particularly in Asia and the Middle East. We expect to remain at or near
full utilization for our Jackups in the near term, and at the present time we do
not anticipate any inter-regional relocations of these units.
The
outlook for our Other Floaters that operate in the mid-water sector has improved
substantially from the global oversupply position that existed throughout most
of 2004. We expect overall North Sea industry activity to remain well above 2004
levels, with resulting improvements in utilization and dayrates in 2005. Demand
in the Gulf of Mexico market sector also rose in late 2004, which has caused us
to reactivate or commence active marketing efforts for some of our cold-stacked
units in this fleet.
The
Transocean Legend is being relocated to Singapore from Brazil for
shipyard work in advance of a long-term program. Likewise, we plan to relocate
the Sedco Express to Angola from Brazil upon completion of its shipyard
work to commence a long-term drilling program. In addition to these
mobilizations and contract preparation shipyard periods, we expect downtime
during the first and second quarters of 2005 to result from planned shipyard
projects for the Sedco 706, Transocean Rather, Searex 10, Trident 15,
Trident 16 and Deepwater Navigator. The Jim Cunningham
returned to work in February 2005 after undergoing repairs resulting from a well
control incident in 2004. These rig mobilizations and shipyard projects are
expected to have a negative impact on revenues and related
earnings.
The
offshore contract drilling market remains highly competitive and cyclical, and
it has been historically difficult to forecast future market conditions. Risks
include declines in oil and/or gas prices that 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 Russia, other former
Soviet Union states and the Middle East.
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.
As of
February 28, 2005, approximately 64 percent of our fleet days were committed for
the remainder of 2005 and approximately 27 percent for the year
2006.
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, including treaties that the U.S.
has with other nations. A material change in these tax laws, treaties or
regulations, including those in and involving the U.S., could result in a higher
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 Act contains provisions that apply to certain companies that
undertook a transaction commonly known as an inversion after a specified date.
Because our reorganization as a Cayman Islands company in May 1999 occurred
prior to the effective dates specified in the Act, we do not believe there
should be any adverse impact to us from the inversion provisions of the Act.
Additionally, the tax treaty between the U.S. and Barbados was recently amended.
We do not expect the amendment to have a material adverse effect on our
financial position, results of operations or cash flows.
The Act
also creates a temporary incentive for U.S. corporations to repatriate
accumulated income earned abroad by providing, in some cases, an 85 percent
dividends received deduction for dividends paid by certain non-U.S. subsidiaries
of the U.S. corporation (“controlled foreign corporations”) to the U.S.
corporation. The deduction is subject to a number of limitations and uncertainty
currently remains as to how to interpret numerous provisions of the Act.
Further, several requirements must be met in order to qualify for the deduction.
While we are still in the process of analyzing whether any of our U.S.
subsidiaries could qualify for the deduction, it is reasonably possible that
under the repatriation provisions of the Act certain of our non-U.S.
subsidiaries may repatriate to our U.S. subsidiaries some amount of earnings up
to an estimated maximum amount of $150 million. As we have provided deferred
U.S. taxes on the unremitted earnings of these controlled foreign corporations,
this deduction, should we qualify, could reduce our tax expense in 2005 by an
estimated maximum amount of $40 million. The ultimate amounts could be much less
or even zero.
The Act
further provides for a tax deduction for qualified production activities. Under
the guidance of FASB Staff Position No. 109-1, Application of FASB Statement
No. 109, “Accounting for Income Taxes,” to the Tax Deduction on Qualified
Production Activities Provided by the American Jobs Creation Act of 2004,
the deduction will be treated as a “special deduction” as described in SFAS 109
and not as a reduction in the tax rate. As such, the special deduction has no
effect on deferred tax assets and liabilities existing on the date of enactment.
Rather, the impact of this deduction will be reported in the period in which the
deduction is claimed on our tax return. We are still reviewing whether any of
our operations would qualify for this deduction. Further, because of losses
carried forward by the applicable subsidiaries, this deduction is not expected
to have any impact on our tax provision in 2005.
Our
income tax returns are subject to review and examination in the various
jurisdictions in which we operate. In October 2004, we received from the U.S.
Internal Revenue Service (“IRS”) examination reports setting forth proposed
changes to the U.S. federal income tax reported for the period 1999-2000. The
maximum amount of additional tax based on the proposed changes would be
approximately $195 million, exclusive of interest. While we have agreed to
certain non-material adjustments, we believe our returns are materially correct
as filed and intend to defend ourselves vigorously. The IRS has also notified us
of its intent to audit our 2002 and 2003 tax years. No examination report has
been received at this time.
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. Based on these
inquiries, we believe the Norwegian authorities are contemplating a tax
assessment on the dividend of approximately $106 million, 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 current consolidated financial
position, results of operations and cash flows.
In
addition, other tax authorities have examined the amounts of income and expense
subject to tax in their jurisdiction for prior periods. We are currently
contesting various non-U.S. assessments that have been asserted and would expect
to contest any future U.S. or non-U.S. assessments. We do not expect the
liability, if any, resulting from existing or future assessments to have a
material adverse effect on our current consolidated financial position, results
of operations and cash flows. We cannot predict with certainty the outcome or
effect of any of the tax assessments described herein. There can be no
assurance that our beliefs or expectations as to the outcome or effect of any
tax assessment we are contesting will prove correct and the eventual outcome of
these matters could materially differ from management's current
estimates.
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, taking into account prudent and feasible tax planning
strategies as required by the FASB’s Statement of Financial Accounting Standards
(“SFAS”) 109, Accounting for Income Taxes. 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. The ultimate allocation of tax
benefits between TODCO and our other U.S. subsidiaries will occur in 2005 upon
the filing of our 2004 U.S. consolidated federal income tax return. This
final allocation of tax benefits could impact our effective tax rate for
2005.
Performance
and Other Key Indicators
Fleet
Utilization and Dayrates—The following table shows our average dayrates and
utilization for the quarterly periods ended on or prior to December 31, 2004. We
consolidated TODCO’s results of operations and financial condition in our
consolidated financial statements through December 16, 2004 (see “―Significant
Events”). Average dayrate 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, 2004 |
|
September
30, 2004 |
|
December
31, 2003 |
|
Average
Dayrates |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
Transocean
Drilling Segment: |
|
|
|
|
|
|
|
High-Specification
Floaters |
|
|
|
|
|
|
|
|
Fifth-Generation
Deepwater Floaters |
|
$ |
180,100 |
|
$ |
193,400 |
|
$ |
186,500 |
|
|
Other
Deepwater Floaters |
|
$ |
119,400 |
|
$ |
103,900 |
|
$ |
101,400 |
|
|
Other
High-Specification Floaters |
|
$ |
135,700 |
|
$ |
111,200 |
|
$ |
117,900 |
|
|
Total
High-Specification Floaters |
|
$ |
149,000 |
|
$ |
142,200 |
|
$ |
141,800 |
|
|
Other
Floaters |
|
$ |
64,000 |
|
$ |
65,400 |
|
$ |
60,600 |
|
|
Jackups |
|
$ |
55,800 |
|
$ |
52,500 |
|
$ |
53,700 |
|
|
Other
Rigs |
|
$ |
48,100 |
|
$ |
44,700 |
|
$ |
45,200 |
|
|
Segment
Total |
|
$ |
93,900 |
|
$ |
91,100 |
|
$ |
87,900 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
TODCO
Segment (a) |
|
$ |
28,600 |
|
$ |
27,300 |
|
$ |
21,500 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Total
Drilling Fleet |
|
$ |
74,200 |
|
$ |
69,800 |
|
$ |
67,400 |
|
| |
|
|
|
Utilization
|
|
|
| |
|
|
|
Transocean
Drilling Segment: |
|
|
|
High-Specification
Floaters |
|
|
|
Fifth-Generation
Deepwater Floaters |
|
|
89 |
% |
|
83 |
% |
|
91 |
% |
|
Other
Deepwater Floaters |
|
|
69 |
% |
|
78 |
% |
|
69 |
% |
|
Other
High-Specification Floaters |
|
|
92 |
% |
|
84 |
% |
|
74 |
% |
|
Total
High-Specification Floaters |
|
|
80 |
% |
|
81 |
% |
|
78 |
% |
|
Other
Floaters |
|
|
50 |
% |
|
45 |
% |
|
47 |
% |
|
Jackups |
|
|
81 |
% |
|
81 |
% |
|
81 |
% |
|
Other
Rigs |
|
|
54 |
% |
|
44 |
% |
|
53 |
% |
|
Segment
Total |
|
|
69 |
% |
|
67 |
% |
|
68 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
TODCO
Segment (a) |
|
|
47 |
% |
|
45 |
% |
|
40 |
% |
| |
|
|
|
|
|
|
|
|
|
|
|
Total
Drilling Fleet |
|
|
61 |
% |
|
58 |
% |
|
56 |
% |
_________________
(a) TODCO
was deconsolidated effective December 17, 2004. Statistics for the TODCO segment
are through December 16, 2004 for the three months ended December 31,
2004.
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—Beginning
with the first quarter of 2004, we began classifying our revenues into two
categories: (1) contract drilling revenues and (2) other revenues, as other
revenue became a more significant component of our total revenues. Our other
revenue represents client reimbursable revenue, integrated services revenue and
other miscellaneous revenues. 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.
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. The
principal elements of these costs are direct and indirect labor and benefits,
repair and maintenance, 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 and insurance costs represent the most significant components of our
operating and maintenance costs. Insurance costs include insurance premiums,
personal injury losses less than the deductible and hull and machinery losses
that fall below the deductible.
We do not
expect operating and maintenance expenses 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. We
maintain a per occurrence insurance deductible of $10 million on our hull and
machinery and our protection and indemnity policies. We also have an additional
aggregate deductible of $23 million that is applied to each hull and machinery
occurrence until it has been exhausted over one or more occurrences. After this
$23 million aggregate deductible is fully exhausted, the hull and machinery
deductible reverts to $10 million per occurrence.
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,
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 Policies.”
Financial
Condition
December
31, 2004 compared to December 31, 2003
| |
|
December
31, |
|
|
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except % change) |
|
|
|
|
Total
Assets |
|
|
|
|
|
|
|
|
|
|
Transocean
Drilling |
|
$ |
10,758.3 |
|
$ |
10,874.0 |
|
$ |
(115.7 |
) |
|
(1 |
)% |
|
TODCO |
|
|
− |
|
|
788.6 |
|
|
(788.6 |
) |
|
(100 |
)% |
| |
|
$ |
10,758.3 |
|
$ |
11,662.6 |
|
$ |
(904.3 |
) |
|
(8 |
)% |
The
decrease in Transocean Drilling segment assets was primarily due to asset
depreciation ($432.6 million) and decreases in cash and cash equivalents ($3
million), partially offset by increases to investments in and advances to
unconsolidated subsidiaries ($104 million), property and equipment, net of
retirements ($89 million) (see
“―Capital Expenditures”),
goodwill ($21 million), accounts receivable ($19 million) and other long-term
assets ($61 million). The decrease in cash and cash equivalents resulted
primarily from repayments of debt ($1,069 million), partially offset by proceeds
received from the TODCO Offerings ($684 million), net proceeds received from the
sale of a semisubmersible rig ($28 million) and cash from operations during the
year ended December 31, 2004. The increase in investments in and advances to
unconsolidated subsidiaries primarily relates to our 22 percent interest in
TODCO. The increase in goodwill primarily related to changes in our estimates
related to certain pre-acquisition income tax-related contingencies, and the
increase in other long-term assets was primarily due to incremental deferred
income tax expense related to intercompany rig sales. The decrease in TODCO
segment assets resulted from the deconsolidation of TODCO (see
“―Significant Events”).
Liquidity
and Capital Resources
Sources
and Uses of Cash
| |
|
Years
ended December 31, |
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
| |
|
|
|
(In
millions) |
|
|
|
Net
Cash Provided by Operating Activities |
|
|
|
|
|
|
|
|
Net
income |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
133.0 |
|
|
Depreciation |
|
|
524.6 |
|
|
508.2 |
|
|
16.4 |
|
|
Other
non-cash items |
|
|
(45.6 |
) |
|
(63.6 |
) |
|
18.0 |
|
|
Working
capital |
|
|
(27.1 |
) |
|
61.6 |
|
|
(88.7 |
) |
| |
|
$ |
604.1 |
|
$ |
525.4 |
|
$ |
78.7 |
|
Net cash
provided by operating activities increased $78.7 million due to an increase in
cash generated from net income adjusted for non-cash activity of $167.4 million,
partially offset by a decrease in cash related to working capital items of $88.7
million during the year ended December 31, 2004 as compared to the corresponding
prior year period.
| |
|
Years
ended December 31, |
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
| |
|
|
|
(In
millions) |
|
|
|
Net
Cash Provided by (Used in) Investing Activities |
|
|
|
|
|
|
|
|
Capital
expenditures |
|
$ |
(127.0 |
) |
$ |
(493.8 |
) |
$ |
366.8 |
|
|
Proceeds
from disposal of assets, net |
|
|
50.4 |
|
|
8.4 |
|
|
42.0 |
|
|
DDII
LLC’s cash acquired, net of cash paid |
|
|
− |
|
|
18.1 |
|
|
(18.1 |
) |
|
DD
LLC’s cash acquired |
|
|
− |
|
|
18.6 |
|
|
(18.6 |
) |
|
Proceeds
from TODCO Offerings |
|
|
683.6 |
|
|
- |
|
|
683.6 |
|
|
Reduction
of cash from the deconsolidation of TODCO |
|
|
(68.6 |
) |
|
- |
|
|
(68.6 |
) |
|
Joint
ventures and other investments, net |
|
|
10.4 |
|
|
3.3 |
|
|
7.1 |
|
| |
|
$ |
548.8 |
|
$ |
(445.4 |
) |
$ |
994.2 |
|
Net cash
provided by investing activities increased $994.2 million over the previous
year. The increase is primarily the result of proceeds from the TODCO Offerings
of $683.6 million combined with an increase in proceeds from asset sales as
compared to the prior year and a reduction in current year capital expenditures
primarily due to the 2003 acquisition of the Deepwater
Frontier and
Deepwater
Pathfinder totaling
$382.8 million. Partially offsetting these increases was the decrease in cash of
$68.6 million resulting from the deconsolidation of TODCO compared to $36.7
million of cash acquired upon acquisition of ConocoPhillips’ interests in DD LLC
and DDII LLC during 2003.
| |
|
Years
ended December 31, |
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
| |
|
(In
millions) |
|
Net
Cash Used in Financing Activities |
|
|
|
|
|
|
|
|
Borrowings
(repayments) under revolving credit agreement |
|
$ |
(250.0 |
) |
$ |
250.0 |
|
$ |
(500.0 |
) |
|
Repayments
on other debt instruments |
|
|
(957.0 |
) |
|
(1,252.7 |
) |
|
295.7 |
|
|
Cash
received from termination of interest rate swaps |
|
|
− |
|
|
173.5 |
|
|
(173.5 |
) |
|
Other,
net |
|
|
31.4 |
|
|
9.0 |
|
|
22.4 |
|
| |
|
$ |
(1,175.6 |
) |
$ |
(820.2 |
) |
$ |
(355.4 |
) |
Net cash
used in financing activities increased in 2004 compared to 2003 primarily due to
higher 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
approximately 71.3 percent of our 8% Debentures by means of a tender offer. We
had net borrowings under our revolving credit facility in 2003 that were repaid
in 2004. In addition, the termination of our interest rate swaps was a source of
cash in 2003 with no comparable activity during 2004 (see
“—Derivative Instruments”).
Capital
Expenditures
Capital
expenditures totaled $127.0 million during the year ended December 31, 2004 of
which $118.2 million and $8.8 million related to the Transocean Drilling and
TODCO segments, respectively.
During
2005, we expect to spend approximately $140 million on our existing fleet,
corporate infrastructure and major upgrades. These amounts are dependent upon
the actual level of operational and contracting activity. In addition, we expect
to spend another $50 million towards those upgrades required and funded by our
drilling contracts, and another $35.7 million for the purchase of the
semisubmersible rig M.G.
Hulme, Jr. (see
“—Acquisitions and Dispositions”). 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
of Liquidity”) and may utilize other commercial bank or capital market
financings.
Acquisitions
and Dispositions
From time
to time, we review possible acquisitions of businesses and drilling units and
may in the future make significant capital commitments for such purposes. Any
such acquisition 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 would likely fund the cash portion of any such acquisition
through cash balances on hand, the incurrence of additional debt, sales of
assets, issuance of ordinary shares or other securities or a combination
thereof. In addition, from time to time, we review possible dispositions of
drilling units.
Acquisition - In
November 2004, we gave notice to Deep Sea Investors, L.L.C. (“Deep Sea
Investors”) of our intent to purchase the semisubmersible M.G.
Hulme, Jr. for
approximately $35.7 million. See “―Off-Balance
Sheet Arrangement.”
Dispositions—During
2004, we completed the TODCO Offerings. See “—Significant Events.”
In March
2004, we entered into agreements to sell two semisubmersible rigs, the
Sedco
600 and
Sedco
602, for net
proceeds of $52.7 million in connection with our efforts to dispose of certain
non-strategic assets in our Transocean Drilling segment. 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, which had no
tax effect. In January 2005, we completed the sale of the Sedco
600 for net
proceeds of $24.9 million, and we expect to recognize an after-tax gain of $18.8
million in the first quarter of 2005.
During
the year ended December 31, 2004, we settled insurance claims and sold marine
support vessels and certain other assets for net proceeds of $22.4 million and
recorded net gains of $4.2 million ($3.3 million, net of tax) in our Transocean
Drilling segment and $6.0 million, which had no tax effect, in our TODCO
segment.
Sources
of Liquidity
Our
primary sources of liquidity in 2004 were our cash flows from operations,
proceeds from the TODCO Offerings, proceeds from asset sales, borrowings under
our revolving credit agreement and existing cash balances. Our primary uses of
cash were debt repayments and capital expenditures. At December 31, 2004, we had
$451.3 million in cash and cash equivalents.
We expect
to use existing cash balances, internally generated cash flows and proceeds from
asset sales, including potential sales of our interest in TODCO, 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, proceeds from asset sales, including
potential sales of our interest in TODCO, and committed bank facility
availability exceed our expected liquidity needs, we may use a portion of such
cash to reduce debt prior to scheduled maturities through repurchases,
redemptions or tender offers, or make repayments on any outstanding bank
borrowings. As we approach our targeted debt levels of $1 to $2 billion, we will
begin to explore alternative uses of our excess cash. Such possible uses could
include an extraordinary dividend, share repurchases, resumption of periodic
dividends and/or opportunistic asset acquisitions.
At
December 31, 2004 and 2003, our total debt was $2,481.5 million and $3,658.1
million, respectively. Net debt, a non-GAAP financial measure defined as total
debt less cash and cash equivalents, at such dates was $2,030.2 million and
$3,184.1 million, respectively. During the year ended December 31, 2004, we
reduced net debt by $1,153.9 million. The reconciliation of total debt to net
debt at carrying value is as follows (in millions):
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
|
Total
Debt |
|
$ |
2,481.5 |
|
$ |
3,658.1 |
|
|
Less:
Cash and cash equivalents |
|
|
(451.3 |
) |
|
(474.0 |
) |
|
Net
Debt |
|
$ |
2,030.2 |
|
$ |
3,184.1 |
|
We
believe net debt provides useful information regarding the level of our
indebtedness by reflecting the amount of indebtedness assuming cash and
investments are used to repay debt. Net debt declined each year since 2001
because cash flows, primarily from operations and asset sales, have exceeded
capital expenditures.
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.
We have
access to a bank line of credit under an $800 million five-year revolving credit
agreement expiring in December 2008. As of March 1, 2005, $800.0 million
remained available under this credit line. Because our current cash balances,
expected cash flow and this revolving credit agreement provide us with adequate
liquidity, we terminated our commercial paper program during the first quarter
of 2004.
The bank
credit line requires compliance with various covenants and provisions customary
for agreements of this nature, including an earnings before interest, taxes,
depreciation and amortization (“EBITDA”) to interest coverage ratio and debt to
tangible capital ratio, both as defined by the credit agreement, of not less
than three to one and not greater than 50 percent, respectively. Other
provisions of the credit agreement include limitations on creating liens,
incurring 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, 2005, $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 |
|
2005 |
|
2006-2007 |
|
2008-2009 |
|
Thereafter |
|
Contractual
Obligations |
|
|
|
|
Debt |
|
$ |
2,390.2 |
|
$ |
19.6 |
|
$ |
500.0 |
|
$ |
266.8 |
|
$ |
1,603.8 |
|
|
Operating
Leases |
|
|
68.8 |
|
|
26.6 |
|
|
19.9 |
|
|
14.8 |
|
|
7.5 |
|
|
Purchase
Obligations |
|
|
35.7 |
|
|
35.7 |
|
|
- |
|
|
- |
|
|
- |
|
|
Defined
Benefit Pension Plans |
|
|
2.4 |
|
|
2.4 |
|
|
- |
|
|
- |
|
|
- |
|
|
Total
Obligations |
|
$ |
2,497.1 |
|
$ |
84.3 |
|
$ |
519.9 |
|
$ |
281.6 |
|
$ |
1,611.3 |
|
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 have a
required obligation to make a contribution in 2005 to our funded Norway defined
benefit pension plans. See “—Retirement Plans and Other Postemployment Benefits”
for a discussion of expected contributions for pension funding requirements of
expected benefit payments for our unfunded defined benefit pension
plans.
At
December 31, 2004, 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 |
|
2005 |
|
2006-2007 |
|
2008-2009 |
|
Thereafter |
|
| |
|
(In
millions) |
|
Other
Commercial Commitments |
|
|
|
|
|
|
|
|
|
|
|
|
Standby
Letters of Credit |
|
$ |
182.2 |
|
$ |
151.3 |
|
$ |
24.8 |
|
$ |
6.1 |
|
$ |
- |
|
|
Surety
Bonds |
|
|
7.6 |
|
|
7.6 |
|
|
- |
|
|
- |
|
|
- |
|
|
Surety
Bonds-TODCO |
|
|
11.9 |
|
|
11.9 |
|
|
- |
|
|
- |
|
|
- |
|
|
Total |
|
$ |
201.7 |
|
$ |
170.8 |
|
$ |
24.8 |
|
$ |
6.1 |
|
$ |
- |
|
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. Until April 2005, we also
guarantee $11.9 million of TODCO’s surety bonds, which TODCO has collateralized.
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, 2004,
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
January 2003, we terminated swaps and associated fair value hedges with respect
to our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and
9.5% Senior Notes due December 2008. In March 2003, we terminated swaps with
respect to our 6.625% Notes due April 2011. As a result of these terminations,
we received cash proceeds, net of accrued interest, of $173.5 million that had
been recognized in connection with the associated fair value hedges as a fair
value adjustment to long-term debt in our consolidated balance sheet and is
being amortized as a reduction to interest expense over the life of the
underlying debt. Such reduction amounted to $22.7 million in 2004. As a result
of the redemption of our 9.5% Senior Notes in March 2004 and 6.75% Senior Notes
in October 2004, we recognized unamortized premium of $25.5 million from the
2003 termination of the related interest rate swap as a reduction to our loss on
retirement of debt (see “—Historical 2004 compared to 2003”). Based on the
unamortized premiums remaining on the terminated interest rate swaps and taking
the announced March 2005 redemption of the 6.95% Senior Notes into account, we
expect our interest expense to be reduced by $13.3 million in 2005.
Historical
2004 compared to 2003
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.
Transocean
Drilling Segment
| |
|
Years
ended |
|
|
|
|
|
| |
|
December
31, |
|
|
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except day amounts and percentages) |
|
| |
|
|
|
|
Revenue
earning days (a) |
|
|
23,427 |
|
|
23,712 |
|
|
(285 |
) |
|
(1 |
)% |
|
Utilization
(b) |
|
|
68 |
% |
|
69 |
% |
|
N/A |
|
|
(1 |
)% |
|
Average
dayrate (c) |
|
$ |
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 |
|
|
1,445.1 |
|
|
1,367.9 |
|
|
77.2 |
|
|
6 |
% |
|
Depreciation |
|
|
432.6 |
|
|
416.0 |
|
|
16.6 |
|
|
4 |
% |
|
Impairment
loss on long-lived assets |
|
|
− |
|
|
5.2 |
|
|
(5.2 |
) |
|
N/M |
|
|
Gain
from sale of assets, net |
|
|
(25.9 |
) |
|
(4.9 |
) |
|
(21.0 |
) |
|
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
(a) Revenue
earning day is a day for which a rig earns dayrate after commencement of
operations.
(b) Utilization
is defined as the total actual number of revenue earning days as a percentage of
total number of calendar days in the period.
(c) Average
dayrate is defined as contract drilling revenue earned per revenue earning
day.
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 $25.9 million related to the sale of
the semisubmersible rig Sedco
602 and the
sale of other assets. During the year ended December 31, 2003, this segment
recognized net gains of $4.9 million related to the sale of the jackup rig
RBF
160, the
sale of the Searex
15, the
settlement of an insurance claim and the sale of other assets.
TODCO
Segment
The
results discussed below for the TODCO segment are through December 16, 2004 as a
result of the TODCO Offerings and the deconsolidation of TODCO. See
“—Significant Events.”
| |
|
Years
ended |
|
|
|
|
|
| |
|
December
31, |
|
|
|
|
|
| |
|
2004 |
|
2003 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except day amounts and percentages) |
|
| |
|
|
|
|
Revenue
earning days (a) (b) |
|
|
10,476 |
|
|
10,953 |
|
|
(477 |
) |
|
(4 |
)% |
|
Utilization
(a) (c) |
|
|
43 |
% |
|
41 |
% |
|
N/A |
|
|
5 |
% |
|
Average
dayrate (a) (d) |
|
$ |
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 |
|
|
281.2 |
|
|
242.5 |
|
|
38.7 |
|
|
16 |
% |
|
Depreciation |
|
|
92.0 |
|
|
92.2 |
|
|
(0.2 |
) |
|
N/M |
|
|
Impairment
loss on long-lived assets |
|
|
− |
|
|
11.3 |
|
|
(11.3 |
) |
|
N/M |
|
|
Gain
from sale of assets, net |
|
|
(6.0 |
) |
|
(0.9 |
) |
|
(5.1 |
) |
|
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.
(b) Revenue
earning day is a day for which a rig earns dayrate after commencement of
operations.
(c) Utilization
is defined as the total actual number of revenue earning days as a percentage of
total number of calendar days in the period.
(d) Average
dayrate is defined as contract drilling revenue earned per revenue earning
day.
This
segment’s contract drilling revenues increased by $72.5 million due to an
increase in average dayrates 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 $6.0 million primarily related to the
sale of marine support vessels by Delta Towing, as well as the sale of other
assets and the settlement of an October 2000 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 |
|
|
2.6 |
% |
|
Other
(Income) Expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of unconsolidated subsidiaries |
|
|
(9.2 |
) |
|
(5.1 |
) |
|
(4.1 |
) |
|
80.4
|
% |
|
Interest
income |
|
|
(9.3 |
) |
|
(18.8 |
) |
|
9.5 |
|
|
(50.5 |
)% |
|
Interest
expense |
|
|
171.7 |
|
|
202.0 |
|
|
(30.3 |
) |
|
(15.0 |
)% |
|
Gain
from TODCO offerings |
|
|
(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 of $8.8 million in
2003 of expenses relating to the TODCO IPO.
Equity in
earnings of unconsolidated subsidiaries 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 Offerings (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 Offerings 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.
Historical
2003 compared to 2002
Overview
The
decreases in our average dayrates and utilization were mainly attributable to
the decline in overall market conditions primarily within our Other Floaters
fleet category. The increase in our operating and maintenance expenses was
primarily due to a change in accounting for client reimbursable expenses. In
addition, our revenues, utilization and operating and maintenance expense were
negatively impacted by a riser separation incident on the drillship Discoverer
Enterprise, an
electrical fire on the Peregrine
I and a
labor strike and a restructuring of a benefit plan in Nigeria (see “—Significant
Events”). Operating and maintenance expense was also negatively impacted by a
well control incident on inland barge Rig
62 and a fire on
inland barge Rig
20. With the
overall market decline we responded rapidly to reduce costs when rigs were
idled. We also reduced costs by implementing standardized purchasing through
negotiated agreements, nationalization of our labor force where appropriate and
headcount reductions in support groups. Our 2003 financial results included the
recognition of a number of non-cash charges pertaining to asset impairments and
loss on debt retirements. Debt and cash decreased during 2003 primarily as a
result of repayments on debt instruments as we continued to maintain our focus
on debt reduction. We also increased our investment in the Fifth-Generation
fleet category by purchasing the portions of the DD LLC and DDII LLC joint
ventures that had previously been held by ConocoPhillips and paying off the
synthetic lease financing arrangements associated with the Deepwater
Pathfinder and
Deepwater
Frontier. See
“—Significant Events.”
As a
result of the implementation of Emerging Issues Task Force (“EITF”) Issue No.
99-19, Reporting
Revenue Gross as a Principal versus Net as an Agent, costs we
incur that are charged to our customers on a reimbursable basis were recognized
as operating and maintenance expense beginning in 2003. In addition, the amounts
billed to our customers associated with these reimbursable costs were being
recognized as operating revenue. The increase in operating revenues and
operating and maintenance expense resulting from this implementation was
approximately $100.5 million for the year ended December 31, 2003. This change
in the accounting treatment for client reimbursables had no effect on our
consolidated financial position, results of operations or cash flows. We
previously recorded these charges and related reimbursements on a net basis in
operating and maintenance expense. Prior period amounts were not reclassified,
as the amounts were not material.
Significant
Events
Transocean
Drilling Segment
DD
LLC and DDII LLC Joint Ventures—In May
2003, we purchased ConocoPhillips’ 40 percent interest in DDII LLC. DDII LLC was
the lessee in a synthetic lease financing facility with a special purpose entity
entered into in connection with the construction of the Deepwater
Frontier. As a
result of this purchase, we consolidated DDII LLC in our financial statements
late in the second quarter of 2003. In December 2003, DDII LLC paid $197.5
million for the purchase of the rig through the payoff of the synthetic lease
financing arrangement. In conjunction with the payoff of the synthetic lease
financing arrangements, our relationship with the special purpose entity was
terminated.
In
December 2003, we purchased ConocoPhillips’ 50 percent interest in DD LLC. DD
LLC was the lessee in a synthetic lease financing facility with a special
purpose entity entered into in connection with the construction of the
Deepwater
Pathfinder. As a
result of this purchase, we consolidated DD LLC in our financial statements late
in the fourth quarter of 2003. In December 2003, DD LLC paid $185.3 million for
the purchase of the rig through the payoff of the synthetic lease financing
arrangement. In conjunction with the payoff of the synthetic lease financing
arrangement, our relationship with the special purpose entity was terminated.
Operational
Incidents—In April
2003, our deepwater drillship Peregrine
I
temporarily suspended drilling operations as a result of an electrical fire
requiring repairs at a shipyard. The rig resumed
operations in early July 2003. Operating income was negatively impacted by
approximately $9.5 million due to the loss of dayrate and related expenses.
In April
2003, we announced that drilling operations had ceased on four of our mobile
offshore drilling units located offshore Nigeria due to a strike by local
members of the labor unions in Nigeria on the semisubmersible rigs M.G.
Hulme, Jr. and
Sedco
709 and the
jackup rigs Trident
VI and
Trident
VIII. All of
these rigs returned to operations in May and June 2003. Labor issues in Nigeria
were resolved and settled in the fourth quarter of 2003. Operating income was
negatively impacted by approximately $26.6 million due to loss of dayrate and
the restructuring of the Nigeria defined benefit plan.
In May
2003, we announced that a drilling riser had separated on our deepwater
drillship Discoverer
Enterprise and that
the rig had temporarily suspended drilling operations for our customer. The rig
resumed operations in July 2003. Operating income for the year ended December
31, 2003 was negatively impacted by approximately $46.4 million due to expenses
incurred on the Discoverer
Enterprise as well
as several other of our Fifth-Generation Deepwater Floaters related to the
drilling riser separation and a related disagreement with our customer that was
resolved in the first quarter of 2004. At the time, we were in discussions with
our insurers relating to an insurance claim for a portion of our losses stemming
from this incident.
TODCO
Segment
Operational
Incidents—In June
2003, TODCO incurred a loss as a result of a well blowout and fire aboard inland
barge Rig
62. During
the year ended December 31, 2003, TODCO incurred a $7.6 million loss relating to
this incident.
In
September 2003, TODCO recorded a loss of approximately $3.5 million on inland
barge Rig
20 as a
result of a fire.
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.
Transocean
Drilling Segment
| |
|
Years
ended |
|
|
|
|
|
| |
|
December
31, |
|
|
|
|
|
| |
|
2003 |
|
2002 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except day amounts and percentages) |
|
| |
|
|
|
|
Revenue
earning days (a) |
|
|
23,712 |
|
|
26,315 |
|
|
(2,603 |
) |
|
(10 |
)% |
|
Utilization
(b) |
|
|
69 |
% |
|
78 |
% |
|
N/A |
|
|
(12 |
)% |
|
Average
dayrate (c) |
|
$ |
89,400 |
|
$ |
93,500 |
|
$ |
(4,100 |
) |
|
(4 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
drilling revenues |
|
$ |
2,118.7 |
|
$ |
2,460.6 |
|
$ |
(341.9 |
) |
|
(14 |
)% |
|
Other
revenues |
|
|
88.0 |
|
|
25.5 |
|
|
62.5 |
|
|
N/M |
|
| |
|
|
2,206.7 |
|
|
2,486.1 |
|
|
(279.4 |
) |
|
(11 |
)% |
|
Operating
and maintenance expense |
|
|
1,367.9 |
|
|
1,291.3 |
|
|
76.6 |
|
|
6 |
% |
|
Depreciation |
|
|
416.0 |
|
|
408.4 |
|
|
7.6 |
|
|
2 |
% |
|
Impairment
loss on long-lived assets and goodwill |
|
|
5.2 |
|
|
2,528.1 |
|
|
(2,522.9 |
) |
|
N/M |
|
|
Gain
from sale of assets, net |
|
|
(4.9 |
) |
|
(2.7 |
) |
|
(2.2 |
) |
|
81 |
% |
|
Operating
income (loss) before general and administrative expense |
|
$ |
422.5 |
|
$ |
(1,739.0 |
) |
$ |
2,161.5 |
|
|
124 |
% |
_________________
“N/A”
means not applicable
“N/M”
means not meaningful
| (a) |
Revenue earning day is a day for which a rig earns
dayrate after commencement of operations. |
|
(b) |
Utilization
is defined as the total actual number of revenue earning days as a
percentage of total number of calendar days in the
period. |
|
(c) |
Average
dayrate is defined as contract drilling revenue earned per revenue earning
day. |
Due to a
general deterioration in market conditions, average dayrates and utilization
declined resulting in a decrease in this segment’s contract drilling revenues of
approximately $337.0 million, excluding the impact of the items discussed
separately below. Contract drilling revenues were also adversely impacted by
approximately $35.1 million due to the labor strike in Nigeria, the riser
separation incident on the Discoverer
Enterprise and the
electrical fire on the Peregrine
I.
Additional decreases of $14.1 million resulted from rigs sold, returned to owner
and transferred from this segment to the TODCO segment. These decreases were
partially offset by increases in contract drilling revenue of $46.6 million from
a rig transferred into this segment from the TODCO segment during the second
quarter of 2002 and from the Deepwater
Frontier as a
result of the
consolidation of DDII LLC late in the second quarter of 2003. See
“—Significant Events.”
Other
revenues for 2003 increased $62.5 million primarily due to $82.7 million of
costs incurred and billed to customers on a reimbursable basis (see
“—Overview”), partially offset by a decrease of $17.9 million from the favorable
settlement of a contract dispute during 2002 and a decrease in revenue from
management fees as a result of the consolidation of DDII LLC late in the second
quarter of 2003 and discontinued management of the Seillean.
The
increase in this segment’s operating and maintenance expense was primarily due
to the recognition of approximately $83.0 million in client reimbursable costs
as operating and maintenance expense as a result of implementing EITF 99-19 in
2003 (see “—Overview”). In addition, expenses increased approximately $89.9
million due to costs associated with the riser separation incident on the
Discoverer
Enterprise, the
consolidation of DDII LLC, which leased the
Deepwater Frontier, the
restructuring of the Nigeria defined benefit plan, costs related to the
electrical fire on the Peregrine
I and the
transfer of a jackup rig into this segment from the TODCO segment during the
second quarter of 2002 (see “—Significant Events”). Partially offsetting these
increases were decreased operating and maintenance expenses of approximately
$51.0 million resulting from lower activity, implementation of standardized
purchasing through negotiated agreements, nationalization of our labor force in
certain operating locations and headcount reductions in support groups.
Operating and maintenance expenses were further reduced by $44.0 million
relating to rigs sold, returned to owner or removed from drilling service during
and subsequent to 2002, the settlements of a dispute and an insurance claim as
well as a reduction in our insurance program expense during 2003 and costs
incurred in 2002 associated with restructuring charges and a litigation
provision with no comparable activity in 2003.
The
increase in this segment’s depreciation expense resulted primarily from $9.1
million of additional depreciation on capital upgrades, the transfer of a rig
from the TODCO segment into this segment and depreciation expense related to
assets reclassified from held for sale to our active fleet during 2002 because
they no longer met the criteria for assets held for sale under SFAS 144. These
increases were partially offset by lower depreciation expense of $2.8 million
following the sale of rigs classified as held and used during and subsequent to
2002.
The
decrease in impairment loss in this segment is primarily due to the recognition
of a $2,494.1 million goodwill impairment charge that resulted from our annual
impairment test of goodwill conducted as of October 1, 2002 with no comparable
charge in 2003. The impairment charge recorded in 2003 resulted from the removal
of two drilling units from our active fleet. In 2002, we also recorded $28.5
million of non-cash impairment charges in this segment primarily related to
assets reclassified from held for sale to our active fleet because they no
longer met the held for sale criteria under SFAS 144.
During
2003, this segment recognized net pre-tax gains of $4.9 million related to the
sale of the RBF
160, the
Searex
15, the
settlement of an insurance claim and the sale of other assets. During 2002, this
segment recognized net pre-tax gains of $5.5 million related to the sale of the
Transocean
96, Transocean 97 and a
mobile offshore production unit, the partial settlement of an insurance claim
and the sale of other assets, which were partially offset by net pre-tax losses
of $2.8 million from the sale of the RBF
209 and an
office building.
TODCO
Segment
| |
|
Years
ended |
|
|
|
|
|
| |
|
December
31, |
|
|
|
|
|
| |
|
2003 |
|
2002 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except day amounts and percentages) |
|
| |
|
|
|
|
Revenue
earning days (a) |
|
|
10,953 |
|
|
9,101 |
|
|
1,852 |
|
|
20 |
% |
|
Utilization
(b) |
|
|
41 |
% |
|
34 |
% |
|
N/A |
|
|
21 |
% |
|
Average
dayrate (c) |
|
$ |
19,200 |
|
$ |
20,600 |
|
$ |
(1,400 |
) |
|
(7 |
)% |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract
drilling revenues |
|
$ |
209.8 |
|
$ |
187.8 |
|
$ |
22.0 |
|
|
12 |
% |
|
Other
revenues |
|
|
17.8 |
|
|
- |
|
|
17.8 |
|
|
N/M |
|
| |
|
|
227.6 |
|
|
187.8 |
|
|
39.8 |
|
|
21 |
% |
|
Operating
and maintenance expense |
|
|
242.5 |
|
|
202.9 |
|
|
39.6 |
|
|
20 |
% |
|
Depreciation |
|
|
92.2 |
|
|
91.9 |
|
|
0.3 |
|
|
N/M |
|
|
Impairment
loss on long-lived assets and goodwill |
|
|
11.3 |
|
|
399.3 |
|
|
(388.0 |
) |
|
N/M |
|
|
Gain
from sale of assets, net |
|
|
(0.9 |
) |
|
(1.0 |
) |
|
0.1 |
|
|
(10 |
)% |
|
Operating
loss before general and administrative expense |
|
$ |
(117.5 |
) |
$ |
(505.3 |
) |
$ |
387.8 |
|
|
77 |
% |
_________________
“N/A”
means not applicable
“N/M”
means not meaningful
| (a) |
Revenue earning day is a day for which a rig earns
dayrate after commencement of operations. |
|
(b) |
Utilization
is defined as the total actual number of revenue earning days as a
percentage of total number of calendar days in the
period. |
|
(a) |
Average
dayrate is defined as contract drilling revenue earned per revenue earning
day. |
Higher
utilization in 2003 resulted in an increase in this segment’s contract drilling
revenue of $42.9 million, partially offset by a decrease of $21.7 million due to
lower average dayrates.
Other
revenues for 2003 included $17.8 million related to costs incurred and billed to
customers on a reimbursable basis. See “—Overview.”
A large
portion of our operating and maintenance expense consists of employee-related
costs and is fixed or only semi-variable. Accordingly, operating and maintenance
expense does not vary in direct proportion to activity or dayrates.
The
increase in this segment’s operating and maintenance expense was due primarily
to approximately $18.0 million in client reimbursable costs as operating and
maintenance expense as a result of implementing EITF 99-19 during 2003 (see
“—Overview”). In addition, expenses increased due to an
increase in activity of approximately $14.0 million in 2003, costs of
approximately $11.0 million associated with the well control incident on inland
barge Rig
62 and the
fire incident on inland barge Rig
20 (see
“―Significant
Events”), as well as approximately $7.4 million related to a
write-down of other receivables, an insurance claim provision and the
consolidation of a joint venture that owns two land rigs during the third
quarter of 2002. These increases were partially offset by approximately $10.9
million of reduced expense relating to our insurance program in 2003 compared to
the same period in 2002, the release of a provision for doubtful accounts
receivable during 2003 upon collection of amounts previously
reserved, lower
expenses resulting from the transfer of a jackup rig from this segment into the
Transocean Drilling segment during the second quarter of 2002 and
severance-related costs, other restructuring charges and compensation-related
expenses incurred in 2002 with no comparable activity in 2003.
The
decrease in impairment loss in this segment is primarily due to the recognition
of a $381.9 million non-cash goodwill impairment charge that resulted from our
annual impairment test of goodwill conducted as of October 1, 2002 with no
comparable charge in 2003. Our 2003 impairment charges resulted primarily from
our decision to take five jackup rigs out of drilling service and market the
rigs for alternative uses. In 2002, we recorded non-cash impairment charges in
this segment of $17.4 million primarily related to assets reclassified from held
for sale to our active fleet because they no longer met the held for sale
criteria under SFAS 144.
Total
Company Results of Operations
| |
|
Years
ended |
|
|
|
|
|
| |
|
December
31, |
|
|
|
|
|
| |
|
2003 |
|
2002 |
|
Change |
|
%
Change |
|
| |
|
(In
millions, except % change) |
|
| |
|
|
|
|
|
|
|
|
|
|
General
and Administrative Expense |
|
$ |
65.3 |
|
$ |
65.6 |
|
$ |
(0.3 |
) |
|
N/M |
|
|
Other
(Income) Expense, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of unconsolidated subsidiaries |
|
|
(5.1 |
) |
|
(7.8 |
) |
|
2.7 |
|
|
(35 |
)% |
|
Interest
income |
|
|
(18.8 |
) |
|
(25.6 |
) |
|
6.8 |
|
|
(26 |
)% |
|
Interest
expense, net of amounts capitalized |
|
|
202.0 |
|
|
212.0 |
|
|
(10.0 |
) |
|
(5 |
)% |
|
Loss
on retirement of debt |
|
|
15.7 |
|
|
− |
|
|
15.7 |
|
|
N/M |
|
|
Impairment
loss on note receivable from related party |
|
|
21.3 |
|
|
− |
|
|
21.3 |
|
|
N/M |
|
|
Other,
net |
|
|
3.0 |
|
|
0.3 |
|
|
2.7 |
|
|
N/M |
|
|
Income
Tax Expense (Benefit) |
|
|
3.0 |
|
|
(123.0 |
) |
|
126.0 |
|
|
N/M |
|
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
(0.8 |
) |
|
1,363.7 |
|
|
(1,364.5 |
) |
|
N/M |
|
_________________________
“N/M”
means not meaningful
The
decrease in general and administrative expense was primarily attributable to
$9.0 million of costs related to the exchange of our newly issued notes for
TODCO’s notes in March 2002 as more fully described in Note 8 to our
consolidated financial statements and reduced expense related to employee
benefits for 2003. Offsetting these decreases was $8.8 million in expenses
relating to the TODCO IPO in 2003, of which $3.1 million was incurred and
deferred in 2002.
Equity in
earnings of unconsolidated subsidiaries decreased approximately $3.8 million
primarily related to TODCO’s 25 percent share of losses from Delta Towing, which
included TODCO’s share of non-cash impairment charges on the carrying value of
Delta Towing’s fleet and a decrease in our 50 percent share of earnings from
ODL, which owns the drillship Joides
Resolution, as the
rig came off contract in the third quarter of 2003. Offsetting these decreases
was an increase in equity in earnings of $1.6 million related to our 50 percent
share of earnings of DD LLC, which leased the Deepwater
Pathfinder, as a
result of the rig’s increased utilization and average dayrates in 2003 compared
to the same period in 2002.
The
decrease in interest income was primarily due to a decrease of $3.2 million in
interest earned on the notes receivable from Delta Towing due largely to the
establishment of a reserve in the third quarter of 2003 resulting from Delta
Towing’s failure to make scheduled quarterly interest payments. Also
contributing to the decrease was lower average cash balances for 2003 compared
to 2002 primarily due to the utilization of cash for debt reduction and capital
expenditures.
The
decrease in interest expense was attributable to reductions in interest expense
of $29.7 million associated with debt that was refinanced, repaid or retired
during and subsequent to 2002. We also received a refund of interest in 2003
from a taxing authority compared to an interest payment in 2002 resulting in a
reduction in interest expense of $2.1 million. 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 $22.2 million (see “—Derivative Instruments”).
During
2003, we recognized a $15.7 million loss on early retirements of $888.6 million
face value debt.
During
2003, we recognized a $21.3 million impairment loss on TODCO’s note receivable
from Delta Towing.
We
recognized a $3.5 million loss in other, net relating to the effect of foreign
currency exchange rate changes on our monetary assets and liabilities primarily
those denominated in Venezuelan bolivars, partially offset by the favorable
effect of foreign currency exchange rate changes on a U.K. pound denominated
escrow deposit.
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 year ended December 31, 2003 included a tax benefit of $14.6 million
attributable to the favorable resolution of a non-U.S. income tax liability,
partially offset by an increase in our estimated annual effective tax rate to
approximately 30 percent on earnings before non-cash note receivable and other
asset impairments, loss on debt retirements, TODCO IPO-related costs and Nigeria
benefit plan restructuring costs compared to our effective tax rate of
approximately 14 percent for 2002. The year ended December 31, 2002 included a
non-U.S. tax benefit of $175.7 million attributable to the restructuring of
certain non-U.S. operations.
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. During 2002,
we recognized a $1,363.7 million goodwill impairment charge in our TODCO
reporting unit as a cumulative effect of a change in accounting principle
related to the implementation of SFAS 142.
Critical
Accounting Policies and 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 these 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 are believed to be 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.
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 to us 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 customers regarding the application of
contract provisions to our drilling operations. We derive a majority of our
revenue from services to international oil companies and government-owned or
government-controlled oil companies. Our receivables are concentrated in certain
oil-producing countries. We generally do not require collateral or other
security to support client receivables.
If the
financial condition of our clients was to deteriorate or their access to freely
convertible currency was restricted, resulting in impairment of their ability to
make the required payments, additional allowances may be required. During the
years ended December 31, 2004, 2003 and 2002, we established new reserves for
doubtful accounts of $10.2 million, $24.4 million and $16.6 million,
respectively. Additionally, in each of the three years ended December 31, 2004,
we wrote off uncollectible accounts of $6.9 million, $7.5 million and $11.4
million, respectively, all of which had been previously reserved.
Income
taxes—We are a
Cayman Islands company. The Cayman Islands does not impose corporate income
taxes. We provide income taxes 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 taxes because the countries 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. Our effective tax rate
is expected to fluctuate from year to year as our operations are conducted in
different taxing jurisdictions and the amount of pre-tax income
fluctuates.
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 reserves for estimated tax exposures in jurisdictions of operation. Our
annual tax provision includes the impact of reserve provisions and changes to
reserves 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 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.
We have
recently completed an IRS examination for the calendar years 1999 and 2000. The
IRS has also notified us of its intent to audit our 2002 and 2003 tax years. We
are also undergoing examinations in other taxing jurisdictions for various
fiscal years. The liabilities associated with these examinations will ultimately
be resolved when events such as the completion of audits by the taxing
jurisdictions, administrative appeals procedures and/or judicial decisions
occur. To the extent the audits or other events result in an adjustment to the
accrued estimates, the effect would be recognized in the period of the
event.
We do not
believe it is possible to reasonably estimate the potential impact of changes to
the assumptions and estimates identified because the resulting change to our tax
liability, if any, is dependent on numerous factors which cannot be reasonably
estimated. These include, among others, the amount and nature of additional
taxes potentially asserted by local tax authorities; the willingness of local
tax authorities to negotiate a fair settlement through an administrative
process; the impartiality of the local courts; and the potential for changes in
the tax paid to one country to either produce, or fail to produce, an offsetting
tax change in other countries. Our experience has been that the estimates and
assumptions we have used to provide for future tax assessments have proven to be
appropriate. However, past experience is only a guide and the potential exists
that the tax resulting from the resolution of current and potential future tax
controversies may differ materially from the amounts accrued.
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, 2002, 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 $112.3 million.
We increased the valuation allowance as of December 31, 2003 to $181.8 million,
and decreased it to $115.3 million as of December 31, 2004. 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 “—Historical 2004 compared to 2003” and
“—Historical 2003 compared to 2002.” We continually evaluate strategies that
could allow for the future utilization of our deferred tax assets.
We have
not provided for U.S. deferred taxes on the unremitted earnings of our
U.S. subsidiaries and certain foreign subsidiaries that are permanently
reinvested. Should we make a distribution from the unremitted earnings of these
subsidiaries, we could be required to record additional taxes. At the current
time, a determination of the amount of unrecognized deferred tax liability is
not practical.
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 adverse
effect on our consolidated financial position, results of operations and 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.
Property
and equipment—Our
property and equipment represents 65 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 $32 million while a one year decrease
would cause an increase in our annual depreciation expense of approximately $47
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.
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 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.
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 $3.4 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 liability for claims incurred but not reported 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.
Restructuring
Charges
In
September 2002, we committed to restructuring plans in France and Norway. We
established a liability of approximately $4.0 million for the estimated
severance-related costs associated with the involuntary termination of 24
employees pursuant to these plans. The charge was reported as operating and
maintenance expense in our consolidated statements of operations related to the
Transocean Drilling segment. Through December 31, 2004, approximately $3.6
million had been paid to 24 employees representing full or partial payments. In
June 2003, we released the expected surplus liability of $0.3 million to
operating and maintenance expense in the Transocean Drilling segment.
Substantially all of the remaining liability is expected to be paid by the end
of the first quarter in 2005.
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 an unfunded defined benefit plan (the “Nigeria
Plan”) that provides retirement and severance benefits for certain of our
Nigerian employees. The benefits we provide under defined benefit pension plans
are comprised of the U.S. Plans, the Norway Plans and the Nigeria Plan
(collectively, the “Transocean Plans”).
| |
|
Retirement
Plan |
|
Supplemental
Retirement
Plan |
|
Frozen
Plans |
|
Subtotal-
U.S.
Plans |
|
Norway
Plans |
|
Nigeria
Plan |
|
Total
Transocean Plans |
_____ |
| |
(in
millions) |
|
|
Accumulated
Benefit Obligation |
|
|
|
At
December 31, 2004 |
|
$ |
115.8 |
|
$ |
5.9 |
|
$ |
109.1 |
|
$ |
230.8 |
|
$ |
38.8 |
|
$ |
0.3 |
|
$ |
269.9 |
|
|
At
December 31, 2003 |
|
|
101.4 |
|
|
7.7 |
|
|
102.2 |
|
|
211.3 |
|
|
30.2 |
|
|
- |
|
|
241.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Projected
Benefit Obligation |
|
|
|
At
December 31, 2004 |
|
$ |
154.8 |
|
$ |
8.9 |
|
$ |
109.1 |
|
$ |
272.8 |
|
$ |
53.0 |
|
$ |
0.4 |
|
$ |
326.2 |
|
|
At
December 31, 2003 |
|
|
138.1 |
|
|
10.9 |
|
|
102.2 |
|
|
251.2 |
|
|
44.2 |
|
|
0.1 |
|
|
295.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair
Value of Plan Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
$ |
107.3 |
|
$ |
- |
|
$ |
94.4 |
|
$ |
201.7 |
|
$ |
34.9 |
|
$ |
- |
|
$ |
236.6 |
|
|
At
December 31, 2003 |
|
|
95.0 |
|
|
- |
|
|
91.3 |
|
|
186.3 |
|
|
28.1 |
|
|
- |
|
|
214.4 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded
Status |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
$ |
(47.5 |
) |
$ |
(8.9 |
) |
$ |
(14.7 |
) |
$ |
(71.1 |
) |
$ |
(18.1 |
) |
$ |
(0.4 |
) |
$ |
(89.6 |
) |
|
At
December 31, 2003 |
|
|
(43.1 |
) |
|
(10.9 |
) |
|
(10.9 |
) |
|
(64.9 |
) |
|
(16.1 |
) |
|
(0.1 |
) |
|
(81.1 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net
Periodic Benefit Cost (Income) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ending December 31, 2004 |
|
$ |
11.3 |
|
$ |
1.7 |
|
$ |
(0.7 |
) |
$ |
12.3 |
|
$ |
4.5 |
|
$ |
0.2 |
|
$ |
17.0 |
(a) |
|
Year
Ending December 31, 2003 |
|
|
10.7 |
|
|
1.6 |
|
|
(1.7 |
) |
|
10.6 |
|
|
(1.8 |
) |
|
13.0 |
|
|
21.8
|
(a) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change
in Accumulated Other Comprehensive Income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ending December 31, 2004 |
|
$ |
- |
|
$ |
1.5 |
|
$ |
4.8 |
|
$ |
6.3 |
|
$ |
- |
|
$ |
- |
|
$ |
6.3 |
|
|
Year
Ending December 31, 2003 |
|
|
(8.2 |
) |
|
1.3 |
|
|
(3.1 |
) |
|
(10.0 |
) |
|
- |
|
|
- |
|
|
(10.0 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Employer
Contributions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ending December 31, 2004 |
|
$ |
5.4 |
|
$ |
5.0 |
|
$ |
0.4 |
|
$ |
10.8 |
|
$ |
2.8 |
|
$ |
0.1 |
|
$ |
13.7 |
|
|
Year
Ending December 31, 2003 |
|
|
- |
|
|
0.7 |
|
|
0.4 |
|
|
1.1 |
|
|
3.8 |
|
|
18.4 |
|
|
23.3 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
Assumptions - Benefit Obligations |
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
|
5.50 |
% |
|
5.50 |
% |
|
5.50 |
% |
|
|
|
|
6.00 |
% |
|
20.00 |
% |
|
5.60 |
%
(b) |
|
At
December 31, 2003 |
|
|
6.00 |
% |
|
6.00 |
% |
|
6.00 |
% |
|
|
|
|
6.00 |
% |
|
20.00 |
% |
|
6.25 |
%
(b) |
|
Rate
of compensation increase |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
|
5.45 |
% |
|
5.45 |
% |
|
- |
|
|
|
|
|
3.50 |
% |
|
15.00 |
% |
|
5.00 |
%
(b) |
|
At
December 31, 2003 |
|
|
5.45 |
% |
|
5.45 |
% |
|
- |
|
|
|
|
|
3.50 |
% |
|
15.00 |
% |
|
5.24 |
%
(b) |
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted-Average
Assumptions - Net Periodic Benefit Cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount
rate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
|
6.00 |
% |
|
6.00 |
% |
|
6.00 |
% |
|
|
|
|
6.00 |
% |
|
20.00 |
% |
|
6.01 |
%
(b) |
|
At
December 31, 2003 |
|
|
6.50 |
% |
|
6.50 |
% |
|
6.50 |
% |
|
|
|
|
6.00 |
% |
|
20.00 |
% |
|
6.65 |
%
(b) |
|
Expected
long-term rate of return on plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
|
9.00 |
% |
|
- |
|
|
9.00 |
% |
|
|
|
|
7.00 |
% |
|
- |
|
|
8.73 |
%
(c) |
|
At
December 31, 2003 |
|
|
9.00 |
% |
|
- |
|
|
9.00 |
% |
|
|
|
|
7.00 |
% |
|
- |
|
|
8.73 |
%
(c) |
|
Rate
of compensation increase |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At
December 31, 2004 |
|
|
5.45 |
% |
|
5.45 |
% |
|
- |
|
|
|
|
|
3.50 |
% |
|
15.00 |
% |
|
5.00 |
%
(b) |
|
At
December 31, 2003 |
|
|
5.45 |
% |
|
5.45 |
% |
|
- |
|
|
|
|
|
3.50 |
% |
|
15.00 |
% |
|
5.24 |
%
(b) |
______________
|
(a) |
Pension
costs were reduced by expected returns on plan assets of $19.6 million and
$19.7 million for the years ended December 31, 2004 and 2003,
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. A contribution of
$5.4 million was made to the funded U.S. Plans during 2004. No contributions
were made to the funded U.S. Plans during 2003. Contributions of $5.4 million
and $1.1 million to the unfunded U.S. Plans in 2004 and 2003, respectively, were
to fund benefit payments.
The $13.7
million we contributed to the Transocean Plans in 2004 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, |
|
| |
|
2004 |
|
2003 |
|
Components
of Net Periodic Benefit Cost (a) |
|
|
|
|
|
|
Service
cost |
|
$ |
16.7 |
|
$ |
16.6 |
|
|
Interest
cost |
|
|
16.7 |
|
|
18.2 |
|
|
Expected
return on plan assets |
|
|
(19.6 |
) |
|
(19.7 |
) |
|
Amortization
of transition obligation |
|
|
0.3 |
|
|
0.3 |
|
|
Amortization
of prior service cost |
|
|
0.6 |
|
|
1.3 |
|
|
Recognized
net actuarial losses |
|
|
2.3 |
|
|
0.4 |
|
|
SFAS
88 settlements/curtailments |
|
|
- |
|
|
4.7 |
|
|
Benefit
cost |
|
$ |
17.0 |
|
$ |
21.8 |
|
| ______________ |
|
|
|
|
|
|
|
| (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 2004 and an allocation of
approximately 55 percent of plan assets to equity securities. Debt securities
and other investments also experienced increased values, but to a lesser extent.
During 2004, the market value of the investments in the Transocean Plans
increased by $22.1 million, or 10.3 percent. The increase is due to net
investment gains of $22.6 million, primarily in the funded U.S. Plans, resulting
from the favorable performance of equity markets in 2004, partially offset by
benefit plan payments of $17.4 million from these plans. We expect to contribute
$3.0 million to the Transocean Plans in 2005, comprised of an estimated $0.6
million to fund expected benefit payments for the unfunded U.S. Plans and
Nigeria Plan, and an estimated $2.4 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, 2004, we had cumulative losses of $80.5
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 which reflect expected future service, as
appropriate, are expected to be paid by the Transocean Plans (in
millions):
| |
|
Years
ending
December 31, |
|
| |
|
|
|
|
2005 |
|
$ |
13.5 |
|
|
2006 |
|
|
13.9 |
|
|
2007 |
|
|
14.4 |
|
|
2008 |
|
|
15.1 |
|
|
2009 |
|
|
15.7 |
|
|
Thereafter |
|
|
118.5 |
|
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. During 2002, we recorded a non-cash minimum pension
liability adjustment related to the U.S. Plans that resulted in a charge to
other comprehensive income of $45.7 million ($32.5 million, net of tax). This
charge was attributable primarily to the decline in the market value of the
funded U.S. Plans’ assets and increased benefit obligations associated with a
reduction in the discount rate that resulted in the value of the funded U.S.
Plans’ assets being less than the accumulated benefit obligation. In 2003, the
increase in the fair value of plan assets more than offset the effect of the
decrease in the discount rate resulting in a decrease in the minimum pension
liability of $10.0 million ($9.3 million, net of tax). 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
($4.1 million, net of tax). At December 31, 2004, the minimum pension liability
included in other comprehensive income was $42.0 million ($27.3 million, net of
tax). The minimum pension liability adjustments did not impact our results of
operations during 2002, 2003 or 2004, nor did these adjustments affect our
ability to meet any financial covenants related to our debt facilities.
Our
expected long-term rate of return on plan assets for the funded U.S. Plans was
9.0 percent as of December 31, 2004 and 2003. 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, 2004, 6.0 percent at December 31,
2003 and 6.5 percent at December 31, 2002. We expect pension expense related to
the Transocean Plans for 2005 to increase by approximately $5.2 million
primarily due to the change in discount rate assumptions.
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).
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, |
|
| |
|
2004 |
|
2003 |
|
Components
of Net Periodic Benefit Cost (a) |
|
|
|
|
|
|
Service
cost |
|
$ |
1.0 |
|
$ |
2.0 |
|
|
Interest
cost |
|
|
2.1 |
|
|
3.4 |
|
|
Amortization
of prior service cost |
|
|
(2.3 |
) |
|
0.3 |
|
|
Recognized
net actuarial losses |
|
|
1.5 |
|
|
1.3 |
|
|
Settlements/curtailments
|
|
|
- |
|
|
(0.6 |
) |
|
Benefit
cost |
|
$ |
2.3 |
|
$ |
6.4 |
|
| ______________ |
|
|
|
|
|
|
|
| (a) Amounts
are before income tax effect. |
|
|
|
|
|
|
|
The
following postretirement benefits payments are expected to be paid (in
millions):
| |
|
Years
ending December 31, |
|
| |
|
|
|
|
2005 |
|
$ |
1.4 |
|
|
2006 |
|
|
1.5 |
|
|
2007 |
|
|
1.6 |
|
|
2008 |
|
|
1.7 |
|
|
2009 |
|
|
1.8 |
|
|
Thereafter |
|
|
10.7 |
|
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 postretirement 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.
In May
2004, the FASB staff 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 year ended
December 31, 2004.
Off-Balance
Sheet Arrangement
We lease
the semisubmersible rig M. G.
Hulme, Jr. from
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 are obligated to pay rent of approximately $11.9
million in 2005. In November 2004 we gave notice to Deep Sea Investors of our
intent to purchase the rig under the lease purchase option at the end of the
lease term in November 2005. Based on this notice, we are now obligated to
purchase the rig and we have agreed to a purchase price of $35.7 million. The
lease does not require that collateral be maintained or contain any credit
rating triggers.
Effective
December 31, 2003, we adopted and applied the provisions of FIN 46, as revised
December 31, 2003, for all variable interest entities. FIN 46 requires the
consolidation of variable interest entities in which an enterprise absorbs a
majority of the entity’s expected losses, receives a majority of the entity’s
expected residual returns, or both, as a result of ownership, contractual or
other financial interests in the entity. Because the sale/leaseback agreement is
with an entity in which we have no direct investment, we are not entitled to
receive the financial information of the leasing entity and the equity holders
of the leasing company will not release the financial statements or other
financial information to us in order for us to make the determination of whether
the entity is a variable interest entity. In addition, without the financial
statements or other financial information, we are unable to determine if we are
the primary beneficiary of the entity and, if so, what we would consolidate. We
have no exposure to loss as a result of the sale/leaseback agreement. We
currently account for the lease of this semisubmersible drilling rig as an
operating lease.
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 2004, we earned
$2.4 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.
TODCO—We own a
22 percent interest in TODCO (see “—Significant Events”). 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,
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. Amounts recorded between us
and TODCO subsequent to the deconsolidation of TODCO on December 17, 2004 were
not material. At December 31, 2004, we had payables related to the
administrative support TODCO provides of $0.3 million, which is included in
accounts payable in the consolidated balance sheet. At December 31, 2004, we had
a long-term payable related to our indemnification of certain TODCO non-U.S.
income tax liabilities of $11.2 million, which is included in other long-term
liabilities in the 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 current consolidated
financial position, results of operations and cash flows. Until April 2005, we
also guarantee $11.9 million of TODCO’s surety bonds, which TODCO has
collateralized.
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.
The
master separation agreement also contains several provisions regarding TODCO’s
corporate governance and accounting practices that apply as long as we own
specified percentages of TODCO’s common stock. As long as we own shares
representing at least 10 percent of the voting power of TODCO’s outstanding
voting stock, we have the right to designate for nomination a number of
directors proportionate to our voting power and designate one member of any
committee of TODCO’s board of directors.
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. 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.
As of December 31, 2004, TODCO is estimated to have approximately $375 million
of pre-closing tax benefits subject to its obligation to reimburse Transocean
Holdings, after elimination of those benefits TODCO expects to use in connection
with its separation from Transocean Holdings. The ultimate amount will depend on
many factors, including the ultimate allocation of tax benefits between TODCO
and our other subsidiaries under applicable law and taxable income for calendar
year 2004. Income taxes and income tax benefits accruing after the closing of
the TODCO IPO, to the extent attributable to Transocean Holdings or its
affiliates (other than TODCO or its subsidiaries), generally will be for the
account of Transocean Holdings and, to the extent attributable to TODCO or its
subsidiaries, generally will be for the account of TODCO. However, TODCO will be
responsible for all taxes, other than income taxes, attributable to the TODCO
business, whether accruing before, on or after the closing of the TODCO IPO.
Exceptions
to the general allocation rules discussed above may apply with respect to
specific tax items or under special circumstances, including in circumstances
where TODCO’s use or absorption of any pre-closing tax benefit defers or
precludes its use or absorption of any income tax benefit created after the
closing of the TODCO IPO or arises out of or relates to the alternative minimum
tax provisions of the U.S. Internal Revenue Code. In addition, TODCO generally
must pay Transocean Holdings for any tax benefits otherwise attributable to
TODCO that result from the delivery by Transocean or its subsidiaries, after the
closing of the TODCO IPO, of stock of Transocean to an employee of TODCO in
connection with the exercise of an employee stock option. If any person other
than Transocean or its subsidiaries becomes the beneficial owner of greater than
50 percent of the aggregate voting power of TODCO’s outstanding voting stock,
TODCO will be deemed to have used or absorbed all pre-closing tax benefits and
generally will be required to pay Transocean Holdings a specified amount for
these pre-closing tax benefits at the time the requisite voting power is
attained. Moreover, if any of TODCO’s subsidiaries that join with TODCO in the
filing of consolidated returns ceases to join in the filing of such returns,
TODCO will be deemed to have used that portion of the pre-closing tax benefits
attributable to that subsidiary following the cessation, and TODCO generally
will be required to pay Transocean Holdings a specified amount for this deemed
tax benefit at the time such subsidiary ceases to join in the filing of such
returns.
Other
Agreements with TODCO—In
addition to the agreements described above, we also entered into the following
agreements with TODCO: (1) a transition services agreement under which we
will provide specified administrative support during the transitional period
following the closing of the TODCO IPO, (2) an employee matters agreement that
allocates specified assets, liabilities and responsibilities relating to TODCO’s
current and former employees and their participation in our benefit plans under
which we have generally agreed to indemnify TODCO for employment liabilities
arising from any acts of our employees or from claims by our employees against
TODCO and for liabilities relating to benefits for our employees (and TODCO has
generally agreed to similarly indemnify us) and (3) a registration rights
agreement under which TODCO has agreed to register the sale of shares of TODCO’s
common stock held by us under the Securities Act of 1933, as amended, and
granted us “piggy-back” registration rights.
New
Accounting Pronouncements
In April
2004, the FASB issued FSP 129-1, Disclosure
of Information about Capital Structure,
Relating
to Contingently Convertible Securities, which
applies to all contingently convertible securities and became effective the date
of issue. The FSP requires disclosure of the nature of the contingency and the
potential impact of conversion on the financial statements, particularly the
impact on earnings per share, and whether the securities have been included in
the entity’s calculation of diluted earnings per share. The implementation of
this FSP did not have an effect on our consolidated financial statements and
related notes thereto as our disclosures are in accordance with the disclosure
requirements as stated in this FSP.
In
September 2004, the EITF of the FASB reached a consensus on issue No. 04-08,
The
Effect of Contingently Convertible Instruments on Diluted Earnings per Share
(“EITF
04-08”), which is effective for reporting periods ending after December 15,
2004. Contingently convertible instruments within the scope of EITF 04-08 are
instruments that contain conversion features that are contingently convertible
or exercisable based on (a) a market price trigger or (b) multiple contingencies
if one of the contingencies is a market price trigger for which the instrument
may be converted or share settled based on meeting a specified market condition.
EITF 04-08 requires companies to include shares issuable under convertible
instruments in diluted earnings per share computations (if dilutive) regardless
of whether the market price trigger (or other contingent feature) has been met.
In addition, prior period earnings per share amounts presented for comparative
purposes must be restated. We adopted EITF 04-08 as of December 31, 2004 and the
adoption did not have an effect on our earnings per share for the years ended
December 31, 2004, 2003 and 2002.
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 Accounting Principles Board (“APB”) Opinion No. 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. SFAS
123(R) requires adoption no later than July 1, 2005.
SFAS
123(R) permits adoption using one of two methods: (i) a modified prospective
method in which compensation costs are recognized beginning with the effective
date based on the requirements of SFAS 123(R) (a) for all share-based payments
granted after the effective date and (b) for all awards granted to employees
prior to the effective date of SFAS 123(R) that remain unvested on the effective
date or (ii) a modified retrospective method, which includes the requirements of
the modified prospective method but also permits entities to restate based on
the amounts previously recognized under SFAS 123 for purposes of pro forma
disclosures either (a) all prior periods presented or (b) prior interim periods
of the year of adoption.
Although
we will adopt SFAS 123(R) effective July 1, 2005, we have not determined which
method we will use. We adopted the fair-value-based method of accounting for
share-based payments effective January 1, 2003 using the modified prospective
method as described in SFAS 148, Accounting
for Stock-Based Compensation-Transition and Disclosure. While
we currently use the Black-Scholes formula to estimate the value of stock
options granted to employees, which is an acceptable share-based award valuation
model, we may choose some other model that is also acceptable in determining
fair value of stock awards upon adoption of SFAS 123(R). Because SFAS 123(R)
must be applied to unvested awards granted and accounted for under APB 25, any
additional compensation costs not previously recognized under SFAS 123 will be
recognized under SFAS 123(R). Our unvested APB 25 options will vest in the third
quarter of 2005. If we adopt SFAS 123(R) using the modified prospective method,
the impact would not be material to our consolidated financial position, results
of operations or cash flows. If we adopt using the modified retrospective
method, the impact of those amounts would approximate the amounts described in
our pro forma net income and earnings per share disclosure in Note 2 to our
consolidated financial statements under “Item 8. Financial Statements and
Supplementary Data” included elsewhere in this annual report. 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 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 recognized operating cash flows related to
the tax deduction benefits of $5.9 million, $0.3 million and $0.3 million in
2004, 2003 and 2002, respectively.
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 the Organization of Petroleum Exporting Countries, commonly
called “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.
|
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 is highly competitive and cyclical, with intense price
competition.
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.
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 caused by equipment problems 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, and loss of production, loss of
well control, punchthroughs, craterings and natural disasters such as hurricanes
and fires. 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 operators 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 may 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
maintain 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, and action of waves, punch-throughs, cratering, blowouts,
explosions, and war risks. We insure all of our offshore drilling equipment for
general and third party liabilities, occupational and illness risks, and
property damage. We generally insure all of our offshore drilling rigs against
property damage for their approximate fair market value.
In
accordance with industry practices, we believe we are adequately insured
for
normal
risks in our operations; however, such insurance coverage may 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 for
their approximate fair
market value,
our insurance would not completely cover the costs that would be required to
replace certain of our units, including certain High-Specification Floaters. We
have also
increased our
deductibles such that
certain
claims may not be reimbursed by insurance carriers. Such lack of reimbursement
may cause the
company
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 a 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
recent terrorist attacks. As of February 28, 2005, 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
of 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 to the country of operation. We
seek to limit these risks by structuring contracts such that compensation is
made in freely convertible currencies and, to the extent possible, by limiting
acceptance of non-convertible currencies to amounts that match our expense
requirements in local currency.
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 taxation policies in the jurisdictions in which we operate, which
could include policies directed toward companies organized in jurisdictions with
low tax rates. A material change in the tax laws of any country in which we have
significant operations, including the U.S., 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 “—Outlook” and “—Critical Accounting Policies and Estimates—Income
Taxes.”
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, 2005, approximately 15 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, substantially all
are working under agreements that are subject to salary negotiation in 2005.
These negotiations could result in higher personnel expenses, other increased
costs or increased operating restrictions.
Our
chief executive officer and nonemployee directors who also serve as directors of
TODCO may have potential conflicts of interest as to matters relating to TODCO
and Transocean.
Our chief
executive officer is a director of TODCO, and two of our nonemployee directors
are also directors of TODCO. As a result of their positions, these directors may
have potential conflicts of interest as to matters relating to TODCO and
Transocean. In connection with any transaction or other relationship involving
the two companies, these directors may need to recuse themselves and not
participate in any board action relating to these transactions or relationships.
In addition, our interests may conflict with those of TODCO in a number of areas
relating to our past and ongoing relationships. We may not be able to resolve
any potential conflicts with TODCO and, even if we do, the resolution may be
less favorable than if we were dealing with an unaffiliated third
party.
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, the clients will
have the financial capability to fulfill their contractual obligations to us.
Also, these indemnities may not be enforceable in all instances. Also, 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.
On
September 11, 2001, the U.S. was the target of terrorist attacks of
unprecedented scope. In the past several years, world political events have
resulted in military action in Afghanistan and Iraq. Military action by the U.S.
or other nations could escalate and further acts of terrorism in the U.S. or
elsewhere may occur. Such acts of terrorism could be directed against companies
such as ours. These developments have caused instability in the world's
financial and insurance markets. 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.
Inflation
The
general rate of inflation in the majority of the countries in which we operate
has been moderate over the past several years and has not had a material impact
on our results of operations.
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, revenues, expenses, commodity
prices, customer drilling programs, supply and demand, utilization rates,
dayrates, planned shipyard projects and rig mobilizations and their effects, rig
relocations, expected downtime, 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, plans to dispose of our remaining interest in
TODCO, the valuation allowance for deferred net tax assets of TODCO, intended
reduction of debt, planned asset sales, timing of asset sales, proceeds from
asset sales, our effective tax rate, the purchase of the M.G.
Hulme, Jr., changes
in tax laws, treaties and regulations, our Sarbanes-Oxley Section 404 process,
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,
pension plan contributions 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 “—Risk
Factors” above, 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.
ITEM 7A. 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 and
related weighted-average interest rates for each of the years ended
December 31 relating to debt as of December 31, 2004.
At
December 31, 2004 (in millions, except interest rate percentages):
| |
|
Scheduled
Maturity Date (a) (b) |
|
Fair
Value |
|
| |
|
2005 |
|
2006 |
|
2007 |
|
2008 |
|
2009 |
|
Thereafter |
|
Total |
|
12/31/04 |
|
Total
debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fixed
rate |
|
$ |
19.6 |
|
$ |
400.0 |
|
$ |
100.0 |
|
$ |
266.8 |
|
$ |
- |
|
$ |
1,603.8 |
|
$ |
2,390.2 |
|
$ |
2,702.5 |
|
|
Average
interest rate |
|
|
7.3 |
% |
|
1.5 |
% |
|
7.5 |
% |
|
6.7 |
% |
|
- |
|
|
7.1 |
% |
|
6.1 |
% |
|
|
|
__________________________
| (a) |
|
Maturity
dates of the face value of our debt assumes 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, 2004, 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, 2004 cash investment levels, a one percent increase
in interest rates would result in approximately $3.8 million of additional
interest income per year.
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. 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,
2004, we had no open foreign exchange derivative contracts.
ITEM 8. Financial
Statements and Supplementary Data
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, 2004. 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, 2004, 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, 2004. 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, 2004.
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, 2004, 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, 2004, 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, 2004, 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, 2004 and 2003, and the related
consolidated statements of operations, comprehensive income (loss), equity, and
cash flows for each of the three years in the period ended December 31, 2004 and
our report dated March 14, 2005 expressed an unqualified opinion
thereon.
Houston,
Texas
March 14,
2005
The Board
of Directors and Shareholders of Transocean Inc.
We have
audited the accompanying consolidated balance sheets of Transocean Inc. and
Subsidiaries (the “Company”) as of December 31, 2004 and 2003, and the related
consolidated statements of operations, comprehensive income (loss), equity, and
cash flows for each of
the three years in the period ended December 31, 2004. Our
audits also included the financial statement schedule listed in 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, 2004 and 2003, and the consolidated results of
their operations and their cash flows for each of the three years in the period
ended December 31, 2004, in conformity with U.S. generally accepted accounting
principles. Also, in our opinion, the related financial statement schedule, when
considered in relation to the basic financial statements taken as a whole,
presents fairly in all material respects the information set forth
therein.
As
discussed in Note 2 to the consolidated financial statements, the Company
adopted Statement of Financial Accounting Standards No. 123 effective January 1,
2003.
We also
have audited, in accordance with the standards of the Public Company Accounting
Oversight Board (United States), the effectiveness of Tranocean Inc.’s internal
control over financial reporting as of December 31, 2004, 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
14, 2005 expressed an unqualified opinion
thereon.
Houston,
Texas
March 14,
2005
CONSOLIDATED
STATEMENTS OF OPERATIONS
(In
millions, except per share data)
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
Operating
Revenues |
|
|
|
|
|
|
|
|
Contract
drilling revenues |
|
$ |
2,416.4 |
|
$ |
2,328.5 |
|
$ |
2,648.4 |
|
|
Other
revenues |
|
|
197.5 |
|
|
105.8 |
|
|
25.5 |
|
| |
|
|
2,613.9 |
|
|
2,434.3 |
|
|
2,673.9 |
|
|
Costs
and Expenses |
|
|
|
|
|
|
|
|
|
|
|
Operating
and maintenance |
|
|
1,726.3 |
|
|
1,610.4 |
|
|
1,494.2 |
|
|
Depreciation |
|
|
524.6 |
|
|
508.2 |
|
|
500.3 |
|
|
General
and administrative |
|
|
67.0 |
|
|
65.3 |
|
|
65.6 |
|
|
Impairment
loss on long-lived assets and goodwill |
|
|
− |
|
|
16.5 |
|
|
2,927.4 |
|
|
Gain
from sale of assets, net |
|
|
(31.9 |
) |
|
(5.8 |
) |
|
(3.7 |
) |
| |
|
|
2,286.0 |
|
|
2,194.6 |
|
|
4,983.8 |
|
|
Operating
Income (Loss) |
|
|
327.9 |
|
|
239.7 |
|
|
(2,309.9 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Other
Income (Expense), net |
|
|
|
|
|
|
|
|
|
|
|
Equity
in earnings of unconsolidated subsidiaries |
|
|
9.2 |
|
|
5.1 |
|
|
7.8 |
|
|
Interest
income |
|
|
9.3 |
|
|
18.8 |
|
|
25.6 |
|
|
Interest
expense |
|
|
(171.7 |
) |
|
(202.0 |
) |
|
(212.0 |
) |
|
Gain
from TODCO offerings |
|
|
308.8 |
|
|
− |
|
|
− |
|
|
Non-cash
TODCO tax sharing agreement charge |
|
|
(167.1 |
) |
|
− |
|
|
− |
|
|
Loss
on retirement of debt |
|
|
(76.5 |
) |
|
(15.7 |
) |
|
− |
|
|
Impairment
loss on note receivable from related party |
|
|
− |
|
|
(21.3 |
) |
|
− |
|
|
Other,
net |
|
|
0.4 |
|
|
(3.0 |
) |
|
(0.3 |
) |
| |
|
|
(87.6 |
) |
|
(218.1 |
) |
|
(178.9 |
) |
|
Income
(Loss) Before Income Taxes, Minority Interest and |
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
240.3 |
|
|
21.6 |
|
|
(2,488.8 |
) |
|
Income
Tax Expense (Benefit) |
|
|
91.3 |
|
|
3.0 |
|
|
(123.0 |
) |
|
Minority
Interest |
|
|
(3.2 |
) |
|
0.2 |
|
|
2.4 |
|
|
Income
(Loss) Before Cumulative Effect of Changes in Accounting
Principles |
|
|
152.2 |
|
|
18.4 |
|
|
(2,368.2 |
) |
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
− |
|
|
0.8 |
|
|
(1,363.7 |
) |
|
Net
Income (Loss) |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
(3,731.9 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted Earnings (Loss) Per Share |
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Cumulative Effect of Changes in Accounting
Principles |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(7.42 |
) |
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
− |
|
|
− |
|
|
(4.27 |
) |
|
Net
Income (Loss) |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(11.69 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Weighted
Average Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
|
320.9 |
|
|
319.8 |
|
|
319.1 |
|
|
Diluted |
|
|
325.2 |
|
|
321.4 |
|
|
319.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Dividends
Paid Per Share |
|
$ |
− |
|
$ |
− |
|
$ |
0.06 |
|
See accompanying notes.
CONSOLIDATED
STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In
millions)
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
Net
Income (Loss) |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
(3,731.9 |
) |
|
Other
Comprehensive Income (Loss), net of tax |
|
|
|
|
|
|
|
|
|
|
|
Amortization
of gain on terminated interest rate swaps |
|
|
(0.2 |
) |
|
(0.2 |
) |
|
(0.3 |
) |
|
Change
in unrealized loss on securities available for sale |
|
|
0.1 |
|
|
0.2 |
|
|
- |
|
|
Change
in share of unrealized loss in unconsolidated joint venture’s interest
rate swaps (net of tax expense (benefit) of $1.1 and $(1.1) for the years
ended December 31, 2003 and 2002, respectively) |
|
|
− |
|
|
2.0 |
|
|
3.6 |
|
|
Minimum
pension liability adjustments (net of tax expense (benefit) of $(2.2),
$0.7 and $(13.2) for the years ended December 31, 2004, 2003 and 2002,
respectively) |
|
|
(4.1 |
) |
|
9.3 |
|
|
(32.5 |
) |
|
Other
Comprehensive Income (Loss) |
|
|
(4.2 |
) |
|
11.3 |
|
|
(29.2 |
) |
|
Total
Comprehensive Income (Loss) |
|
$ |
148.0 |
|
$ |
30.5 |
|
$ |
(3,761.1 |
) |
See
accompanying notes.
CONSOLIDATED
BALANCE SHEETS
(In
millions, except share data)
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
|
ASSETS |
|
|
|
|
|
|
Cash
and Cash Equivalents |
|
$ |
451.3 |
|
$ |
474.0 |
|
|
Accounts
Receivable, net |
|
|
|
|
|
|
|
|
Trade |
|
|
426.5 |
|
|
435.3 |
|
|
Other |
|
|
15.5 |
|
|
45.0 |
|
|
Materials
and Supplies, net |
|
|
144.7 |
|
|
152.0 |
|
|
Deferred
Income Taxes, net |
|
|
19.0 |
|
|
41.0 |
|
|
Other
Current Assets |
|
|
52.1 |
|
|
31.6 |
|
|
Total
Current Assets |
|
|
1,109.1 |
|
|
1,178.9 |
|
| |
|
|
|
|
|
|
|
|
Property
and Equipment |
|
|
9,732.9 |
|
|
10,673.0 |
|
|
Less
Accumulated Depreciation |
|
|
2,727.7 |
|
|
2,663.4 |
|
|
Property
and Equipment, net |
|
|
7,005.2 |
|
|
8,009.6 |
|
|
Goodwill |
|
|
2,251.9 |
|
|
2,230.8 |
|
|
Investments
in and Advances to Unconsolidated Subsidiaries |
|
|
109.2 |
|
|
5.5 |
|
|
Deferred
Income Taxes |
|
|
43.8 |
|
|
28.2 |
|
|
Other
Assets |
|
|
239.1 |
|
|
209.6 |
|
|
Total
Assets |
|
|
|
|
|
|
|
|
|
|
$ |
10,758.3 |
|
$ |
11,662.6 |
|
| |
|
|
|
|
|
|
|
|
LIABILITIES
AND SHAREHOLDERS' EQUITY |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Accounts
Payable |
|
$ |
180.8 |
|
$ |
146.1 |
|
|
Accrued
Income Taxes |
|
|
17.1 |
|
|
57.2 |
|
|
Debt
Due Within One Year |
|
|
19.4 |
|
|
45.8 |
|
|
Other
Current Liabilities |
|
|
213.0 |
|
|
262.0 |
|
|
Total
Current Liabilities |
|
|
430.3 |
|
|
511.1 |
|
| |
|
|
|
|
|
|
|
|
Long-Term
Debt |
|
|
2,462.1 |
|
|
3,612.3 |
|
|
Deferred
Income Taxes, net |
|
|
124.1 |
|
|
42.8 |
|
|
Other
Long-Term Liabilities |
|
|
345.2 |
|
|
299.4 |
|
|
Total
Long-Term Liabilities |
|
|
2,931.4 |
|
|
3,954.5 |
|
| |
|
|
|
|
|
|
|
|
Commitments
and Contingencies |
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
Minority
Interest |
|
|
4.0 |
|
|
4.4 |
|
| |
|
|
|
|
|
|
|
|
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, 321,533,998 and
319,926,500 shares issued and outstanding at December 31, 2004 and 2003,
respectively |
|
|
3.2 |
|
|
3.2 |
|
|
Additional
Paid-in Capital |
|
|
10,695.8 |
|
|
10,643.8 |
|
|
Accumulated
Other Comprehensive Loss |
|
|
(24.4 |
) |
|
(20.2 |
) |
|
Retained
Deficit |
|
|
(3,282.0 |
) |
|
(3,434.2 |
) |
|
Total
Shareholders' Equity |
|
|
7,392.6 |
|
|
7,192.6 |
|
|
Total
Liabilities and Shareholders' Equity |
|
$ |
10,758.3 |
|
$ |
11,662.6 |
|
See
accompanying notes.
CONSOLIDATED
STATEMENTS OF EQUITY
(In
millions, except per share data)
| |
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
| |
|
|
|
|
|
Additional |
|
Other |
|
Retained |
|
|
|
| |
|
Ordinary
Shares |
|
Paid-in |
|
Comprehensive |
|
Earnings
|
|
Total |
|
| |
|
Shares |
|
Amount |
|
Capital |
|
Income
(Loss) |
|
(Deficit) |
|
Equity |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance
at December 31, 2001 |
|
|
318.8 |
|
$ |
3.2 |
|
$ |
10,611.7 |
|
$ |
(2.3 |
) |
$ |
297.7 |
|
$ |
10,910.3 |
|
|
Net
loss |
|
|
-
|
|
|
-
|
|
|
- |
|
|
- |
|
|
(3,731.9 |
) |
|
(3,731.9 |
) |
|
Issuance
of ordinary shares under |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock-based
compensation plans |
|
|
0.4 |
|
|
- |
|
|
10.9 |
|
|
- |
|
|
- |
|
|
10.9 |
|
|
Cash
dividends ($0.06 per share) |
|
|
- |
|
|
- |
|
|
- |
|
|
- |
|
|
(19.2 |
) |
|
(19.2 |
) |
|
Gain
on terminated interest rate swaps |
|
|
- |
|
|
- |
|
|
- |
|
|
(0.3 |
) |
|
- |
|
|
(0.3 |
) |
|
Other
comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
related
to joint venture |
|
|
- |
|
|
- |
|
|
- |
|
|
3.6 |
|
|
- |
|
|
3.6 |
|
|
Minimum
pension liability |
|
|
- |
|
|
- |
|
|
- |
|
|
(32.5 |
) |
|
- |
|
|
(32.5 |
) |
|
Other |
|
|
- |
|
|
- |
|
|
0.5 |
|
|
- |
|
|
- |
|
|
0.5 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
See
accompanying notes.
CONSOLIDATED
STATEMENTS OF CASH FLOWS
(In
millions)
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Cash
Flows from Operating Activities |
|
|
|
|
|
|
|
|
Net
income (loss) |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
(3,731.9 |
) |
|
Adjustments
to reconcile net income (loss) to net cash provided by
operating
activities |
|
|
|
|
|
|
|
|
|
|
|
Depreciation |
|
|
524.6 |
|
|
508.2 |
|
|
500.3 |
|
|
Stock-based
compensation expense |
|
|
25.3 |
|
|
6.3 |
|
|
0.8 |
|
|
Impairment
loss on goodwill |
|
|
− |
|
|
− |
|
|
4,239.7 |
|
|
Deferred
income taxes |
|
|
18.1 |
|
|
(98.5 |
) |
|
(224.4 |
) |
|
Equity
in earnings of unconsolidated subsidiaries |
|
|
(9.2 |
) |
|
(5.1 |
) |
|
(7.8 |
) |
|
Net
(gain) loss from disposal of assets |
|
|
(19.2 |
) |
|
13.4 |
|
|
3.9 |
|
|
Gain
from TODCO offerings |
|
|
(308.8 |
) |
|
− |
|
|
− |
|
|
Non-cash
TODCO tax sharing agreement charge |
|
|
167.1 |
|
|
− |
|
|
− |
|
|
Loss
on retirement of debt |
|
|
76.5 |
|
|
15.7 |
|
|
− |
|
|
Impairment
loss on long-lived assets |
|
|
− |
|
|
16.5 |
|
|
51.4 |
|
|
Impairment
loss on note receivable from related party |
|
|
− |
|
|
21.3 |
|
|
− |
|
|
Amortization
of debt-related discounts/premiums, fair value |
|
|
|
|
|
|
|
|
|
|
|
adjustments
and issue costs, net |
|
|
(21.2 |
) |
|
(24.3 |
) |
|
6.2 |
|
|
Deferred
income, net |
|
|
37.8 |
|
|
4.4 |
|
|
(5.5 |
) |
|
Deferred
expenses, net |
|
|
(22.0 |
) |
|
(33.2 |
) |
|
(20.0 |
) |
|
Tax
benefit from exercise of stock options |
|
|
5.9 |
|
|
0.3 |
|
|
0.3 |
|
|
Other
long-term liabilities |
|
|
10.2 |
|
|
10.8 |
|
|
17.1 |
|
|
Other,
net |
|
|
(6.1 |
) |
|
8.8 |
|
|
(12.1 |
) |
|
Changes
in operating assets and liabilities |
|
|
|
|
|
|
|
|
|
|
|
Accounts
receivable |
|
|
(29.3 |
) |
|
19.8 |
|
|
179.4 |
|
|
Accounts
payable and other current liabilities |
|
|
6.3 |
|
|
6.5 |
|
|
(78.8 |
) |
|
Income
taxes receivable/payable, net |
|
|
1.2 |
|
|
27.8 |
|
|
8.9 |
|
|
Other
current assets |
|
|
(5.3 |
) |
|
7.5 |
|
|
11.5 |
|
|
Net
Cash Provided by Operating Activities |
|
|
604.1 |
|
|
525.4 |
|
|
939.0 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Cash
Flows from Investing Activities |
|
|
|
|
|
|
|
|
|
|
|
Capital
expenditures |
|
|
(127.0 |
) |
|
(493.8 |
) |
|
(141.0 |
) |
|
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 |
|
|
50.4 |
|
|
8.4 |
|
|
88.3 |
|
|
Proceeds
from TODCO offerings |
|
|
683.6 |
|
|
− |
|
|
- |
|
|
Reduction
of cash from the deconsolidation of TODCO |
|
|
(68.6 |
) |
|
− |
|
|
- |
|
|
Joint
ventures and other investments, net |
|
|
10.4 |
|
|
3.3 |
|
|
7.4 |
|
|
Net
Cash Provided by (Used in) Investing Activities |
|
|
548.8 |
|
|
(445.4 |
) |
|
(45.3 |
) |
See
accompanying notes.
TRANSOCEAN
INC. AND SUBSIDIARIES
CONSOLIDATED
STATEMENTS OF CASH FLOWS (Continued)
(In
millions)
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Cash
Flows from Financing Activities |
|
|
|
|
|
|
|
|
Net
repayments under commercial paper program |
|
|
− |
|
|
− |
|
|
(326.4 |
) |
|
Net
borrowings (repayments) on revolving credit agreement |
|
|
(250.0 |
) |
|
250.0 |
|
|
|
|
|
Repayments
on other debt instruments |
|
|
(957.0 |
) |
|
(1,252.7 |
) |
|
(189.3 |
) |
|
Cash
from termination of interest rate swaps |
|
|
− |
|
|
173.5 |
|
|
− |
|
|
Net
proceeds from issuance of ordinary shares under stock-based
|
|
|
|
|
|
|
|
|
|
|
|
compensation
plans |
|
|
30.4 |
|
|
12.8 |
|
|
10.2 |
|
|
Dividends
paid |
|
|
− |
|
|
− |
|
|
(19.1 |
) |
|
Financing
costs |
|
|
− |
|
|
(4.9 |
) |
|
(8.5 |
) |
|
Other,
net |
|
|
1.0 |
|
|
1.1 |
|
|
0.2 |
|
|
Net
Cash Used in Financing Activities |
|
|
(1,175.6 |
) |
|
(820.2 |
) |
|
(532.9 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Net
Increase (Decrease) in Cash and Cash Equivalents |
|
|
(22.7 |
) |
|
(740.2 |
) |
|
360.8 |
|
|
Cash
and Cash Equivalents at Beginning of Period |
|
|
474.0 |
|
|
1,214.2 |
|
|
853.4 |
|
|
Cash
and Cash Equivalents at End of Period |
|
$ |
451.3 |
|
$ |
474.0 |
|
$ |
1,214.2 |
|
See
accompanying notes.
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, 2004, we owned, had partial ownership interests in or operated 93
mobile offshore and barge drilling units. As of this date, our assets consisted
of 32 High-Specification semisubmersibles and drillships (“floaters”), 24 Other
Floaters, 26 Jackup Rigs and 11 Other Rigs.
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 businesses 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
TODCO Offering” and “December TODCO Offering” and, together with the TODCO IPO,
the “TODCO 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 TODCO
Offering and 15.0 million shares of TODCO’s class A common stock (25 percent of
TODCO’s total outstanding shares) in the December TODCO Offering. Prior to the
December TODCO 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 TODCO Offering, we converted
all of our remaining TODCO class B common stock not sold in the TODCO Offerings
into shares of class A common stock. After the TODCO Offerings, we hold 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 have a majority voting interest in TODCO and
no longer consolidate TODCO in our financial statements but account for our
remaining investment using the equity method of accounting. Our current
intention is to dispose of our remaining interest in TODCO, which could be
achieved through a number of possible transactions including additional public
offerings, open market sales, sales to one or more third parties, a spin-off to
our shareholders, split-off offerings to our shareholders that would allow for
the opportunity to exchange our ordinary shares for shares of TODCO’s class A
common stock or a combination of these transactions.
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 influence or control over the
unconsolidated subsidiary. We use the cost method of accounting for investments
in unconsolidated subsidiaries where our ownership is less than 20 percent and
where we do not have significant influence over the unconsolidated subsidiary.
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 are 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. At December 31, 2003 such restricted cash was $12.0 million
and was classified as other assets in the consolidated balance
sheet.
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 trades 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 $16.8 million
and $29.1 million at December 31, 2004 and 2003, 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 $20.3 million and $17.5 million
at December 31, 2004 and 2003, respectively.
Property
and Equipment—Property
and equipment, consisting primarily of offshore drilling rigs and related
equipment, represented 65 percent of our total assets at December 31, 2004. 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 income.
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 life of
four rigs, which had estimated useful lives ranging from 30 to 32 years, to 35
years. We determined 35 years was appropriate for each of these rigs based on
the current contracts these rigs are operating under as well as the additional
life-extending work, upgrades and inspections we have performed on these rigs.
The impact of the life extension of these four rigs was a reduction in
depreciation expense of $4.7 million in the fourth quarter of 2004 and such
reduction is expected to be approximately $12 million in 2005.
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, 2004, we had an asset held for sale in the amount of $5.6 million
that was included in other current assets (See Notes 6 and 27). We had no assets
classified as held for sale at December 31, 2003.
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. Goodwill
resulting from the R&B Falcon merger was allocated to our then two reporting
units, Transocean Drilling and TODCO, at a ratio of 68 percent and 32 percent,
respectively. The allocation was determined based on the percentage of each
reporting unit’s assets at fair value to the total fair value of assets acquired
in the R&B Falcon merger. The fair value was determined from a third party
valuation. Goodwill resulting from previous mergers was allocated entirely to
the Transocean Drilling reporting unit.
During
the first quarter of 2002, we implemented SFAS 142 and performed the initial
test of impairment of goodwill on our two reporting units. The test was applied
utilizing the estimated fair value of the reporting units as of January 1, 2002
determined based on a combination of each reporting unit’s discounted cash flows
and publicly traded company multiples and acquisition multiples of comparable
businesses. There was no goodwill impairment for the Transocean Drilling
reporting unit. However, because of deterioration in market conditions that
affected the TODCO reporting unit since the completion of the R&B Falcon
merger, a $1,363.7 million ($4.27 per diluted share) impairment of goodwill was
recognized as a cumulative effect of a change in accounting principle in the
first quarter of 2002.
During
the fourth quarter of 2002, we performed our annual test of goodwill impairment
as of October 1. Due to a general decline in market conditions, we recorded a
non-cash impairment charge of $2,876.0 million ($9.01 per diluted share), of
which $2,494.1 million and $381.9 million related to the Transocean Drilling and
TODCO reporting units, respectively.
During
the fourth quarter of 2004 and 2003, we performed our annual test of goodwill
impairment as of October 1 with no impairment indicated for either of the years
ended December 31, 2004 and 2003.
Our
goodwill balance and changes in the carrying amount of goodwill are as follows
(in millions):
| |
|
Balance
at
January
1, 2004 |
|
Other
(a) |
|
Balance
at
December
31, 2004 |
| |
|
|
|
|
|
|
|
Transocean
Drilling |
|
$2,230.8 |
|
$21.1 |
|
$2,251.9 |
| ______________________ |
|
|
|
|
|
|
|
(a)
Primarily represents net adjustments during 2004 of income tax-related
pre-acquisition contingencies. |
Impairment
of Long-Lived Assets—The
carrying value of long-lived assets, principally property and equipment, is
reviewed for potential impairment when events or changes in circumstances
indicate that the carrying amount of such assets may not be recoverable. For
property and equipment held for use, the determination of recoverability is made
based upon the estimated undiscounted future net cash flows of the related asset
or group of assets being evaluated. Property and equipment held for sale are
recorded at the lower of net book value or fair value. 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. No loss
contracts were included in the results of operations for the years ended
December 31, 2004, 2003 and 2002. 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
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 Translation—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 $0.4 million, $(3.5) million, and $(0.5) million for the
years ended December 31, 2004, 2003 and 2002, 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 15.
Stock-Based
Compensation—Through
December 31, 2002 and in accordance with the provisions of SFAS 123,
Accounting
for Stock-Based Compensation, we had
elected to follow Accounting Principles Board Opinion (“APB”) 25, Accounting
for Stock Issued to Employees, and
related interpretations in accounting for our employee stock-based compensation
plans. Effective January 1, 2003, we adopted the fair value recognition
provisions of SFAS 123 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 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, will continue to be accounted
for under the recognition and measurement provisions of APB 25 (see
“―New Accounting Pronouncements”). As a
result of the adoption of SFAS 123, we recorded higher compensation expense of
$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
and the ESPP 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, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Net
Income (Loss) as Reported |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
(3,731.9 |
) |
|
Add
back: Stock-based compensation expense included in reported
|
|
|
|
|
|
|
|
|
|
|
|
net
income (loss), net of related tax effects |
|
|
18.2 |
|
|
4.6 |
|
|
2.8 |
|
|
Deduct:
Total stock-based compensation expense determined under
the |
|
|
|
|
|
|
|
|
|
|
|
fair
value method for all awards, net of related tax effects |
|
|
|
|
|
|
|
|
|
|
|
Long-Term
Incentive Plan |
|
|
(22.4 |
) |
|
(18.2 |
) |
|
(23.9 |
) |
|
ESPP |
|
|
(2.6 |
) |
|
(2.5 |
) |
|
(2.2 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Pro
Forma Net Income (Loss) |
|
$ |
145.4 |
|
$ |
3.1 |
|
$ |
(3,755.2 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Basic
Earnings (Loss) Per Share |
|
|
|
|
|
|
|
|
|
|
|
As
Reported |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(11.69 |
) |
|
Pro
Forma |
|
|
0.45 |
|
|
0.01 |
|
|
(11.77 |
) |
| |
|
|
|
|
|
|
|
|
|
|
|
Diluted
Earnings (Loss) Per Share |
|
|
|
|
|
|
|
|
|
|
|
As
Reported |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(11.69 |
) |
|
Pro
Forma |
|
|
0.45 |
|
|
0.01 |
|
|
(11.77 |
) |
The above
pro forma amounts are not indicative of future pro forma results. The fair value
of each option grant under our long-term incentive plan was estimated on the
date of grant using the Black-Scholes option pricing model with the following
weighted-average assumptions used:
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
|
Dividend
yield |
|
|
- |
|
|
- |
|
|
- |
|
|
Expected
price volatility range |
|
|
38%-42 |
% |
|
39%-45 |
% |
|
49%-51 |
% |
|
Risk-free
interest rate range |
|
|
2.59%-3.71 |
% |
|
1.94%-3.16 |
% |
|
2.79%-4.11 |
% |
|
Expected
life of options (in years) |
|
|
4.30 |
|
|
4.21 |
|
|
3.84 |
|
|
Weighted-average
fair value of options granted |
|
$ |
10.65 |
|
$ |
7.13 |
|
$ |
12.25 |
|
The fair
value of each option grant under the ESPP was estimated using the following
weighted-average assumptions:
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
|
Dividend
yield |
|
|
- |
|
|
- |
|
|
- |
|
|
Expected
price volatility |
|
|
27 |
% |
|
41 |
% |
|
45 |
% |
|
Risk-free
interest rate |
|
|
1.19 |
% |
|
1.09 |
% |
|
2.14 |
% |
|
Expected
life of options |
|
|
Less
than one year |
|
|
Less
than one year |
|
|
Less
than one year |
|
|
Weighted-average
fair value of options granted |
|
$ |
4.10 |
|
$ |
4.69 |
|
$ |
4.76 |
|
New
Accounting Pronouncements— In
April 2004, the FASB issued FASB Staff Position (“FSP”) 129-1, Disclosure
of Information about Capital Structure,
Relating
to Contingently Convertible Securities, which
applies to all contingently convertible securities and became effective the date
of issue. The FSP requires disclosure of the nature of the contingency and the
potential impact of conversion on the financial statements, particularly the
impact on earnings per share, and whether the securities have been included in
the entity’s calculation of diluted earnings per share. The implementation of
this FSP did not have an effect on our consolidated financial statements and
related notes thereto as our disclosures are in accordance with the disclosure
requirements as stated in this FSP.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
September 2004, the Emerging Issues Task Force (“EITF”) of the FASB reached a
consensus on Issue No. 04-08, The
Effect of Contingently Convertible Instruments on Diluted Earnings per Share
(“EITF
04-08”), which is effective for reporting periods ending after December 15,
2004. Contingently convertible instruments within the scope of EITF 04-08 are
instruments that contain conversion features that are contingently convertible
or exercisable based on (a) a market price trigger or (b) multiple contingencies
if one of the contingencies is a market price trigger for which the instrument
may be converted or share settled based on meeting a specified market condition.
EITF 04-08 requires companies to include shares issuable under convertible
instruments in diluted earnings per share computations (if dilutive) regardless
of whether the market price trigger (or other contingent feature) has been met.
In addition, prior period earnings per share amounts presented for comparative
purposes must be restated. We adopted EITF 04-08 as of December 31, 2004 and the
adoption did not have an effect on our earnings per share for the years ended
December 31, 2004, 2003 and 2002.
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. SFAS
123(R) requires adoption no later than July 1, 2005.
SFAS
123(R) permits adoption using one of two methods: (i) a modified prospective
method in which compensation costs are recognized beginning with the effective
date based on the requirements of SFAS 123(R) (a) for all share-based payments
granted after the effective date and (b) for all awards granted to employees
prior to the effective date of SFAS 123(R) that remain unvested on the effective
date or (ii) a modified retrospective method, which includes the requirements of
the modified prospective method but also permits entities to restate based on
the amounts previously recognized under SFAS 123 for purposes of pro forma
disclosures either (a) all prior periods presented or (b) prior interim periods
of the year of adoption.
Although
we will adopt SFAS 123(R) effective July 1, 2005, we have not determined which
method we will use. We adopted the fair-value-based method of
accounting for share-based payments effective January 1, 2003 using the modified
prospective method as described in SFAS 148, Accounting
for Stock-Based Compensation―Transition and Disclosure. While
we currently use the Black-Scholes formula to estimate the value of stock
options granted to employees, which is an acceptable share-based award valuation
model, we may choose some other model that is also acceptable in determining
fair value of stock awards upon adoption of SFAS 123(R). Because SFAS 123(R)
must be applied to unvested awards granted and accounted for under APB 25, any
additional compensation costs not previously recognized under SFAS 123 will be
recognized under SFAS 123(R). Our unvested APB 25 options will vest in the third
quarter of 2005. If we adopt SFAS 123(R) using the modified prospective method,
the impact would not be material to our consolidated financial position, results
of operations or cash flows. If we adopt using the modified retrospective
method, the impact of those amounts would approximate the amounts described in
our pro forma net income and earnings per share disclosure (see “―Stock
Compensation Expense”). 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 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
recognized operating cash flows related to the tax deduction benefits of $5.9
million, $0.3 million and $0.3 million in 2004, 2003 and 2002,
respectively.
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, 2004, 2003
and 2002, 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, 2001 |
|
$ |
3.9 |
|
$ |
(0.6 |
) |
$ |
(5.6 |
) |
$ |
- |
|
$ |
(2.3 |
) |
|
Other
comprehensive income (loss) |
|
|
(0.3 |
) |
|
- |
|
|
3.6 |
|
|
(32.5 |
) |
|
(29.2 |
) |
|
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 |
) |
Deepwater
Drilling L.L.C. (“DD LLC”), a previously unconsolidated subsidiary in which we
had a 50 percent ownership interest, entered into interest rate swaps with
aggregate market values netting to a $6.7 million liability at December 31,
2002. Our interest in these swaps was recorded as other comprehensive loss
related to an unconsolidated joint venture. These swaps expired in October 2003
(see Note 10).
Note
4—TODCO Offerings and Deconsolidation
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.
We
entered into various agreements with TODCO to set forth our respective rights
and obligations relating to our businesses and to effect the separation of our
two companies. These agreements included a master separation agreement, tax
sharing agreement, employee matters agreement, transition services agreement and
registration rights 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, 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, taking into account prudent and feasible tax
planning strategies as required by SFAS 109, Accounting
for Income Taxes. 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 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. TODCO
amortized to compensation expense $4.6 million ($0.01 per Transocean’s diluted
share), which had no tax effect, subsequent to the TODCO IPO and prior to our
deconsolidation of TODCO from our consolidated financial statements 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 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
In
September 2004, we completed the September TODCO 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
($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 this offering.
In
December 2004, we completed the December TODCO 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 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 this offering. In connection with this offering, we
converted all of our remaining 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 outstanding voting interest in
TODCO is proportionate to our ownership interest. 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.
As of
December 31, 2004, we held a 22 percent interest in TODCO, represented by 13.3
million shares of class A common stock. We deconsolidated TODCO from our
consolidated statements of operations and balance sheet effective December 17,
2004 and subsequently accounted for our investment in TODCO under the equity
method of accounting (see Note 20).
Under the
tax sharing agreement entered into between us and TODCO at the time of the TODCO
IPO, 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, 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 a majority voting interest, TODCO is no
longer included 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 based on the filing of TODCO’s tax
returns.
Note
5—Capital Expenditures and Other Asset Acquisitions
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.
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.
Capital
expenditures totaled $141.0 million during the year ended December 31, 2002 and
related to our existing fleet and corporate infrastructure. A substantial
majority of the capital expenditures in 2002 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 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 March
2004, we entered into an agreement to sell two semisubmersible rigs, the
Sedco
600 and
Sedco
602, for net
proceeds of approximately $52.7 million in connection with our efforts to
dispose of non-strategic assets in our Transocean Drilling segment. 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. At
December 31, 2004, the Sedco
600 was
classified as an asset held for sale in the amount of $5.6 million and was
included in other current assets in our consolidated balance sheet. See Notes 2
and 27.
During
the year ended December 31, 2004, we settled insurance claims and sold marine
support vessels and certain other assets for net proceeds of $22.4 million. We
recorded net gains of $4.2 million ($3.3 million, or $0.01 per diluted share,
net of tax) in our Transocean Drilling segment and $6.0 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 other
assets for net proceeds of approximately $8.4 million and recorded net gains of
$4.6 million ($4.0 million, or $0.01 per diluted share, net of tax) in our
Transocean Drilling segment and $0.9 million ($0.6 million, net of tax) in our
TODCO segment.
During
the year ended December 31, 2002, we completed the sale of the jackup rig
RBF
209 and two
semisubmersible rigs, the Transocean
96 and
Transocean
97, for net
proceeds of $49.4 million and recognized net losses of $0.4 million ($0.3
million, net of tax) in our Transocean Drilling segment.
During
the year ended December 31, 2002, we settled an insurance claim and sold certain
other assets for net proceeds of approximately $38.9 million and recorded net
gains of $3.1 million ($2.8 million, or $0.01 per diluted share, net of tax) and
$1.0 million ($0.6 million, net of tax) in our Transocean Drilling and TODCO
segments, respectively.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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.
During
the year ended December 31, 2002, we recorded non-cash impairment charges of
$34.0 million ($22.2 million, or $0.07 per diluted share, net of tax), in our
Transocean Drilling segment associated with assets held for sale and assets
reclassified from held for sale to held and used. The determination of fair
market value was based on an offer from a potential buyer, in the case of the
assets held for sale, and third party valuations, in the case of the
reclassification of assets to held and used.
During
the year ended December 31, 2002, we recorded non-cash impairment charges of
$17.4 million ($11.3 million, or $0.04 per diluted share, net of tax), in our
TODCO segment associated with assets held for sale and assets reclassified from
held for sale to held and used. The determination of fair market value was based
on an offer from a potential buyer, in the case of the assets held for sale, and
third party valuations, in the case of the reclassification of assets to held
and used.
During
the fourth quarter of 2002, we performed our annual test of goodwill impairment
as of October 1, 2002. As a result of that test and a general decline in market
conditions, we recorded non-cash impairments of $2,494.1 million ($7.82 per
diluted share) and $381.9 million ($1.20 per diluted share), which had no tax
effect, in our Transocean Drilling and TODCO segments, respectively. See Note
2.
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, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
6.75%
Senior Notes, due April 2005 |
|
$ |
- |
|
$ |
361.2 |
|
|
7.31%
Nautilus Class A1 Amortizing Notes - final maturity May
2005 |
|
|
19.4 |
|
|
63.6 |
|
|
6.95%
Senior Notes, due April 2008 |
|
|
263.1 |
|
|
269.5 |
|
|
9.5%
Senior Notes, due December 2008 |
|
|
- |
|
|
357.3 |
|
|
$800
Million Revolving Credit Agreement - final maturity December
2008 |
|
|
- |
|
|
250.0 |
|
|
6.625%
Notes, due April 2011 |
|
|
785.7 |
|
|
797.3 |
|
|
7.375%
Senior Notes, due April 2018 |
|
|
246.9 |
|
|
250.4 |
|
|
Zero
Coupon Convertible Debentures, due May 2020 (put options exercisable
May
2008 and May 2013) |
|
|
17.0 |
|
|
16.5 |
|
|
1.5%
Convertible Debentures, due May 2021 (put options exercisable May 2006,
May
2011 and May 2016) |
|
|
400.0 |
|
|
400.0 |
|
|
8%
Debentures, due April 2027 |
|
|
56.8 |
|
|
198.1 |
|
|
7.45%
Notes, due April 2027 (put options exercisable April 2007) |
|
|
95.0 |
|
|
94.8 |
|
|
7.5%
Notes, due April 2031 |
|
|
597.6 |
|
|
597.5 |
|
|
Other |
|
|
- |
|
|
1.9 |
|
|
Total
Debt |
|
|
2,481.5 |
|
|
3,658.1 |
|
|
Less
Debt Due Within One Year |
|
|
19.4 |
|
|
45.8 |
|
|
Total
Long-Term Debt |
|
$ |
2,462.1 |
|
$ |
3,612.3 |
|
The
scheduled maturity of our debt, at face value, assumes the bondholders exercise
their options 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, and is as follows (in millions):
| |
|
Years
ending |
|
| |
|
December
31, |
|
| |
|
|
|
|
|
2005 |
|
$ |
19.6 |
|
|
2006 |
|
|
400.0 |
|
|
2007 |
|
|
100.0 |
|
|
2008 |
|
|
266.8 |
|
|
2009 |
|
|
- |
|
|
Thereafter |
|
|
1,603.8 |
|
|
Total |
|
$ |
2,390.2 |
|
Commercial
Paper Program¾We have a
revolving credit agreement, described below, which, together with previous
revolving credit agreements, provided liquidity for commercial paper borrowings
made under the commercial paper program during 2003. Because we believe our
current cash balances, the revolving credit agreement described below and
operating cash flow provide us with adequate liquidity, we terminated our
commercial paper program during the first quarter of 2004.
Revolving
Credit Agreement—We are
party to an $800.0 million five-year revolving credit agreement (the “Revolving
Credit Agreement”) dated December 16, 2003. The Revolving Credit Agreement bears
interest, at our option, at a base rate or London Interbank Offered Rate
(“LIBOR”) plus a margin that can vary from 0.35 percent to 0.95 percent
depending on our non-credit enhanced senior unsecured public debt rating. At
December 31, 2004, the applicable margin was 0.50 percent. A facility fee
varying from 0.075 percent to 0.225 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. At December 31, 2004, the applicable facility fee was 0.125 percent. A
utilization fee of 0.125 percent is payable if amounts outstanding under the
Revolving Credit Agreement are greater than $264.0 million. At December 31,
2004, no amount was outstanding under the Revolving Credit Agreement.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
Revolving Credit Agreement requires compliance with various covenants and
provisions customary for agreements of this nature, including an earnings before
interest, taxes, depreciation and amortization (“EBITDA”) to interest coverage
ratio, as defined by the Revolving Credit Agreement, of not less than three to
one, a debt to total tangible capital ratio, as defined by the credit agreement,
of not greater than 50 percent, and limitations on creating liens, incurring
debt, transactions with affiliates, sale/leaseback transactions and mergers and
sale of substantially all assets.
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 (see “—Retired, Redeemed and Repurchased Debt”). For
2003, these notes are combined with our notes of the corresponding series issued
by us in the above table. At December 31, 2004, $247.8 million and $246.5
million principal amount of our 6.95% and 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). In connection with the Exchange Offer,
TODCO paid $8.3 million in consent payments to holders of TODCO’s notes whose
notes were exchanged. The consent payments are being amortized as an increase to
interest expense over the remaining term of the respective notes and such
amortization was approximately $0.8 million, $1.3 million and $1.3 million in
the years ended December 31, 2004, 2003 and 2002, respectively. The 6.95% and
7.375% Senior Notes are redeemable at our option at a make-whole premium (see
Note 27).
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, 2004, $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, 2004, $26.4 million
face value of these notes was outstanding with a discounted value of $17.0
million. Should all of the debentures be put to us in May 2008, the debentures
will have a discounted value of $19.0 million.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
8%
Debentures—In April
1997, we issued $200.0 million aggregate principal amount of 8% Debentures due
April 15, 2027, which are redeemable, at any time, at our option at a make-whole
premium (see “—Retired, Redeemed and Repurchased Debt”).
Nautilus
Class A1 and A2 Notes—In
August 1999, one of our subsidiaries completed a $250.0 million project
financing for the construction of the Deepwater
Nautilus that
consisted of a $200.0 million, 7.31% Class A1 amortizing note with a final
maturity in May 2005 and a $50.0 million, 9.41% Class A2 note maturing in May
2005 (see “—Retired, Redeemed and Repurchased Debt”). These notes were recorded
at fair value on January 31, 2001 as part of the R&B Falcon merger. The
Nautilus Class A1 Note is collateralized by the Deepwater
Nautilus, which
had a carrying value of $286.7 million at December 31, 2004, and the rig's
drilling contract revenues. At December 31, 2004, approximately $19.6 million
principal amount was outstanding on the Nautilus Class A1 Note.
Retired,
Redeemed and Repurchased Debt—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
December 2004, the 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 aggregate principal amounts outstanding
of $7.7 million, $2.2 million, $10.2 million and $3.5 million, respectively. See
Note 4.
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 ($0.01 per diluted share), which had no tax
effect, in the fourth quarter of 2004 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 TODCO 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. We recognized a loss on the
redemption of debt of $28.1 million ($0.09 per share), which had no tax effect,
in the first quarter of 2004 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
December 2003, we repaid all of the $87.1 million principal amount outstanding
9.125% Senior Notes, of which $10.2 million principal amount outstanding was the
obligation of TODCO, plus accrued and unpaid interest, in accordance with their
scheduled maturity. We funded the repayment from existing cash balances.
In
December 2003, we repaid the remaining $187.5 million principal amount
outstanding under a prior term loan agreement, plus accrued and unpaid interest,
of which $150.0 million related to the early retirement of this debt. The term
loan agreement was terminated in conjunction with this repayment. We funded the
repayment from existing cash balances.
In May
2003, we repurchased and retired all of the $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
In April
2003, we repaid the entire $239.5 million aggregate principal amount outstanding
6.5% Senior Notes, of which $5.0 million principal amount outstanding was the
obligation of TODCO, plus accrued and unpaid interest, in accordance with their
scheduled maturity. We funded the repayment from existing cash
balances.
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 and with purchases from foreign suppliers. We use a variety
of techniques to minimize exposure to foreign exchange risk, including customer
contract payment terms and 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, 2004 and 2003, 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, 2004 and 2003.
See Note 10.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
market values of any open swap transactions would be carried on our consolidated
balance sheet as an asset or liability depending on the movement of interest
rates after the transaction is entered into and depending on the security being
hedged.
Should a
counterparty default at a time in which the market value of the swap with that
counterparty is classified as an asset in our consolidated balance sheet, we may
be unable to collect on that asset. To mitigate such risk of failure, we enter
into swap transactions with a diverse group of high-quality
institutions.
Credit
Risk—Financial
instruments that potentially subject us to concentrations of credit risk are
primarily cash and cash equivalents and trade receivables. It is our practice to
place our cash and cash equivalents in time deposits at commercial banks with
high credit ratings or mutual funds, which invest exclusively in high quality
money market instruments. In foreign locations, local financial institutions are
generally utilized for local currency needs. We limit the amount of exposure to
any one institution and do not believe we are exposed to any significant credit
risk.
We derive
the majority of our revenue from services to international oil companies and
government-owned and government-controlled oil companies. Receivables are
dispersed in various countries. See Note 21. 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, 2004, we had approximately 8,400 employees and we also utilized
approximately 2,200 persons through contract labor providers. As of such date,
approximately 15 percent of our employees and contract labor worldwide worked
under collective bargaining agreements, most of whom worked in Norway, U.K. and
Nigeria. Of these represented individuals, 100 percent are working under
agreements that are subject to salary negotiation in 2005.
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 margin of 50 basis points, 246 basis points, 171 basis points and
413 basis points, respectively, which were 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 swaps and associated fair value hedges with respect
to our 6.75% Senior Notes due April 2005, 6.95% Senior Notes due April 2008 and
9.5% Senior Notes due December 2008. In March 2003, we terminated swaps with
respect to our 6.625% Notes. As a result of these terminations, we received cash
proceeds, net of accrued interest, of $173.5 million that had been recognized in
connection with the associated fair value hedges as a fair value adjustment to
the underlying long-term debt in our consolidated balance sheet and the fair
value adjustment is being amortized as a reduction to interest expense over the
remaining life of the underlying debt. During the years ended December 31, 2004
and 2003, such reduction amounted to $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 9.5% Senior Notes in March 2004 and 6.75% Senior Notes in
October 2004, we recognized $25.5 million ($0.08 per diluted share) of the
unamortized fair value adjustment as a reduction to our loss on redemption of
debt (see Notes 8 and 27). There were no tax effects related to these
reductions.
At
December 31, 2004 and 2003, we had no outstanding interest rate swaps.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
DD LLC, a
previously unconsolidated joint venture in which we had a 50 percent ownership
interest, entered into interest rate swaps in August 1998 that expired in
October 2003. Our interest in these swaps was included in accumulated other
comprehensive income, net of tax, with corresponding reductions to deferred
income taxes and investments in and advances to unconsolidated
subsidiaries.
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, 2004 |
|
December
31, 2003 |
|
| |
|
Carrying
Amount |
|
Fair
Value |
|
Carrying
Amount |
|
Fair
Value |
|
| |
|
(in
millions) |
|
(in
millions) |
|
|
Cash
and cash equivalents |
|
$ |
451.3 |
|
$ |
451.3 |
|
$ |
474.0 |
|
$ |
474.0 |
|
|
Trade
receivables |
|
|
426.5 |
|
|
426.5 |
|
|
435.3 |
|
|
435.3 |
|
|
Debt |
|
|
2,481.5 |
|
|
2,702.5 |
|
|
3,658.1 |
|
|
3,849.8 |
|
Note
12—Other
Current Liabilities
Other
current liabilities are comprised of the following (in millions):
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Accrued
payroll and employee benefits |
|
$ |
98.1 |
|
$ |
133.0 |
|
|
Deferred
income |
|
|
53.2 |
|
|
35.7 |
|
|
Accrued
interest |
|
|
30.2 |
|
|
39.2 |
|
|
Accrued
taxes, other than income |
|
|
14.4 |
|
|
12.7 |
|
|
Reserves
for contingent liabilities |
|
|
1.2 |
|
|
17.5 |
|
|
Other |
|
|
15.9 |
|
|
23.9 |
|
|
Total
Other Current Liabilities |
|
$ |
213.0 |
|
$ |
262.0 |
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
13—Other
Long-Term Liabilities
Other
long-term liabilities are comprised of the following (in millions):
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Reserves
for contingent liabilities |
|
$ |
194.9 |
|
$ |
170.3 |
|
|
Accrued
pension and early retirement |
|
|
54.0 |
|
|
45.0 |
|
|
Accrued
retiree life insurance and medical benefits |
|
|
35.4 |
|
|
34.8 |
|
|
Deferred
income |
|
|
19.1 |
|
|
8.8 |
|
|
Other |
|
|
41.8 |
|
|
40.5 |
|
|
Total
Other Long-Term Liabilities |
|
$ |
345.2 |
|
$ |
299.4 |
|
Note
14—Supplementary
Cash Flow Information
Non-cash
investing activities for the years ended December 31, 2004, 2003 and 2002
included $9.7 million, $8.9 million and $7.9 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.
In 2002,
we reclassified the remaining assets that had not been disposed of from assets
held for sale to property and equipment based on management's assessment that
these assets no longer met the held for sale criteria under SFAS 144. As a
result, $55.0 million was reflected as an increase in property and equipment
with a corresponding decrease in other assets.
Cash
payments for interest were $201.2 million, $219.0 million and $210.5 million for
the years ended December 31, 2004, 2003 and 2002, respectively. Cash payments
for income taxes, net, were $75.1 million, $73.4 million and $91.1 million for
the years ended December 31, 2004, 2003 and 2002, respectively.
Note
15—Income
Taxes
Transocean
Inc., a Cayman Islands company, is not subject to income tax in the Cayman
Islands. 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 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.
As a
result of changes in our estimates related to the ultimate disposition of
certain pre-acquisition tax contingencies arising prior to our merger with Sedco
Forex Holdings Limited (“Sedco Forex”) effective December 31, 1999, we recorded
$21.1 million of additional goodwill during the year ended December 31,
2004.
The
components of the provision (benefit) for income taxes are as follows (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Current
provision |
|
$ |
73.2 |
|
$ |
101.5 |
|
$ |
101.4 |
|
|
Deferred
provision (benefit) |
|
|
18.1 |
|
|
(98.5 |
) |
|
(224.4 |
) |
|
Income
tax provision (benefit) before cumulative effect of changes in accounting
principles |
|
$ |
91.3 |
|
$ |
3.0 |
|
$ |
(123.0 |
) |
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, |
|
| |
|
2004 |
|
2003 |
|
Deferred
Tax Assets-Current
|
|
|
|
|
|
|
|
|
Accrued
personnel taxes |
|
$ |
0.6 |
|
$ |
1.1 |
|
|
Accrued
workers' compensation insurance |
|
|
0.5 |
|
|
6.8 |
|
|
Incentive
compensation and other accruals |
|
|
7.1 |
|
|
4.1 |
|
|
Insurance
accruals |
|
|
9.1 |
|
|
14.3 |
|
|
Unearned
income and miscellaneous reserves |
|
|
5.0 |
|
|
18.2 |
|
|
Total
Current Deferred Tax Assets |
|
|
22.3 |
|
|
44.5 |
|
| |
|
|
|
|
|
|
|
|
Deferred
Tax Liabilities-Current
|
|
|
|
|
|
|
|
|
Deferred
expenses |
|
|
(3.3 |
) |
|
(3.5 |
) |
|
Total
Current Deferred Tax Liabilities |
|
|
(3.3 |
) |
|
(3.5 |
) |
|
Net
Current Deferred Tax Assets |
|
$ |
19.0 |
|
$ |
41.0 |
|
| |
|
|
|
|
|
|
|
|
Deferred
Tax Assets-Noncurrent
(Non-U.S.) |
|
|
|
|
|
|
|
|
Net
operating loss carryforwards |
|
$ |
60.6 |
|
$ |
55.1 |
|
|
Valuation
allowance for noncurrent deferred tax assets |
|
|
(16.8 |
) |
|
(26.9 |
) |
|
Net
Noncurrent Deferred Tax Assets |
|
$ |
43.8 |
|
$ |
28.2 |
|
| |
|
|
|
|
|
|
|
|
Deferred
Tax Assets-Noncurrent
|
|
|
|
|
|
|
|
|
Net
operating loss and other miscellaneous carryforwards |
|
$ |
60.4 |
|
$ |
619.1 |
|
|
Tax
credit carryforwards |
|
|
166.7 |
|
|
259.2 |
|
|
Retirement
and benefit plan accruals |
|
|
3.8 |
|
|
3.8 |
|
|
Other
accruals |
|
|
15.0 |
|
|
35.6 |
|
|
Deferred
income and other |
|
|
2.2 |
|
|
0.7 |
|
|
Valuation
allowance for noncurrent deferred tax assets |
|
|
(98.5 |
) |
|
(154.9 |
) |
|
Total
Noncurrent Deferred Tax Assets |
|
|
149.6 |
|
|
763.5 |
|
| |
|
|
|
|
|
|
|
|
Deferred
Tax Liabilities-Noncurrent
|
|
|
|
|
|
|
|
|
Depreciation
and amortization |
|
|
(255.8 |
) |
|
(689.0 |
) |
|
Investment
in subsidiaries |
|
|
(14.2 |
) |
|
(109.3 |
) |
|
Other |
|
|
(3.7 |
) |
|
(8.0 |
) |
|
Total
Noncurrent Deferred Tax Liabilities |
|
|
(273.7 |
) |
|
(806.3 |
) |
|
Net
Noncurrent Deferred Tax Liabilities |
|
$ |
(124.1 |
) |
$ |
(42.8 |
) |
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. 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
provided a valuation allowance to offset deferred tax assets on net operating
losses incurred during the year in certain jurisdictions where, in the opinion
of management, it is more likely than not that the financial statement benefit
of these losses would not be realized. We have also provided a valuation
allowance for foreign tax credit carryforwards reflecting the possible
expiration of these benefits prior to their utilization. At December 31, 2002,
the valuation allowance was $112.3 million. The valuation allowance for
non-current deferred tax assets decreased $56.4 million and increased $42.6
million during the years ended December 31, 2004 and 2003,
respectively.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We have
not provided for U.S. deferred taxes on the unremitted earnings of our
U.S. subsidiaries and certain foreign subsidiaries that are permanently
reinvested. Should we make a distribution from the unremitted earnings of these
subsidiaries, we could be required to record additional taxes. At the current
time, a determination of the amount of unrecognized deferred tax liability is
not practical.
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 adverse
effect on our consolidated financial position, results of operations and 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 $31.0 million
against the estimated deferred tax assets of TODCO in excess of its deferred tax
liabilities, 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. The ultimate allocation of tax benefits between TODCO and
our other U.S. subsidiaries will occur in 2005 upon the filing of our 2004 U.S.
consolidated federal income tax return. This final allocation of tax
benefits could impact our effective tax rate for 2005.
As a
result of our deconsolidation of TODCO (see Note 4), our deferred tax assets and
liabilities at December 31, 2004 reflect the removal of TODCO deferred tax asset
and liability balances, including valuation allowances, from our consolidated
balances (see Note 14).
Our U.S.
net operating loss carryforwards expire between 2020 and 2024. The tax effect of
the U.S. net operating loss carryforwards, net of valuation allowances of $13.4
million, was $47.0 million at December 31, 2004. Our U.K. net operating loss
carryforwards do not expire. The tax effect of the U.K. net operating loss
carryforwards, net of valuation allowances of $16.8 million, was $43.8 million
at December 31, 2004, which we expect to utilize through future earnings. In
2004, we decreased the valuation allowance on our U.K. net operating loss
carryforwards by $10.1 million as a result of agreements with the U.K. Inland
Revenue and revised estimates of future taxable income and taking into account
tax planning strategies as required by SFAS 109. Our U.S. foreign tax credit
carryforwards of $80.6 million, which is net of valuation allowances of $85.1
million, will expire between 2009 and 2014.
In June
2003, we recorded a $14.6 million ($0.04 per diluted share) foreign tax benefit
attributable to the favorable resolution of a non-U.S. income tax
liability.
During
2002, we recorded a $175.7 million ($0.55 per diluted share) tax benefit
attributable to the restructuring of certain non-U.S. operations. As a result of
the restructuring, previously unrecognized losses were offset against deferred
gains, resulting in a reduction of noncurrent deferred taxes
payable.
Transocean
Inc., a Cayman Islands company, is not subject to income taxes in the Cayman
Islands. For the three years ended December 31, 2004, 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 an 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 or income, or computed on 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. Therefore, under present law there will
be no Cayman Islands tax consequences affecting distributions.
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, including treaties
that the U.S. has with other nations. A material change in these tax laws,
treaties or regulations, including those in and involving the U.S., could result
in a higher 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 Act
contains provisions which apply to certain companies that undertook a
transaction commonly known as an inversion after a specified date. Because our
reorganization as a Cayman Islands company in May 1999 occurred prior to the
effective dates specified in the Act, we do not believe there should be any
adverse impact to us from the inversion provisions of the Act. Additionally, the
tax treaty between the U.S. and Barbados was recently amended. We do not expect
the amendment 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 Act
also creates a temporary incentive for U.S. corporations to repatriate
accumulated income earned abroad by providing, in some cases, an 85 percent
dividends received deduction for dividends paid by certain non-U.S. subsidiaries
of the U.S. corporation (“controlled foreign corporations”) to the U.S.
corporation. The deduction is subject to a number of limitations and,
uncertainty currently remains as to how to interpret numerous provisions of the
Act. Further, several requirements must be met in order to qualify for the
deduction. While we are still in the process of analyzing whether any of
our U.S. subsidiaries could qualify for the deduction, it is reasonably possible
that under the repatriation provisions of the Act certain of our non-U.S.
subsidiaries may repatriate to our U.S. subsidiaries some amount of earnings up
to an estimated maximum amount of $150 million. As we have provided
deferred U.S. taxes on the unremitted earnings of these controlled foreign
corporations, this deduction, should we qualify, could reduce our tax expense in
2005 by an estimated maximum amount of $40 million. The ultimate amounts
could be much less or even zero.
The Act
further provides for a tax deduction for qualified production activities.
Under the guidance of FASB Staff Position No. 109-1, Application
of FASB Statement No. 109, “Accounting for Income Taxes,” to the Tax Deduction
on Qualified Production Activities Provided by the American Jobs Creation Act of
2004, the
deduction will be treated as a “special deduction” as described in SFAS 109 and
not as a reduction in the tax rate. As such, the special deduction has no
effect on deferred tax assets and liabilities existing on the date of
enactment. Rather, the impact of this deduction will be reported in the
period in which the deduction is claimed on our tax return. We are still
reviewing whether any of our operations would qualify for this deduction.
Further, because of losses carried forward by the applicable subsidiaries, this
deduction is not expected to have any impact on our tax provision in
2005.
Our
income tax returns are subject to review and examination in the various
jurisdictions in which we operate. In October 2004, we received from the U.S.
Internal Revenue Service (“IRS”) examination reports setting forth proposed
changes to the U.S. federal income tax reported for the period 1999-2000. The
proposed changes total approximately $195 million, exclusive of interest. While
we have agreed to certain non-material adjustments, we believe our returns are
materially correct as filed and intend to defend ourselves vigorously. The IRS
has also notified us of its intent to audit our 2002 and 2003 tax years. No
examination report has been received at this time.
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. Based on these
inquiries, we believe the Norwegian authorities are contemplating a tax
assessment on the dividend of approximately $106 million, 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 current consolidated financial
position, results of operations and cash flows.
In
addition, other tax authorities have examined the amounts of income and expense
subject to tax in their jurisdiction for prior periods. We are currently
contesting various non-U.S. assessments that have been asserted and would expect
to contest any future U.S. or non-U.S. assessments. 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 current consolidated financial position, results of operations and
cash flows.
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.
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.
As of December 31, 2004, TODCO is estimated to have approximately $375 million
of pre-closing tax benefits subject to its obligation to reimburse Transocean
Holdings, after elimination of those benefits TODCO expects to use in connection
with its separation from Transocean Holdings. The ultimate amount will depend on
many factors, including the ultimate allocation of tax benefits between TODCO
and our other subsidiaries under applicable law and taxable income for calendar
year 2004. Income taxes and income tax benefits accruing after the closing of
the TODCO IPO, to the extent attributable to Transocean Holdings or its
affiliates (other than TODCO or its subsidiaries), generally will be for the
account of Transocean Holdings and, to the extent attributable to TODCO or its
subsidiaries, generally will be for the account of TODCO. However, TODCO will be
responsible for all taxes, other than income taxes, attributable to the TODCO
business, whether accruing before, on or after the closing of the TODCO
IPO.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
16—Off-Balance
Sheet Arrangement
We lease
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 (see Note 17). In
November 2004, we gave notice to Deep Sea Investors of our intent to purchase
the rig under the lease purchase option for a maximum amount of $35.7 million at
the end of the lease term in November 2005. The lease does not require that
collateral be maintained or contain any credit rating triggers.
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 is
with an entity in which we have no direct investment, we are not entitled to
receive the financial information of the leasing entity and the equity holders
of the leasing company will not release the financial statements or other
financial information to us in order for us to make the determination of whether
the entity is a variable interest entity. In addition, without the financial
statements or other financial information, we are unable to determine if we are
the primary beneficiary of the entity and, if so, what we would consolidate. We
have no exposure to loss as a result of the sale/leaseback agreement. We
currently account for the lease of this semisubmersible drilling rig as an
operating lease.
Note
17—Commitments
and Contingencies
Operating
Leases¾We have
operating lease commitments expiring at various dates, principally for real
estate, office space, office equipment and rig bareboat charters. 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, 2004, future minimum
rental payments related to noncancellable operating leases are as follows (in
millions):
| |
|
Years
ending December 31, |
|
| |
|
|
|
|
|
2005 |
|
$ |
26.6 |
|
|
2006 |
|
|
11.1 |
|
|
2007 |
|
|
8.8 |
|
|
2008
|
|
|
8.3 |
|
|
2009
|
|
|
6.5 |
|
|
Thereafter |
|
|
7.5 |
|
|
Total |
|
$ |
68.8 |
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
We are
party to an operating lease on the M. G.
Hulme, Jr. (see
Note 16). At December 31, 2004, the future minimum lease payments, excluding the
purchase option, was $11.9 million and was included in the table
above.
Rental
expense for all operating leases, including leases with terms of less than one
year, was approximately $40 million, $51 million and $52 million for the years
ended December 31, 2004, 2003 and 2002, respectively.
Legal
Proceedings¾Several
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. Based on a recent decision of the Mississippi Supreme
Court, we anticipate that the trial courts may grant motions requiring each
plaintiff to name the specific defendant or defendants against whom such
plaintiff makes a claim and the time period and location of asbestos exposure so
that the cases may be properly severed. We have not yet had an opportunity to
conduct any discovery nor have we been able to determine the number of
plaintiffs, if any, 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 current consolidated financial position, results
of operations and cash flows.
In 1990
and 1991, two of our subsidiaries were served with various assessments
collectively valued at approximately $6.8 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 $5.9 million. We are continuing to challenge the
assessment, however, and have an action to stay execution of a related tax
foreclosure proceeding. We have received a favorable ruling in connection with a
disputed August 1990 assessment but the government has appealed that ruling. We
also are awaiting a ruling from the Taxpayer's Council in connection with an
October 1990 assessment. If our defenses are ultimately unsuccessful, we believe
that the Brazilian government-controlled oil company, Petrobras, has a
contractual obligation to reimburse us for municipal tax payments required to be
paid by them. We do not expect the liability, if any, resulting from these
assessments to have a material adverse effect on our current consolidated
financial position, results of operations and 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 Gold (Control) Appellate Tribunal ("CEGAT")
together with an application to have the confiscation of the rig stayed pending
the outcome of the appeal. In March 2000, the CEGAT ruled on the stay
application, directing that the confiscation be stayed pending the appeal. The
CEGAT 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 CEGAT 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
CEGAT did not grant us the benefit of a customs duty exemption due to the
absence of the required documentation, CEGAT left it open for our subsidiary to
seek such documentation from the Ministry of Petroleum. Following the CEGAT
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 CEGAT 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 CEGAT, and both
appeals were admitted. The Supreme Court has recently dismissed the Customs
Department appeal and affirmed the CEGAT order but the Customs Department has
not agreed with our interpretation of that order. 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 current consolidated
financial position, results of operations and cash flows.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 current
consolidated financial position, results of operations and 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 current consolidated financial
position, results of operations and cash flows.
One of
our subsidiaries is involved in an action with respect to customs penalties
relating to the Sedco
710
semisubmersible drilling rig. Prior to our merger with Sedco Forex, this
drilling rig, which was working for Petrobras in Brazil at the time, had been
admitted into the country on a temporary basis under authority granted to a
Schlumberger entity. Prior to the Sedco Forex merger, the drilling contract was
moved to an entity that would become one of our subsidiaries. In early 2000, the
drilling contract was extended for another year. On January 10, 2000, the
temporary import permit granted to the Schlumberger entity expired, and renewal
filings were not made until later that January. In April 2000, the Brazilian
customs authorities cancelled the import permit. The Schlumberger entity filed
an action in the Brazilian federal court of Campos for the purpose of extending
the temporary admission. Other proceedings were also initiated in order to
secure the transfer of the temporary admission to our subsidiary. Ultimately,
the court permitted the transfer to our entity but has not ruled that the
temporary admission could be extended without the payment of a financial
penalty. During the first quarter of 2004, the customs office renewed its
efforts to collect a penalty and issued a second assessment for this penalty but
has now done so against our subsidiary. The assessment is for approximately $61
million. We believe that the amount of the assessment, even if it were
appropriate, should only be approximately $6 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 current consolidated financial position, results of operations and 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 current consolidated
financial position, results of operations and 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Letters
of Credit and Surety Bonds—We had
letters of credit outstanding totaling $182.2 million and $186.2 million at
December 31, 2004 and 2003. 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
$7.6 million and $169.5 million at December 31, 2004 and 2003, respectively. The
decrease in outstanding surety bonds is primarily attributable to the expiration
of such bonds totaling $151.1 million related to our Brazil operations. Until
April 2005, we also guarantee $11.9 million of TODCO’s surety bonds, which TODCO
has collateralized.
Note
18—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 earned or deferred units being determined
following the completion of the performance cycle (the “determination date”) at
which time one-third of the options, shares or deferred units granted vest.
Additional vesting occurs December 31 of the two subsequent years following the
determination date.
As of
December 31, 2004, 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, 2004, there were approximately 9.5
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 unvested restricted share awards that could be
issued at December 31, 2004 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 |
|
Weighted-Average |
|
| |
|
Under
Option |
|
Exercise
Price |
|
|
Outstanding
at December 31, 2001 |
|
|
13,460,679 |
|
$ |
27.99 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
2,160,963 |
|
|
28.63 |
|
|
Exercised |
|
|
(102,480 |
) |
|
18.12 |
|
|
Forfeited |
|
|
(141,576 |
) |
|
37.99 |
|
|
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 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
- |
|
|
Exercised |
|
|
(1,153,857 |
) |
|
18.59 |
|
|
Forfeited |
|
|
(149,845 |
) |
|
35.74 |
|
|
Outstanding
at December 31, 2004 |
|
|
13,971,699 |
|
$ |
28.60 |
|
| |
|
|
|
|
|
|
|
|
Exercisable
at December 31, 2002 |
|
|
11,332,039 |
|
$ |
26.14 |
|
|
Exercisable
at December 31, 2003 |
|
|
13,091,737 |
|
$ |
27.53 |
|
|
Exercisable
at December 31, 2004 |
|
|
13,195,638 |
|
$ |
28.77 |
|
The
following table summarizes information about time-based vesting stock options
outstanding at December 31, 2004:
| |
|
Weighted-Average |
|
Options
Outstanding |
|
Options
Exercisable |
|
Range
of |
|
Remaining |
|
Number |
|
Weighted-Average |
|
Number |
|
Weighted-Average |
|
Exercise
Prices |
|
Contractual
Life |
|
Outstanding |
|
Exercise
Price |
|
Outstanding |
|
Exercise
Price |
| |
|
|
|
|
|
|
|
|
|
|
|
|
$
8.68- $19.86 |
|
4.06 |
years |
|
3,189,396 |
|
$15.36 |
|
3,133,060 |
|
$15.29 |
|
$20.12-
$33.69 |
|
4.97 |
years |
|
5,849,952 |
|
$25.94 |
|
5,144,237 |
|
$25.93 |
|
$34.63-
$81.78 |
|
5.42 |
years |
|
4,932,351 |
|
$40.32 |
|
4,918,341 |
|
$40.33 |
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, 2001 |
|
|
61,667 |
|
$ |
25.48 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
13,000 |
|
|
28.80 |
|
|
Distributed |
|
|
(38,326 |
) |
|
17.96 |
|
|
Forfeited |
|
|
(1,000 |
) |
|
38.07 |
|
|
Outstanding
at December 31, 2002 |
|
|
35,341 |
|
|
34.50 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
21,000 |
|
|
20.65 |
|
|
|
|
|
(14,981 |
) |
|
35.27 |
|
|
Forfeited |
|
|
- |
|
|
- |
|
|
Outstanding
at December 31, 2003 |
|
|
41,360 |
|
|
27.19 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
8,281 |
|
|
28.12 |
|
|
|
|
|
(21,519 |
) |
|
30.52 |
|
|
Forfeited |
|
|
(1,547 |
) |
|
32.60 |
|
|
Outstanding
at December 31, 2004 |
|
|
26,575 |
|
$ |
24.58 |
|
The
following table summarizes SARs activity under the Incentive Plan:
| |
|
Number
of Shares |
|
Weighted-Average |
|
| |
|
Under
Option |
|
Exercise
Price |
|
|
Outstanding
at December 31, 2001 |
|
|
118,785 |
|
$ |
33.77 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
32,475 |
|
|
28.80 |
|
|
Exercised |
|
|
- |
|
|
- |
|
|
Forfeited |
|
|
(5,896 |
) |
|
34.97 |
|
|
Outstanding
at December 31, 2002 |
|
|
145,364 |
|
|
32.61 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
- |
|
|
Exercised |
|
|
- |
|
|
- |
|
|
Forfeited |
|
|
(9,946 |
) |
|
34.01 |
|
|
Outstanding
at December 31, 2003 |
|
|
135,418 |
|
|
32.51 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
- |
|
|
- |
|
|
Exercised |
|
|
(666 |
) |
|
28.80 |
|
|
Forfeited |
|
|
(2,427 |
) |
|
35.52 |
|
|
Outstanding
at December 31, 2004 |
|
|
132,325 |
|
$ |
32.47 |
|
In May
2004, we granted 20,538 deferred units to outside directors at a
weighted-average price of $27.17. A deferred unit is a unit that is equal to one
ordinary share. At December 31, 2004, there were 18,256 deferred units
outstanding.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Performance-Based
Awards
There was
no performance-based award activity prior to 2003. The following table
summarizes performance-based stock option activity during 2004 and
2003:
| |
|
Number
of Shares |
|
Weighted-Average |
|
| |
|
Under
Option |
|
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 |
|
At
December 31, 2004 and 2003, none of the performance-based stock options were
exercisable.
The
following table summarizes information about performance-based stock options
outstanding at December 31, 2004:
| |
|
Weighted-Average |
|
Options
Outstanding |
|
Options
Exercisable |
|
Range
of |
|
Remaining |
|
Number |
|
Weighted-Average |
|
Number |
|
Weighted-Average |
|
Exercise
Prices |
|
Contractual
Life |
|
Outstanding |
|
Exercise
Price |
|
Outstanding |
|
Exercise
Price |
| |
|
|
|
|
|
|
|
|
|
|
|
|
$21.20
- $28.12 |
|
8.97 |
years |
|
1,217,314 |
|
$24.29 |
|
- |
|
$- |
During
2004 and 2003, we granted performance-based nonvested restricted ordinary share
awards that are earnable based on the achievement of certain performance
targets. The number of shares to be issued will be quantified upon completion of
the performance period at the determination date. At December 31, 2004 and 2003,
the maximum number of nonvested restricted ordinary shares that could be issued
at the determination date was 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 |
|
|
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
890,073 |
|
$ |
21.20 |
|
|
Distributed |
|
|
- |
|
|
- |
|
|
Forfeited |
|
|
(55,655 |
) |
|
21.20 |
|
|
Outstanding
at December 31, 2003 |
|
|
834,418 |
|
|
21.20 |
|
| |
|
|
|
|
|
|
|
|
Granted |
|
|
700,351 |
|
|
28.12 |
|
|
|
|
|
- |
|
|
- |
|
|
Forfeited |
|
|
(45,066 |
) |
|
22.74 |
|
|
Outstanding
at December 31, 2004 |
|
|
1,489,703 |
|
$ |
24.41 |
|
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 its
beginning-of-year or end-of-year market price. At December 31, 2004, 390,437
ordinary shares were available for issuance pursuant to the ESPP after taking
into account the shares to be issued for the 2004 plan year.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
19—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.
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 an unfunded defined benefit plan (the “Nigeria Plan”) that
provides retirement and severance benefits for certain of our Nigerian
employees. The defined benefit pension benefits we provide are comprised of the
U.S. Plans, the Norway Plans and the Nigeria 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
change in projected benefit obligation, change in plan assets and funded status
is shown in the table below (in millions):
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
Change
in projected benefit obligation |
|
|
|
|
|
|
|
|
Projected
benefit obligation at beginning of year |
|
$ |
295.5 |
|
$ |
295.6 |
|
|
Service
cost |
|
|
16.7 |
|
|
16.6 |
|
|
Interest
cost |
|
|
16.7 |
|
|
18.2 |
|
|
Actuarial
losses (gains) |
|
|
13.9 |
|
|
(8.8 |
) |
|
Foreign
currency exchange rate changes |
|
|
5.7 |
|
|
1.2 |
|
|
Settlements
/ curtailments |
|
|
- |
|
|
(7.5 |
) |
|
Plan
amendments |
|
|
(4.5 |
) |
|
(6.4 |
) |
|
Benefits
paid |
|
|
(17.8 |
) |
|
(13.4 |
) |
|
Projected
benefit obligation at end of year |
|
|
326.2 |
|
|
295.5 |
|
| |
|
|
|
|
|
|
|
|
Change
in plan assets |
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year |
|
|
214.4 |
|
|
188.5 |
|
|
Actual
return on plan assets |
|
|
22.6 |
|
|
32.8 |
|
|
Employer
contributions |
|
|
13.7 |
|
|
23.3 |
|
|
Foreign
currency exchange rate changes |
|
|
3.7 |
|
|
1.0 |
|
|
Settlements
/ curtailments |
|
|
- |
|
|
(17.8 |
) |
|
Benefits
paid |
|
|
(17.8 |
) |
|
(13.4 |
) |
|
Fair
value of plan assets at end of year |
|
|
236.6 |
|
|
214.4 |
|
|
|
|
|
|
|
|
|
|
|
Funded
status |
|
|
(89.6 |
) |
|
(81.1 |
) |
|
Unrecognized
transition obligation |
|
|
2.5 |
|
|
2.0 |
|
|
Unrecognized
net actuarial loss |
|
|
80.5 |
|
|
71.7 |
|
|
Unrecognized
prior service cost |
|
|
(2.0 |
) |
|
2.3 |
|
|
Accrued
pension liability |
|
$ |
(8.6 |
) |
$ |
(5.1 |
) |
|
|
|
|
|
|
|
|
|
|
Amounts
recognized in the consolidated balance sheets consist
of: |
|
|
|
|
|
|
|
|
Prepaid
benefit cost |
|
$ |
3.2 |
|
$ |
3.4 |
|
|
Accrued
benefit liability |
|
|
(54.0 |
) |
|
(44.3 |
) |
|
Intangible
asset |
|
|
0.2 |
|
|
0.1 |
|
|
Accumulated
other comprehensive income |
|
|
42.0 |
|
|
35.7 |
|
|
Net
amount recognized |
|
$ |
(8.6 |
) |
$ |
(5.1 |
) |
The
accumulated benefit obligation for all defined benefit pension plans was $269.9
million and $241.5 million at December 31, 2004 and 2003,
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, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Projected
benefit obligation |
|
$ |
316.2 |
|
$ |
286.1 |
|
|
Fair
value of plan assets |
|
|
225.1 |
|
|
204.7 |
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Accumulated
benefit obligation |
|
$ |
252.5 |
|
$ |
228.5 |
|
|
Fair
value of plan assets |
|
|
213.7 |
|
|
195.2 |
|
Net
periodic benefit cost included the following components (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Components
of Net Periodic Benefit Cost (a) |
|
|
|
|
|
|
|
|
|
|
|
Service
cost |
|
$ |
16.7 |
|
$ |
16.6 |
|
$ |
16.8 |
|
|
Interest
cost |
|
|
16.7 |
|
|
18.2 |
|
|
19.0 |
|
|
Expected
return on plan assets |
|
|
(19.6 |
) |
|
(19.7 |
) |
|
(20.7 |
) |
|
Amortization
of transition obligation |
|
|
0.3 |
|
|
0.3 |
|
|
0.3 |
|
|
Amortization
of prior service cost |
|
|
0.6 |
|
|
1.3 |
|
|
1.4 |
|
|
Recognized
net actuarial (gains) losses |
|
|
2.3 |
|
|
0.4 |
|
|
(0.5 |
) |
|
Special
termination benefits (b) |
|
|
- |
|
|
- |
|
|
1.1 |
|
|
SFAS
88 settlements/curtailments |
|
|
- |
|
|
4.7 |
|
|
(0.3 |
) |
|
Benefit
cost |
|
$ |
17.0 |
|
$ |
21.8 |
|
$ |
17.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Increase
(decrease) in minimum pension liability included in other
comprehensive income (in millions) |
|
$ |
6.3 |
|
$ |
(10.0 |
) |
$ |
45.7 |
|
______________
(a) Amounts
are before income tax effect.
(b) Special
termination benefits paid to a former executive officer of ours from our
unfunded supplemental pension plan upon the officer’s retirement in June
2002.
Weighted-average
assumptions used to determine benefit obligations:
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Discount
rate |
|
|
5.60 |
% |
|
6.25 |
% |
|
Rate
of compensation increase |
|
|
5.00 |
% |
|
5.24 |
% |
Weighted-average
assumptions used to determine net periodic benefit cost:
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Discount
rate |
|
|
6.01 |
% |
|
6.65 |
% |
|
7.31 |
% |
|
Expected
long-term rate of return in plan assets |
|
|
8.73 |
% |
|
8.73 |
% |
|
8.73 |
% |
|
Rate
of compensation increase |
|
|
5.00 |
% |
|
5.24 |
% |
|
5.53 |
% |
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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. We utilize 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, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Equity
securities |
|
|
55.2 |
% |
|
59.7 |
% |
|
Debt
securities |
|
|
31.1 |
% |
|
30.1 |
% |
|
Other |
|
|
13.7 |
% |
|
10.2 |
% |
|
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.
We
contributed $13.7 million to our defined benefit pension plans in 2004. Such
contributions were funded from our cash flows from operations. Contributions of
$5.4 million and $5.4 million were made to the funded and unfunded U.S. Plans,
respectively, during 2004.
We expect
to contribute $3.0 million to the Transocean Plans in 2005, comprised of an
estimated $0.6 million to fund expected benefit payments for the unfunded U.S.
Plans and Nigeria Plan, and an estimated $2.4 million for the funded Norway
Plans.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
following pension benefits payments, which reflect expected future service, as
appropriate, are expected to be paid by the Transocean Plans (in
millions):
| |
|
Years
ending
December 31, |
|
| |
|
|
|
|
|
2005 |
|
$ |
13.5 |
|
|
2006 |
|
|
13.9 |
|
|
2007 |
|
|
14.4 |
|
|
2008 |
|
|
15.1 |
|
|
2009 |
|
|
15.7 |
|
|
Thereafter |
|
|
118.5 |
|
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, |
|
| |
|
2004 |
|
2003 |
|
Change
in benefit obligation |
|
|
|
|
|
|
|
|
Benefit
obligation at beginning of year |
|
$ |
62.0 |
|
$ |
41.2 |
|
|
Service
cost |
|
|
1.0 |
|
|
1.9 |
|
|
Interest
cost |
|
|
2.1 |
|
|
3.4 |
|
|
Actuarial
losses |
|
|
(2.9 |
) |
|
20.1 |
|
|
Participants’
contributions |
|
|
0.4 |
|
|
0.3 |
|
|
Plan
amendments |
|
|
(23.0 |
) |
|
- |
|
|
Settlements
/ curtailments |
|
|
- |
|
|
(2.9 |
) |
|
Benefits
paid |
|
|
(2.1 |
) |
|
(2.0 |
) |
|
Benefit
obligation at end of year |
|
|
37.5 |
|
|
62.0 |
|
|
|
|
|
|
|
|
|
|
|
Change
in plan assets |
|
|
|
|
|
|
|
|
Fair
value of plan assets at beginning of year |
|
|
- |
|
|
0.2 |
|
|
Actual
return on plan assets |
|
|
- |
|
|
(0.2 |
) |
|
Company
contributions |
|
|
1.7 |
|
|
1.7 |
|
|
Participants’
contributions |
|
|
0.4 |
|
|
0.3 |
|
|
Benefits
paid |
|
|
(2.1 |
) |
|
(2.0 |
) |
|
Fair
value of plan assets at end of year |
|
|
- |
|
|
- |
|
|
|
|
|
|
|
|
|
|
|
Funded
status |
|
|
(37.5 |
) |
|
(62.0 |
) |
|
Unrecognized
net actuarial gain |
|
|
23.7 |
|
|
26.0 |
|
|
Unrecognized
prior service cost |
|
|
(21.6 |
) |
|
1.2 |
|
|
Postretirement
benefit liability |
|
$ |
(35.4 |
) |
$ |
(34.8 |
) |
Amounts
recognized in the consolidated balance sheets for the years ended December 31,
2004 and 2003 consisted of accrued benefit costs totaling $35.4 million and
$34.8 million, respectively. There were no prepaid benefit costs recognized for
the years ended December 31, 2004 and 2003.
Net
periodic benefit cost included the following components (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Components
of Net Periodic Benefit Cost |
|
|
|
|
|
|
|
|
|
|
|
Service
cost |
|
$ |
1.0 |
|
$ |
2.0 |
|
$ |
1.0 |
|
|
Interest
cost |
|
|
2.1 |
|
|
3.4 |
|
|
2.5 |
|
|
Amortization
of prior service cost |
|
|
(2.3 |
) |
|
0.3 |
|
|
0.5 |
|
|
SFAS
88 settlements/curtailments |
|
|
- |
|
|
(0.6 |
) |
|
- |
|
|
Recognized
net actuarial losses |
|
|
1.5 |
|
|
1.3 |
|
|
0.3 |
|
|
Benefit
Cost |
|
$ |
2.3 |
|
$ |
6.4 |
|
$ |
4.3 |
|
Weighted-average
discount rates used to determine benefit obligations were 5.50% and 6.00% for
the years ended December 31, 2004 and 2003, respectively.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Weighted-average
assumptions used to determine net periodic benefit cost were as
follows:
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Discount
rate |
|
|
6.00 |
% |
|
6.50 |
% |
|
6.50 |
% |
|
Expected
long-term rate of return in plan assets |
|
|
- |
|
|
- |
|
|
- |
|
|
Rate
of compensation increase |
|
|
- |
|
|
- |
|
|
5.50 |
% |
Assumed
health care cost trend rates were as follows:
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Health
care cost trend rate assumed for next year |
|
|
11 |
% |
|
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- |
|
One- |
|
| |
|
Percentage |
|
Percentage |
|
| |
|
Point |
|
Point |
|
| |
|
Increase |
|
Decrease |
|
|
Effect
on total service and interest cost components in 2004 |
|
$ |
0.3 |
|
$ |
(0.4 |
) |
|
Effect
on postretirement benefit obligations as of December 31,
2004 |
|
$ |
3.4 |
|
$ |
(4.1 |
) |
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, 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 for postretirement benefit plans are the assumed
discount rate and the expected health care cost trend rates. We utilize the
Moody’s Aa long-term corporate bond yield 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 11 percent for 2004
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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
The
following postretirement benefits payments, which reflect expected future
service, as appropriate, are expected to be paid (in millions):
| |
|
Years
ending December 31, |
|
| |
|
|
|
|
|
2005 |
|
$ |
1.4 |
|
|
2006 |
|
|
1.5 |
|
|
2007 |
|
|
1.6 |
|
|
2008 |
|
|
1.7 |
|
|
2009 |
|
|
1.8 |
|
|
Thereafter |
|
|
10.7 |
|
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.
In May
2004, the FASB staff issued 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 year ended
December 31, 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 $20.3 million, $21.8 million and $21.3
million of expense related to our defined contribution plans for the years ended
December 31, 2004, 2003 and 2002, respectively.
Deferred
Compensation Plan—We
provide a Deferred Compensation Plan (the “Plan”). The Plan's primary purpose is
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 enroll in the Plan may 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) may,
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 may authorize employer contributions to
participants and our chief executive officer, with executive compensation
committee approval, is 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, 2004, 2003 or
2002.
Note
20—Investments
in and Advances to Unconsolidated Subsidiaries
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 22.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 has 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. As a result of the TODCO Offerings, Delta Towing was
deconsolidated in connection with the deconsolidation of TODCO at December 17,
2004. See Notes 4 and 22.
As a
result of our deconsolidation of TODCO at December 17, 2004, we now account for
our 22 percent interest in TODCO as an investment in an unconsolidated
subsidiary and recognize our investment in TODCO under the equity method of
accounting. At December 31, 2004, our investment in TODCO was $104.8 million. At
December 31, 2004, the market value of our investment in TODCO was $245.2
million. See Notes 1, 4 and 22.
Note
21—Segments,
Geographical Analysis and Major Customers
Through
December 16, 2004, our operations were aggregated into two reportable segments:
(i) Transocean Drilling and (ii) TODCO. The Transocean Drilling segment consists
of floaters, jackups and other rigs used in support of offshore drilling
activities and offshore support services. The TODCO segment consisted of our
interest in TODCO, which conducts jackup, drilling barge, land rig, submersible
and other operations located in the U.S. Gulf of Mexico and inland waters,
Mexico, Trinidad and Venezuela. As a result of the deconsolidation of TODCO, we
now operate in one industry segment, the Transocean Drilling segment. We provide
services with different types of drilling equipment in several geographic
regions. The location of our rigs and the allocation of resources to build or
upgrade rigs is determined by the activities and needs of customers. Accounting
policies of the segments are the same as those described in the Summary of
Significant Accounting Policies (see Note 2). We account for intersegment
revenue and expenses, if any, as if the revenue or expenses were to third
parties at current market prices.
Operating
revenues and income (loss) before income taxes, minority interest and cumulative
effect of changes in accounting principles by segment were as follows (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
Transocean
Drilling |
|
$ |
2,280.4 |
|
$ |
2,206.7 |
|
$ |
2,486.1 |
|
|
TODCO
(a) |
|
|
333.5 |
|
|
227.6 |
|
|
187.8 |
|
|
Total
Operating Revenues |
|
$ |
2,613.9 |
|
$ |
2,434.3 |
|
$ |
2,673.9 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Operating
Income (Loss) Before General and Administrative Expense |
|
|
|
|
|
|
|
|
|
|
|
Transocean
Drilling |
|
$ |
428.6 |
|
$ |
422.5 |
|
$ |
(1,739.0 |
) |
|
TODCO
(a) (b) |
|
|
(33.7 |
) |
|
(117.5 |
) |
|
(505.3 |
) |
| |
|
|
394.9 |
|
|
305.0 |
|
|
(2,244.3 |
) |
|
Unallocated
general and administrative expense |
|
|
(67.0 |
) |
|
(65.3 |
) |
|
(65.6 |
) |
|
Unallocated
other expense, net |
|
|
(87.6 |
) |
|
(218.1 |
) |
|
(178.9 |
) |
|
Income
(Loss) Before Income Taxes, Minority Interest and |
|
|
|
|
|
|
|
|
|
|
|
Cumulative
Effect of Changes in Accounting Principles (c) |
|
$ |
240.3 |
|
$ |
21.6 |
|
$ |
(2,488.8 |
) |
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
______________
| (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, 2003 and 2002 include $32.3 million, $14.9
million and $19.2 million, respectively, of operating and maintenance
expense that TODCO classifies as general and administrative
expense. |
| (c) |
|
The
year ended December 31, 2004 includes gains from the TODCO Offerings 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 Note 4. |
Depreciation
expense by segment was as follows (in millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
|
Transocean
Drilling |
|
$ |
432.6 |
|
$ |
416.0 |
|
$ |
408.4 |
|
|
TODCO |
|
|
92.0 |
|
|
92.2 |
|
|
91.9 |
|
|
Total
Depreciation Expense |
|
$ |
524.6 |
|
$ |
508.2 |
|
$ |
500.3 |
|
Total
assets by segment were as follows (in millions):
| |
|
December
31, |
|
| |
|
2004 |
|
2003 |
|
| |
|
|
|
|
|
|
|
|
Transocean
Drilling |
|
$ |
10,758.3 |
|
$ |
10,874.0 |
|
|
TODCO |
|
|
− |
|
|
788.6 |
|
|
Total
Assets |
|
$ |
10,758.3 |
|
$ |
11,662.6 |
|
Total
capital expenditures by segment were as follows (in millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Transocean
Drilling |
|
$ |
118.2 |
|
$ |
481.8 |
|
$ |
135.2 |
|
|
TODCO |
|
|
8.8 |
|
|
12.0 |
|
|
5.8 |
|
|
Total
Capital Expenditures |
|
$ |
127.0 |
|
$ |
493.8 |
|
$ |
141.0 |
|
Operating
revenues and long-lived assets by country were as follows (in
millions):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Operating
Revenues |
|
|
|
|
|
|
|
|
|
|
|
United
States |
|
$ |
856.0 |
|
$ |
752.8 |
|
$ |
752.5 |
|
|
Brazil |
|
|
278.0 |
|
|
316.7 |
|
|
283.0 |
|
|
India |
|
|
270.8 |
|
|
119.6 |
|
|
101.4 |
|
|
United
Kingdom |
|
|
208.8 |
|
|
211.6 |
|
|
345.7 |
|
|
Other
Countries (a) |
|
|
1,000.3 |
|
|
1,033.6 |
|
|
1,191.3 |
|
|
Total
Operating Revenues |
|
$ |
2,613.9 |
|
$ |
2,434.3 |
|
$ |
2,673.9 |
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
| |
|
As
of December 31, |
|
| |
|
2004 |
|
2003 |
|
Long-Lived
Assets |
|
|
|
|
|
|
|
|
United
States |
|
$ |
2,396.5 |
|
$ |
3,209.0 |
|
|
Brazil
|
|
|
865.3 |
|
|
1,276.6 |
|
|
Nigeria |
|
|
811.1 |
|
|
438.5 |
|
|
Other
Countries (a) |
|
|
2,932.3 |
|
|
3,085.5 |
|
|
Total
Long-Lived Assets |
|
$ |
7,005.2 |
|
$ |
8,009.6 |
|
______________________
|
(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.
Our
international operations are subject to certain political and other
uncertainties, including risks of war and civil disturbances (or other events
that disrupt markets), expropriation of equipment, repatriation of income or
capital, taxation policies, and the general hazards associated with certain
areas in which operations are conducted.
For the
year ended December 31, 2004, BP, Petrobras and ChevronTexaco 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. For the
year ended December 31, 2002, BP and Shell accounted for approximately 14.1
percent and 11.6 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
22—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. For the
year ended December 31, 2002 we earned $1.6 million for such services to each of
DD LLC and DDII LLC. Such revenue amounts were included in operating revenues in
the 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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 years ended December 31, 2003, and 2002, we earned
interest income on the outstanding balance at each period of $3.1 million and
$6.3 million, respectively, 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 each of the years ended December 31, 2003 and 2002, 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. During the
year ended December 31, 2002, TODCO incurred charges totaling $10.7 million from
Delta Towing for services rendered, of which $1.6 million was rebilled to
TODCO’s customers and $9.1 million was reflected in operating and maintenance
expense.
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. 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 $2.4 million, $1.2 million and $1.2 million for the
years ended December 31, 2004, 2003 and 2002. Such amounts are included in other
revenues in our consolidated statements of operations. At December 31, 2004 and
2003, we had receivables from ODL of $1.1 million and $3.1 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.
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 the consolidated statement
of operations. Any amounts recorded between us and TODCO subsequent to the
deconsolidation of TODCO in mid-December were not material. At December 31,
2004, we had payables related to the administrative support TODCO provides of
$0.3 million, which is included in accounts payable in the consolidated balance
sheet. At December 31, 2004, we had a long-term payable related to our
indemnification of certain TODCO non-U.S. income tax liabilities of $11.2
million, which is included in other long-term liabilities in the 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 current consolidated financial position, results
of operations and cash flows. Until April 2005, we also guarantee $11.9 million
of TODCO’s surety bonds, which TODCO has collateralized.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
23—Restructuring
Charges
In
September 2002, we committed to restructuring plans in France and Norway. We
established a liability of approximately $4.0 million for the estimated
severance-related costs associated with the involuntary termination of 24
employees pursuant to these plans. The charge was reported as operating and
maintenance expense in our consolidated statements of operations related to the
Transocean Drilling segment. Through December 31, 2004, approximately $3.6
million had been paid to 24 employees representing full or partial payments. In
June 2003, we released the expected surplus liability of $0.3 million to
operating and maintenance expense in the Transocean Drilling segment.
Substantially all of the remaining liability is expected to be paid by the end
of the first quarter in 2005.
Note
24—Earnings
Per Share
The
reconciliation of the numerator and denominator used for the computation of
basic and diluted earnings (loss) per share is as follows (in millions, except
per share data):
| |
|
Years
ended December 31, |
|
| |
|
2004 |
|
2003 |
|
2002 |
|
Numerator
for Basic and Diluted Earnings (Loss) per Share |
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Cumulative Effect of Changes in Accounting
Principles |
|
$ |
152.2 |
|
$ |
18.4 |
|
$ |
(2,368.2 |
) |
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
− |
|
|
0.8 |
|
|
(1,363.7 |
) |
|
Net
Income (Loss) |
|
$ |
152.2 |
|
$ |
19.2 |
|
$ |
(3,731.9 |
) |
|
Denominator
for Diluted Earnings (Loss) per Share |
|
|
|
|
|
|
|
|
|
|
|
Weighted-average
shares outstanding for basic earnings per share |
|
|
320.9 |
|
|
319.8 |
|
|
319.1 |
|
|
Effect
of dilutive securities: |
|
|
|
|
|
|
|
|
|
|
|
Employee
stock options and unvested stock grants |
|
|
2.6 |
|
|
1.1 |
|
|
- |
|
|
Warrants
to purchase ordinary shares |
|
|
1.7 |
|
|
0.5 |
|
|
- |
|
|
Adjusted
weighted-average shares and assumed |
|
|
|
|
|
|
|
|
|
|
|
conversions
for diluted earnings (loss) per share |
|
|
325.2 |
|
|
321.4 |
|
|
319.1 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
Basic
and Diluted Earnings (Loss) Per Share |
|
|
|
|
|
|
|
|
|
|
|
Income
(Loss) Before Cumulative Effect of Changes in Accounting Principles |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(7.42 |
) |
|
Cumulative
Effect of Changes in Accounting Principles |
|
|
- |
|
|
- |
|
|
(4.27 |
) |
|
Net
Income (Loss) |
|
$ |
0.47 |
|
$ |
0.06 |
|
$ |
(11.69 |
) |
Ordinary
shares subject to issuance pursuant to the conversion features of the
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. Incremental shares related to stock options, restricted stock
grants and warrants are not included in the calculation of adjusted
weighted-average shares and assumed conversions for diluted earnings per share
for the year ended December 31, 2002 because the effect of including those
shares is anti-dilutive. Incremental shares related to contingently convertible
debentures 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.
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
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, 2004, there were 261,000 warrants outstanding to
purchase 4,567,500 ordinary shares.
Note
26—Quarterly
Results (Unaudited)
Shown
below are selected unaudited quarterly data (in millions, except per share
data):
|
Quarter |
|
First |
|
Second |
|
Third |
|
Fourth |
|
|
2004 |
|
|
|
|
|
|
|
|
|
|
| |
Operating
Revenues |
|
$ |
652.0 |
|
$ |
633.2 |
|
$ |
651.8 |
|
$ |
676.9 |
|
| |
Operating
Income (a) |
|
|
96.8 |
|
|
103.8 |
|
|
71.1 |
|
|
56.2 |
|
| |
Net
Income (Loss) (b) |
|
|
22.7 |
|
|
48.0 |
|
|
154.9 |
|
|
(73.4 |
) |
| |
Basic
and Diluted Earnings (Loss) Per Share |
|
$ |
0.07 |
|
$ |
0.15 |
|
$ |
0.48 |
|
$ |
(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 |
|
|
325.3 |
|
|
321.2 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Operating
Revenues |
|
$ |
616.0 |
|
$ |
603.9 |
|
$ |
622.9 |
|
$ |
591.5 |
|
| |
Operating
Income (c) |
|
|
101.6 |
|
|
19.8 |
|
|
72.8 |
|
|
45.5 |
|
| |
Income
(Loss) Before Cumulative Effect of a Change in
Accounting Principle (d) |
|
|
47.2 |
|
|
(44.5 |
) |
|
11.0 |
|
|
4.7 |
|
| |
Net
Income (Loss) (d) |
|
$ |
47.2 |
|
$ |
(44.5 |
) |
$ |
11.0 |
|
$ |
5.5 |
|
| |
Basic
and Diluted Earnings (Loss) Per Share |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Income
(Loss) Before Cumulative Effect of a Change in Accounting
Principle |
|
$ |
0.15 |
|
$ |
(0.14 |
) |
$ |
0.03 |
|
$ |
0.02 |
|
| |
Weighted
Average Shares Outstanding |
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
Shares
for basic earnings per share |
|
|
319.7 |
|
|
319.8 |
|
|
319.9 |
|
|
319.9 |
|
| |
Shares
for diluted earnings per share |
|
|
321.6 |
|
|
319.8 |
|
|
321.1 |
|
|
321.3 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
___________________________
|
(a) |
First
quarter 2004 included stock option vesting resulting from the TODCO IPO of
$7.1 million (see Note 4). |
|
(b) |
First
quarter 2004 included a gain on the TODCO IPO of $39.4 million, a tax
valuation allowance of $31.0 million, stock option vesting resulting from
the TODCO IPO of $7.1 million (see Note 4) 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 TODCO Offering of $129.4 million (see
Note 4). Fourth quarter 2004 included a gain on the December TODCO
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 Note 4). |
|
(c) |
Second
quarter 2003 included loss on impairments of $15.8 million (see Note 7).
Third quarter 2003 included costs related to the TODCO IPO of $8.0 million
(see Note 1). Fourth quarter 2003 included costs to restructure the
Nigeria defined benefit plans of $16.9 million (see Note
19). |
|
(d) |
Second
quarter 2003 included loss on retirement of debt of $13.8 million (see
Note 8), impairment loss on note receivable from related party of $13.8
million (see Note 2) and a favorable resolution of a non-U.S. income tax
liability of $14.6 million (see Note 15). |
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
Note
27—Subsequent
Events (Unaudited)
In
January 2005, we completed the sale of the semisubmersible rig Sedco
600 for net
proceeds of $24.9 million and expect to recognize an after-tax gain of $18.8
million in the first quarter of 2005.
In
February 2005, we called 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 expect to redeem these notes at 109.92 percent of
face value or $272.4 million, plus accrued and unpaid interest. The redemption
is expected to be completed by March 21, 2005. We expect to recognize a loss on
the redemption of approximately $10.8 million in the first quarter of 2005,
which reflects 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 plan to fund the redemption with existing cash
on hand.
ITEM 9. Changes
in and Disagreements with Accountants on Accounting and Financial
Disclosure
We have
not had a change in or disagreement with our accountants within 24 months prior
to the date of our most recent financial statements or in any period subsequent
to such date.
In
accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of December 31, 2004 to provide reasonable
assurance that information required to be disclosed in our reports filed or
submitted under the Exchange Act is 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 have
continued to make certain changes to our internal controls over financial
reporting during the quarter ended December 31, 2004 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.
None
PART
III
ITEM 10. Directors
and Executive Officers of the Registrant
ITEM 12. Security
Ownership of Certain Beneficial Owners and Management
ITEM 13. Certain
Relationships and Related Transactions
ITEM 14. 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 2005 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, 2004. 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.”
ITEM 15. Exhibits
and Financial Statement Schedules
| |
(a) |
Index
to Financial Statements, Financial Statement Schedules and Exhibits
|
(1)
Financial Statements
Included in Part II of this report:
| |
Page |
|
Included
in Part II of this report: |
|
|
|
56 |
|
|
57 |
|
|
58 |
|
|
59 |
|
|
60 |
|
|
61 |
|
|
62 |
|
|
63 |
|
|
65 |
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 |
|
|
|
|
|
|
|
|
|
Charged |
|
Charged |
|
|
|
|
|
|
|
Balance
at |
|
to
Costs |
|
to
Other |
|
|
|
Balance
at |
|
|
|
Beginning |
|
And |
|
Accounts |
|
Deductions |
|
End
of |
|
|
|
|
of
Period |
|
Expenses |
|
Describe |
|
Describe |
_________ |
Period |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
Ended December 31, 2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Reserves
and allowances deducted from asset |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
accounts: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for doubtful accounts |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
receivable |
|
$ |
24.2 |
|
$ |
16.6 |
|
$ |
- |
|
$ |
20.0 |
(a) |
$ |
20.8 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for obsolete materials and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
supplies |
|
|
24.1
|
|
|
0.3 |
|
|
0.7 |
(c) |
|
6.5 |
(b)
(d) (e) |
|
18.6
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
(h) |
$ |
2.2 |
(b) (f) (g) |
$ |
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 |
(i) (j) |
|
22.7 |
(a) |
|
16.8 |
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Allowance
for obsolete materials and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
supplies |
|
$ |
17.5 |
|
$ |
3.2 |
|
$ |
- |
|
$ |
0.4 |
(k) (l) |
$ |
20.3 |
|
_____________________________
| |
(a) |
Uncollectible
accounts receivable written off, net of
recoveries. |
| |
(b) |
Obsolete
materials and supplies written off, net of
scrap. |
| |
(c) |
Amount
includes $0.4 related to adjustments to the
provision. |
| |
(d) |
Amount
includes $0.8 related to sale of
rigs/inventory. |
| |
(e) |
Amount
includes $3.7 related to adjustments to the
provision. |
| |
(f) |
Amount
includes $0.8 related to sale of rigs/inventory.
|
| |
(g) |
Amount
includes $0.9 related to adjustments to the
provision. |
| |
(h) |
Amount
includes $0.2 related to adjustments to the
provision. |
| |
(i) |
Amount
includes $0.2 related to the TODCO
deconsolidation. |
| |
(j) |
Amount
includes $0.4 related to adjustments to the
provision. |
| |
(k) |
Amount
includes $0.3 related to the TODCO
deconsolidation. |
| |
(l) |
Amount
includes $0.1 related to sale of
rigs/inventory. |
Other
schedules are omitted either because they are not required or are not applicable
or because the required information is included in the financial statements or
notes thereto.
(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 |
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) |
| |
4.17 |
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) |
| |
4.18 |
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) |
| 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 Appendix C to the Company's Proxy Statement dated March
28, 2003) |
|
*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 |
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) |
|
*10.9 |
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) |
|
*10.10 |
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) |
|
*10.11 |
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) |
|
*10.12 |
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) |
|
*10.13 |
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) |
|
*10.14 |
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)
|
|
*10.15 |
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) |
|
*10.16 |
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) |
|
*10.17 |
1992
Long-Term Incentive Plan of Reading & Bates Corporation (incorporated
by reference to Exhibit B to Reading & Bates' Proxy Statement dated
April 27, 1992) |
|
*10.18 |
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) |
|
*10.19 |
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) |
|
*10.20 |
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) |
|
*10.21 |
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) |
|
*10.22 |
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) |
|
*10.23 |
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) |
|
*10.24 |
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) |
|
10.25 |
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) |
|
10.26 |
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)
|
|
10.27 |
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) |
|
10.28 |
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) |
|
*10.29 |
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) |
|
*10.30 |
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) |
|
*10.31 |
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) |
|
*10.32 |
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) |
|
*10.33 |
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) |
|
*10.34 |
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 15, 2005) |
|
*10.35 |
Description
of Director Compensation (incorporated by reference to Item 1.01 of the
Company's Current Report on Form 8-K on February 15,
2005) |
|
†*10.36 |
Description
of Base Salaries for Certain Executive
Officers |
_____________________________
*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 16, 2005.
| |
|
|
| |
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 16, 2005
| |
Signature |
|
Title |
|
| |
|
|
|
|
| |
|
|
|
|
| |
|
|
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|
| |
* |
|
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) |
|
| |
|
|
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| |
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| |
* |
|
Director |
|
| |
Victor
E. Grijalva |
|
|
|
| |
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| |
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| |
* |
|
Director |
|
| |
Arthur
Lindenauer |
|
|
|
| |
|
|
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| |
|
|
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| |
* |
|
Director |
|
| |
Martin
B. McNamara |
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
* |
|
Director |
|
| |
Roberto
Monti |
|
|
|
TRANSOCEAN
INC. AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS - Continued
| |
|
|
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|
| |
Signature |
|
Title |
|
| |
|
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| |
|
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| |
* |
|
Director |
|
| |
Richard
A. Pattarozzi |
|
|
|
| |
|
|
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| |
|
|
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|
| |
* |
|
Director |
|
| |
Kristian
Siem |
|
|
|
| |
|
|
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|
| |
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| |
* |
|
Director |
|
| |
Robert
M. Sprague |
|
|
|
| |
|
|
|
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| |
|
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| |
* |
|
Director |
|
| |
Ian
C. Strachan |
|
|
|
| |
|
|
|
|
| |
|
|
|
|
| |
By
/s/ William E. Turcotte |
|
|
|
| |
William
E. Turcotte |
|
|
|
| |
(Attorney-in-Fact) |
|
|
|