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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM 10-K
(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] 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 1-31983
---------------------
TODCO
(Exact name of registrant as specified in its charter)
DELAWARE 76-0544217
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
2000 W. SAM HOUSTON PARKWAY SOUTH, SUITE 800 (713) 278-6000
HOUSTON, TEXAS 77042-3615 (Registrant's telephone number, including area code)
(Address, of registrant's principal executive offices)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
Class A common stock, par value $.01 per share New York Stock Exchange
Preferred stock purchase rights New York Stock Exchange
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 [ ] No [X]
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 the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K [X]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12-b-2 of the Act). Yes [ ] No [X]
At December 31, 2003, all of the registrant's common equity was held by an
affiliate. The aggregate market value of the Class A common stock held by
non-affiliates as of March 1, 2004, was approximately $213.5 million, based on
the closing price of the Class A common stock on that date as reported by the
New York Stock Exchange. There is no active market for Class B common stock, all
of which is held by affiliates. There was no market for the registrant's common
equity at June 30, 2003.
The number of outstanding shares of each class of the registrant's common
stock as of March 1, 2004, was 14,092,286 shares of Class A common stock and
46,200,000 of Class B common stock.
DOCUMENTS INCORPORATED BY REFERENCE
NONE
TABLE OF CONTENTS
PAGE
NUMBER
------
PART I
Item 1. Business.................................................... 2
Item 2. Properties.................................................. 20
Item 3. Legal Proceedings........................................... 20
Item 4. Submission of Matters to a Vote of Security Holders......... 22
PART II
Item 5. Market for the Registrant's Common Equity and Related
Stockholder Matters......................................... 23
Item 6. Selected Financial Data..................................... 24
Item 7. Management's Discussion and Analysis of Financial Condition
and Results of Operations................................... 25
Item 7A. Quantitative and Qualitative Disclosures about Market
Risk........................................................ 45
Item 8. Financial Statements and Supplementary Data................. 46
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosures................................... 90
Item 9A. Controls and Procedures..................................... 90
PART III
Item 10. Directors and Executive Officers of the Registrant.......... 91
Item 11. Executive Compensation...................................... 95
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 99
Item 13. Certain Relationships and Related Party Transactions........ 100
Item 14. Principal Accountant Fees and Services...................... 115
PART IV
Item 15. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 116
1
PART I
ITEM 1. BUSINESS
OVERVIEW
TODCO is a leading provider of contract oil and gas drilling services,
primarily in the U.S. Gulf of Mexico shallow water and inland marine region, an
area that we refer to as the U.S. Gulf Coast. We have the largest fleet of
drilling rigs in the U.S. Gulf Coast and believe that, as a result of our
leading position and geographic focus, we are well-positioned to benefit from a
potential increase in drilling activity associated with the search for natural
gas in this region. TODCO, together with its subsidiaries, unless the context
requires otherwise, will be referred to in this document as "Company," "we,"
"us," or "our". We are a majority owned subsidiary of Transocean Inc.
("Transocean"), the world's largest offshore oil and gas drilling contractor.
We operate a fleet of 70 drilling rigs consisting of 30 inland barge rigs,
24 jackup rigs, three submersible rigs, one platform rig, nine land rigs and
three lake barge rigs. 52 of these rigs currently operate in shallow and inland
waters of the United States with the remainder operating in Mexico, Trinidad and
Venezuela.
Our core business is to contract our drilling rigs, related equipment and
work crews on a dayrate basis to customers who are drilling oil and gas wells.
We provide these services mainly to independent oil and gas companies, but we
also service major international and government-controlled oil and gas
companies. Our customers in the U.S. Gulf Coast typically focus on drilling for
natural gas. Historically, we also provided contract oil and gas drilling
services in deepwater areas and areas outside of the United States other than
Mexico, Trinidad and Venezuela.
BUSINESS SEGMENTS
We provide contract oil and gas drilling services and report the results of
those operations in three business segments which correspond to the principal
geographic regions in which we operate:
- U.S. Inland Barge Segment -- Our barge rig fleet currently operating in
this market segment consists of 12 conventional and 18 posted barge rigs.
These units operate in marshes, rivers, lakes and shallow bay or coastal
waterways that are known as "transition zone". This area along the U.S.
Gulf Coast, where jackup rigs are unable to operate, is the world's
largest market for this type of equipment.
- U.S. Gulf of Mexico Segment -- We currently operate 19 jackup and three
submersible rigs in the U.S. Gulf of Mexico shallow water market segment
which begins at the outer limit of the transition zone and extends to
water depths of about 350 feet. Our jackup rigs in this market segment
consist of independent leg cantilever type units, mat-supported
cantilever type rigs and mat-supported slot type jackup rigs that can
operate in water depths up to 250 feet.
- Other International Segment -- Our other operations are currently
conducted in Mexico, Trinidad and Venezuela. In Mexico, we operate two
jackup rigs and are preparing our platform rig to operate for PEMEX, the
Mexican national oil company. Additionally, we have two jackup rigs in
Trinidad and one in Venezuela, where we also have nine land rigs and
three Lake Maracaibo barges.
In addition to our drilling operations, we own a partial interest in a
joint venture that operates a fleet of U.S. marine support vessels consisting
primarily of shallow water tugs, crewboats and utility barges ("Delta Towing").
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 "Management's Discussion and Analysis of Financial Condition and
Results of Operations" and Note 19 to our consolidated financial statements
included in Item 8 of this report. For information about the risks and
uncertainties relating to our business, see "Risk Factors."
Our website address is www.theoffshoredrillingcompany.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
2
reference in this Form 10-K. We make available on this website, 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 maintains an
Internet site (www.sec.gov) that contains reports, proxy and information
statements, and other information regarding issuers that file electronically
with the SEC, including us.
Our executive offices are located at 2000 W. Sam Houston Parkway South,
Suite 800, Houston, Texas 77042, and our telephone number is (713) 278-6000.
OUR RELATIONSHIP WITH TRANSOCEAN
We were incorporated in Delaware on July 7, 1997 as R&B Falcon Corporation.
On January 31, 2001, we became an indirect wholly owned subsidiary of Transocean
as a result of our merger with Transocean (the "Transocean Merger"). The merger
was accounted for as a purchase, with Transocean as the accounting acquirer. On
December 13, 2002, we changed our name from R&B Falcon Corporation to TODCO.
In July 2002, Transocean announced plans to divest its Gulf of Mexico
shallow and inland water ("Shallow Water") business through an initial public
offering of TODCO. Prior to the closing of our initial public offering, we
transferred to Transocean assets not included in the TODCO business (the
"Transocean Assets"), as defined in the master separation agreement and
described in "Certain Relationships and Related Party
Transactions -- Relationship Between Us and Transocean -- Master Separation
Agreement -- TODCO Business." See the table on page 101 for a summary of our
drilling units and non-drilling units as of December 31, 2000 and as of the
initial public offering. See "Certain Relationships and Related Party
Transactions -- Asset Transfers to Transocean." In 2003, we completed the
transfer to Transocean of all Transocean Assets, including the transfer of all
revenue-producing assets.
In February 2004, we completed the initial public offering of 13,800,000
shares of our Class A common stock (the "IPO") as part of our separation from
Transocean Holdings Inc. ("Transocean Holdings"), a subsidiary of Transocean,
(collectively Transocean). We did not receive any proceeds from the initial sale
of our Class A common stock.
Upon completion of the IPO, we entered into various agreements to complete
the separation of our business from Transocean, including an employee matters
agreement, a master separation agreement and a tax sharing agreement. The master
separation agreement provides for, among other things, the assumption by us of
liabilities relating to our business and the assumption by Transocean of
liabilities unrelated to our business. Under the tax sharing agreement,
Transocean will indemnify us against most pre-IPO income tax liabilities.
However, we must pay Transocean for most pre-IPO income tax benefits that we
utilize after the IPO. See "Certain Relationships and Related Party
Transactions -- Relationship Between Us and Transocean -- Tax Sharing
Agreement." The separation agreements between us and Transocean also govern our
various interim and ongoing relationships.
Transocean currently owns 100% of our outstanding Class B common stock
giving it 94% of the combined voting power of our outstanding common stock.
Transocean does not own any of our outstanding Class A common stock. Transocean
has advised us that its current long term intent is to dispose of our Class B
common stock owned by it.
DRILLING RIG FLEET
Our drilling rig fleet consists of jackup rigs, barge rigs, and other rigs,
which include submersible rigs, a platform drilling rig, land drilling rigs and
Lake Maracaibo barge rigs.
There are several factors that determine the type of rig most suitable for
a particular drilling operation. The most significant factors are water depth
and seabed conditions (in offshore and inland marine environments), whether
drilling is being done over a platform or other structure, and the intended well
depth. Our fleet allows us to meet a broad range of needs in the shallow water
along the U.S. Gulf Coast. Most of our drilling equipment is suitable for both
exploration and development drilling, and we are normally engaged in
3
both types of drilling activity. 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.
Following are brief descriptions of the types of rigs we operate. Rigs
described in the following charts as "under contract" are operating under
contract, including rigs being prepared or mobilized under contract. Rigs
described as "warm stacked" are not under contract but are actively marketed and
may require the hiring of additional crew (and, in some cases, an entire crew),
but are generally ready for service with little or no capital expenditures. Rigs
described as "cold stacked" are not actively marketed, generally cannot be ready
for service immediately and normally require the hiring of an entire crew. Cold
stacked rigs will also require a varying degree of maintenance and significant
refurbishment before they can be operated as drilling rigs. We include
information in the following charts for rated drilling depth, which means
drilling depth stated by the manufacturer of the drilling equipment. A rig may
not have the actual capacity to drill to the rated drilling depth.
JACKUP DRILLING RIGS (24)
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 jacked further up the legs so that the platform is above the highest
expected waves. The rig hull includes the drilling rig, jacking system, crew
quarters, loading and unloading facilities, storage areas for bulk and liquid
materials, helicopter landing deck and other related equipment.
Jackup rig legs may operate independently or have a lower hull referred to
as a "mat" attached to the lower portion of the legs in order to provide a more
stable foundation in soft bottom areas. Independent leg rigs are better suited
for harder or uneven seabed conditions while mat rigs are better suited for soft
bottom conditions. Some of our jackup rigs have a cantilever design, a feature
that permits the drilling platform to be extended out from the hull, allowing it
to perform drilling or workover operations over some types of preexisting
platforms or structures. Our other jackup rigs have a slot-type design,
permitting the rig to be configured for drilling operations to take place
through a slot in the hull. Slot-type rigs are usually used for exploratory
drilling, since it is difficult to position them over existing platforms or
structures. Jackup rigs with the cantilever feature historically have achieved
higher dayrates and utilization rates than slot type rigs.
4
The following table contains information regarding our jackup rig fleet as
of March 1, 2004:
ORIGINAL WATER DEPTH RATED DRILLING
YEAR ENTERED CAPACITY DEPTH
RIG TYPE(A) SERVICE (IN FEET) (IN FEET) LOCATION STATUS
--- ------- ------------ ----------- -------------- --------- --------------
THE 110.............. MC 1982 100 20,000 Trinidad Under Contract
THE 150.............. ILC 1979 150 20,000 U.S. Under Contract
THE 152.............. MC 1980 150 20,000 U.S. Warm Stacked
THE 153.............. MC 1980 150 20,000 U.S. Cold Stacked
THE 155.............. ILC 1980 150 20,000 U.S. Cold Stacked
THE 156.............. ILC 1983 150 20,000 Venezuela Under Contract
THE 185.............. ILC 1982 120 20,000 U.S. Cold Stacked
THE 191.............. MS 1978 160 20,000 U.S. Cold Stacked
THE 200.............. MC 1979 200 20,000 U.S. Under Contract
THE 201.............. MC 1981 200 20,000 U.S. Under Contract
THE 202.............. MC 1982 200 20,000 U.S. Under Contract
THE 203.............. MC 1981 200 20,000 U.S. Under Contract
THE 204.............. MC 1981 200 20,000 U.S. Under Contract
THE 205.............. MC 1979 200 20,000 Mexico Under Contract
THE 206.............. MC 1980 200 20,000 Mexico Under Contract
THE 207.............. MC 1981 200 20,000 U.S. Under Contract
THE 208(b)........... MC 1980 200 20,000 Trinidad Cold Stacked
THE 250.............. MS 1974 250 20,000 U.S. Warm Stacked
THE 251.............. MS 1978 250 20,000 U.S. Under Contract
THE 252.............. MS 1978 250 20,000 U.S. Cold Stacked
THE 253.............. MS 1982 250 20,000 U.S. Under Contract
THE 254.............. MS 1976 250 20,000 U.S. Cold Stacked
THE 255(c)........... MS 1976 250 20,000 U.S. Cold Stacked
THE 256(c)........... MS 1975 250 20,000 U.S. Cold Stacked
---------------
(a) "ILC" means an independent leg cantilevered jackup rig. "MC" means a
mat-supported cantilevered jackup rig. "MS" means a mat-supported slot-type
jackup rig.
(b) This rig is currently unable to operate in the U.S. Gulf of Mexico due to
regulatory restrictions.
(c) These rigs would require substantial refurbishment to be ready for service.
The estimated costs to prepare for service those rigs in the preceding
table that (i) are noted as requiring substantial refurbishment, range from $7.7
million to $9.5 million per rig and (ii) are otherwise listed as cold stacked,
range from $1.0 million to $3.5 million per rig. These estimated amounts will be
subject to variables including the availability and cost of shipyard facilities,
cost of equipment and materials and the actual extent of required repairs and
maintenance. Actual amounts could vary substantially.
BARGE DRILLING RIGS (30)
Barge drilling rigs are mobile drilling platforms that are submersible and
are built to work in eight to 20 feet of water. They are towed by tugboats to
the drill site with the derrick lying down. The lower hull is then submerged by
flooding compartments until it rests on the river or sea floor. The derrick is
then raised and drilling operations are conducted with the barge resting on the
bottom. Our barge drilling fleet consists of conventional and posted barge rigs.
A posted barge is identical to a conventional barge except that the hull and
superstructure are separated by 10- to 14-foot columns, which increases the
water depth capabilities of the rig. Most of our barge drilling rigs are
suitable for deep gas drilling.
5
The following table contains information regarding our barge drilling rig
fleet as of March 1, 2004:
ORIGINAL RATED
YEAR ENTERED HORSEPOWER DRILLING DEPTH
RIG TYPE(A) SERVICE RATING (IN FEET) LOCATION STATUS
--- ------- ------------ ---------- -------------- -------- --------------
1.................... Conv. 1980 2,000 20,000 U.S. Cold Stacked
7.................... Posted 1981 2,000 25,000 U.S. Cold Stacked
9.................... Posted 1975 2,000 25,000 U.S. Under Contract
10................... Posted 1981 2,000 25,000 U.S. Cold Stacked
11................... Conv. 1982 3,000 30,000 U.S. Under Contract
15................... Conv. 1981 2,000 25,000 U.S. Under Contract
17................... Posted 1981 3,000 30,000 U.S. Under Contract
19................... Conv. 1996 1,000 14,000 U.S. Under Contract
20(b)(c)............. Conv. 1998 1,000 14,000 U.S. Cold Stacked
21(b)................ Conv. 1982 1,500 15,000 U.S. Cold Stacked
23................... Conv. 1995 1,000 14,000 U.S. Cold Stacked
27................... Posted 1978 3,000 30,000 U.S. Under Contract
28................... Conv. 1979 3,000 30,000 U.S. Cold Stacked
29................... Conv. 1980 3,000 30,000 U.S. Under Contract
30(b)................ Conv. 1981 3,000 30,000 U.S. Cold Stacked
31(b)................ Conv. 1981 3,000 30,000 U.S. Cold Stacked
32................... Conv. 1982 3,000 30,000 U.S. Cold Stacked
41................... Posted 1981 3,000 30,000 U.S. Under Contract
46................... Posted 1981 3,000 30,000 U.S. Under Contract
47(b)................ Posted 1982 3,000 30,000 U.S. Cold Stacked
48................... Posted 1982 3,000 30,000 U.S. Under Contract
49................... Posted 1980 3,000 30,000 U.S. Cold Stacked
52................... Posted 1981 2,000 25,000 U.S. Under Contract
55................... Posted 1981 3,000 30,000 U.S. Under Contract
57................... Posted 1978 2,000 25,000 U.S. Under Contract
61(b)................ Posted 1978 3,000 30,000 U.S. Cold Stacked
62(d)................ Posted 1978 3,000 30,000 U.S. Cold Stacked
64................... Posted 1979 3,000 30,000 U.S. Under Contract
74(b)(e)............. Posted 1981 2,000 25,000 U.S. Cold Stacked
75(b)(e)............. Posted 1979 3,000 30,000 U.S. Cold Stacked
---------------
(a) "Conv." means a conventional barge rig. "Posted" means a posted barge rig.
(b) These rigs would require substantial refurbishment to be ready for service.
(c) In September 2003, our inland barge Rig 20 experienced a fire while working
in Lake Washington near Port Sulphur, Louisiana. The incident resulted in
the loss of drilling equipment and damage to the rig. The rig is no longer
operating and will require substantial refurbishment to return to service.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Results of Continuing Operations -- Years Ended December
31, 2003 and 2002."
(d) In June 2003, our inland barge Rig 62 experienced a well control incident,
commonly referred to as a blowout, while working in a bay near Galveston,
Texas. The rig is no longer operating and will require substantial
refurbishment to return to service. See "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Results of
Continuing Operations -- Years Ended December 31, 2003 and 2002."
(e) These rigs are not owned by us, but are bareboat chartered from a third
party. Under these bareboat charters, we charter the rigs from a third
party, operate, maintain and insure them and are obligated to return them at
the end of the charter period in accordance with the terms of the charters,
which generally require the rigs to be in the same condition as received,
ordinary wear and tear excepted. Each charter expires in February 2005.
6
Repair costs for rigs designated as cold stacked in the preceding table are
estimated to be $1.1 million per rig or less. Rigs requiring substantial
refurbishment, as noted in footnotes (b), (c) and (d) above, are estimated to
cost between $2.4 million to $4.5 million per rig to repair, except for Rig 62
which is estimated to cost approximately $7.0 million to repair. These estimated
amounts will be subject to variables including the availability and cost of
shipyard facilities, cost of equipment and materials and the actual extent of
required repairs and maintenance. Actual amounts could vary substantially.
OTHER DRILLING RIGS (16)
A submersible rig is a mobile drilling platform that is towed to the well
site where it is submerged by flooding its superstructure until it rests on the
sea floor, with the upper hull above the water surface. After completion of the
drilling operation, the rig is refloated by pumping the water out of the lower
hull, so that it can be towed to another location. Submersible rigs typically
operate in water depths of 12 to 85 feet. Our three submersible rigs are
suitable for deep gas drilling.
A platform drilling rig is placed on a production platform and is similar
to a modular land rig. The production platform's crane is capable of lifting the
modularized rig crane that subsequently sets the rig modules. The assembled rig
has all the drilling, housing and support facilities necessary for drilling
multiple production wells. Most platform drilling rig contracts are for multiple
wells and extended periods of time on the same platform. Once work has been
completed on a particular platform, the rig can be redeployed to another
platform for further work. We have one platform drilling rig.
Our nine land drilling rigs are completely equipped to drill oil and gas
wells. These rigs are designed to be transported by truck and assembled by
crane. They require a firm, level area to be erected and sometimes require
foundation work to be performed to support the drill floor and derrick.
Our three Lake Maracaibo barge rigs are designed to work in Lake Maracaibo,
Venezuela, which requires operation in a floating mode in up to 150 feet of
water. These rigs were modified by widening the hull to 100 feet, installing a
mooring system and cantilevering the drill floor. As a result of these
modifications, these rigs are generally not suitable for deployment to other
locations. None of these rigs have operated since January 2000 and future
prospects are uncertain.
The following table contains information regarding our other rigs as of
March 1, 2004:
ORIGINAL RATED
YEAR ENTERED HORSEPOWER DRILLING DEPTH
RIG TYPE(A) SERVICE/UPGRADED RATING (IN FEET) LOCATION STATUS
--- ------- ---------------- ---------- -------------- --------- --------------
THE 75............... Subm. 1983 N/A 25,000 U.S. Warm Stacked
THE 77............... Subm. 1983 N/A 30,000 U.S. Cold Stacked
THE 78............... Subm. 1983 N/A 30,000 U.S. Cold Stacked
Rig 3(b)............. Plat. 1993/1998 N/A 25,000 Trinidad Cold Stacked
26(c)................ Land 1980/1998 750 6,500 Venezuela Warm Stacked
27(c)................ Land 1981/1997 900 8,000 Venezuela Warm Stacked
36................... Land 1982 2,000 18,000 Venezuela Warm Stacked
37................... Land 1982 2,000 18,000 Venezuela Warm Stacked
40................... Land 1980 2,000 25,000 Venezuela Under Contract
42................... Land 1981 2,000 25,000 Venezuela Warm Stacked
43................... Land 1981 2,000 25,000 Venezuela Warm Stacked
54................... Land 1981 3,000 30,000 Venezuela Warm Stacked
55................... Land 1983 3,000 35,000 Venezuela Warm Stacked
40................... LMB 1980/1994 3,000 25,000 Venezuela Cold Stacked
42................... LMB 1982/1994 2,000 25,000 Venezuela Cold Stacked
43................... LMB 1982/1994 3,000 25,000 Venezuela Cold Stacked
---------------
(a) "Subm." means a submersible rig. "Plat." means a platform drilling rig.
"LMB" means a Lake Maracaibo barge rig.
(b) Our platform rig has been awarded a contract with PEMEX to begin working in
Mexico in mid-2004. The expected cost of upgrades to the platform rig
necessary to comply with the contract specifications is approximately $8
million to $10 million.
(c) These rigs are owned by a joint venture in which we have a 66.7% ownership
interest.
7
The estimated costs to prepare for service those rigs in the preceding
table that are listed as cold stacked range from $1.9 million to $5.3 million
per rig. These estimated amounts will be subject to variables including the
availability and cost of shipyard facilities, cost of equipment and materials
and the actual extent of required repairs and maintenance. Actual amounts could
vary substantially.
DRILLING CONTRACTS
Our contracts to provide 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 factors.
A dayrate drilling contract generally extends over a period of time
covering the drilling of a single well or group of wells or covering a stated
term. These contracts typically can be terminated by the customer 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 customer exercising options for the drilling of additional wells
or for an additional term, or by exercising a right of first refusal.
Historically, most of our drilling contracts have been short-term or on a
well-to-well basis. From time to time, however, we enter into longer term
drilling contracts. In the third quarter of 2003, we were awarded long term
contracts with PEMEX, the Mexican national oil company, for two of our jackup
rigs and a platform rig. After upgrades to comply with contract specifications,
one rig began operating on a 720-day contract in early November 2003 at a
contract dayrate of approximately $42,000. The other jackup rig began operating
in early December 2003 on a 1,081-day contract at a contract dayrate of
approximately $39,000. The platform rig contract is 1,289 days in duration
beginning in mid-2004 at a contract dayrate of approximately $29,000. We expect
the upgrade to the platform rig necessary to comply with contract specifications
to occur in 2004 and cost approximately $8 million to $10 million. Each of the
contracts can be terminated by PEMEX on five days' notice, subject to certain
conditions.
CUSTOMERS
We engage in offshore and inland marine drilling primarily for independent
oil and gas companies, although we also work for large international oil
companies and government-controlled oil companies. One customer, Applied
Drilling Technologies, Inc., accounted for 11% of our 2003 operating revenues.
No other customers accounted for 10% or greater of our revenues in 2003, 2002 or
2001. Nonetheless, the loss of any significant customer could, at least in the
short term, have a material adverse effect on our results of operations.
COMPETITORS
The U.S. Gulf of Mexico shallow water and U.S. inland marine market
segments in which we operate are highly competitive. In the U.S. inland marine
market segment, our principal competitor is Parker Drilling Co. In the U.S. Gulf
of Mexico shallow water market segment, we compete with numerous industry
participants, none of which has a dominant market share. Drilling contracts are
traditionally awarded on a competitive bid basis. Pricing is often the primary
factor in determining which qualified contractor is awarded a job, although rig
availability, safety record, crew quality and technical capability of service
and equipment may also be considered. Many of our competitors in the U.S. Gulf
of Mexico shallow water market segment have greater financial and other
resources than we have and may be better able to make technological improvements
to existing equipment or replace equipment that becomes obsolete.
8
OTHER ASSETS
We have a 25% equity interest in Delta Towing, which operates a U.S. inland
and shallow water marine support vessel business. Beta Marine Services, LLC owns
the remaining 75% equity interest in Delta Towing. In connection with its
formation, Delta Towing issued notes to us with principal amounts totaling $144
million, secured by Delta Towing's assets described in the following paragraph.
Immediately prior to the closing of the merger with Transocean, we valued these
notes at $80 million. Delta Towing has failed to make some of its scheduled
quarterly interest and principal payments on these notes. See "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Related Party Transactions."
Delta Towing owns and operates towing vessels and barges used primarily to
transport and store equipment and material to support jackup and barge rig
drilling operations. Delta Towing utilizes rig moving tugs, utility barges,
service tugs and crew boats in connection with its operations. Although these
assets can be deployed for other uses, any continuation of the current downturn,
or further significant downturn, in oil and gas activity in the transition zone
would have a negative impact on Delta Towing's business that could not be fully
offset by deployment of such assets to other markets. As of March 1, 2004, Delta
Towing's operating assets consisted of 52 inland tugs, 29 offshore tugs, 36
crewboats, 35 deck barges, 17 shale barges, five spud barges and three offshore
barges.
We also own additional offshore equipment that consists of five jackup
rigs, three of which are mat-supported and two which are independent leg rigs,
ranging in water depth capacity from 100 feet to 160 feet, that we do not
anticipate returning to drilling service as we believe doing so would be cost
prohibitive. In May 2003, we decided to market these units for non-drilling uses
such as production platforms or accommodation units.
REGULATION
Our operations are affected in varying degrees by governmental laws and
regulations. The drilling industry is dependent on demand for services from the
oil and gas industry and, accordingly, is also affected by changing tax and
other laws relating to the energy business generally.
The transition zone and shallow water areas of the U.S. Gulf of Mexico are
ecologically sensitive. Environmental issues have led to higher drilling costs,
a more difficult and lengthy well permitting process and, in general, have
adversely affected decisions of oil and gas companies to drill in these areas.
In the United States, regulations applicable to our operations include
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 or other unauthorized discharges of chemicals or wastes
resulting from or related to those operations. Laws and regulations protecting
the environment have become more stringent, and may in some cases impose strict
liability, rendering a person liable for environmental damage without regard to
negligence or fault on the part of such person. Some of these laws and
regulations may expose us to liability for the conduct of or conditions caused
by others or for acts which 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 financial
position or results of operations.
The U.S. Federal Water Pollution Control Act of 1972, commonly referred to
as the Clean Water Act, prohibits the discharge of specified substances into the
navigable waters of the United States without a permit. The regulations
implementing the Clean Water Act require permits to be obtained by an operator
before specified exploration activities occur. Offshore facilities must also
prepare plans addressing spill prevention control and countermeasures.
Violations of monitoring, reporting and permitting requirements can result in
the imposition of civil and criminal penalties.
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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 the liability could be substantial.
Failure to comply with ongoing requirements or inadequate cooperation in the
event of a spill 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 lease conditions or
regulations related to the environment issued pursuant to the 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 liabilities for the cost of cleaning up the
hazardous substances that have been released into the environment and for
damages to natural resources. We could be subject to liability under CERCLA
principally in connection with our onshore activities. It is also not uncommon
for third parties to file claims for personal injury and property damage
allegedly caused by the hazardous substances released into the environment.
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 importation of and operation of drilling units, currency
conversions and repatriation, oil and gas exploration and development, taxation
of offshore earnings and earnings of expatriate personnel, the use of local
employees and suppliers by foreign contractors and duties on the importation and
exportation of drilling units and other equipment. Governments in some foreign
countries have become increasingly active in regulating and controlling the
ownership of concessions and companies holding concessions, the exploration for
oil and gas and other aspects of the oil and gas industries in their countries.
In some areas of the world, this governmental activity has adversely affected
the amount of exploration and development work done by major oil and gas
companies and may continue to do so. Operations in less developed countries can
be subject to legal systems that are not as mature or predictable as those in
more developed countries, which can lead to greater uncertainty in legal matters
and proceedings.
Although significant capital expenditures may be required to comply with
these governmental laws and regulations, such compliance has not materially
adversely affected our earnings or competitive position.
EMPLOYEES
As of March 1, 2004, we had approximately 1,800 employees. We require
highly skilled personnel to operate and provide technical services and support
for our drilling units. As a result, we conduct extensive personnel recruiting,
training and safety programs.
As of March 1, 2004, approximately 114 (or 6%) of our employees worldwide
were working under collective bargaining agreements, approximately 35 of whom
were working in Trinidad and 79 of whom were working in Venezuela. Efforts have
been made from time to time to unionize other portions of our workforce,
including workers in the Gulf of Mexico.
10
RISK FACTORS
Our business, financial condition, results of operations and the trading
prices of our securities can be materially and adversely affected by many events
and conditions including the following:
RISKS RELATED TO OUR BUSINESS
Our business depends on the level of activity in the oil and gas industry in
the U.S. Gulf Coast, which is significantly affected by often volatile oil and
gas prices.
Our business depends on the level of activity in oil and gas exploration,
development and production primarily in the U.S. Gulf Coast (our term for the
U.S. Gulf of Mexico shallow water and inland marine region) where we are active.
Oil and gas prices and our customers' expectations of potential changes in these
prices significantly affect this level of activity. In particular, changes in
the price of natural gas materially affect our operations because we primarily
drill in the U.S. Gulf Coast where the focus of drilling has tended to be on the
search for natural gas. Oil and gas prices are extremely volatile and are
affected by numerous factors, including the following:
- the demand for oil and gas in the United States and elsewhere,
- economic conditions in the United States and elsewhere,
- weather conditions in the United States and elsewhere,
- advances in exploration, development and production technology,
- 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, and
- the worldwide military and political environment, including the recent
war in Iraq, uncertainty or instability resulting from an escalation or
additional outbreak of armed hostilities or other crises in the Middle
East or the geographic areas in which we operate or further acts of
terrorism in the United States, or elsewhere.
Depending on the market prices of oil and gas, companies exploring for oil
and gas may cancel or curtail their drilling programs, thereby reducing demand
for drilling services. In the U.S. Gulf Coast, drilling contracts are generally
short term, and oil and gas companies tend to respond quickly to upward or
downward changes in prices. Any reduction in the demand for drilling services
may materially erode dayrates and utilization rates for our rigs and adversely
affect our financial results.
The U.S. Gulf Coast is a mature oil and gas production region that has
experienced substantial seismic survey and exploration activity for many years.
Because a large number of oil and gas prospects in this region have already been
drilled, additional prospects of sufficient size and quality could be more
difficult to identify. In addition, oil and gas companies may be unable to
obtain financing necessary to drill prospects in this region. This could result
in reduced drilling activity in the U.S. Gulf Coast region. We expect demand for
drilling services in this area to continue to fluctuate with the cycles of
reduced and increased rig demand, and demand at similar points in future cycles
could be lower than levels experienced in past cycles.
The current level of activity in the oil and gas industry is relatively low in
our market segments, which adversely affects our dayrates and rig utilization.
The U.S. natural gas market strongly influences the level of U.S. Gulf
Coast drilling activity. U.S. natural gas prices increased significantly during
2000, which resulted in improved demand for offshore drilling rigs and increased
dayrates for rigs in the Gulf of Mexico. U.S. natural gas prices declined during
2001 and oil and gas companies reduced Gulf of Mexico exploration and
development spending beginning in the second half of
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2001. As a result, demand for drilling rigs declined, industry utilization and
dayrates for Gulf of Mexico shallow water jackup rigs and drilling barges
decreased significantly and our operations were adversely impacted. Current U.S.
Gulf Coast dayrates for jackups are significantly lower than those experienced
during 2000 and the first half of 2001, and there remains surplus rig capacity
for jackups and barges. There has not yet been an increase in drilling activity
in the U.S. Gulf Coast that corresponds to the increase in natural gas prices
since September 2002, and such an increase may not occur. The U.S. Gulf Coast
may not yet have experienced the bottom of the current drilling cycle. In
addition, dayrates and utilization may not rise to the extent of prior drilling
cycles, or at all, as prior results may not be predictive of future results. If
natural gas prices decline, demand for our drilling services could be further
reduced, which would adversely affect both utilization and dayrates.
Our industry is highly cyclical, and our results of operations may be
volatile.
Our industry is highly cyclical, with periods of high demand and high
dayrates followed by periods of low demand and low dayrates. Periods of low rig
demand 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. Due to the
short-term nature of most of our drilling contracts, changes in market
conditions can quickly affect our business. As a result of the cyclicality of
our industry, our results of operations have been volatile, and we expect this
volatility to continue.
Our industry is highly competitive, with intense price competition.
The U.S. Gulf of Mexico shallow water and inland marine market segments in
which we operate are highly competitive. Drilling contracts are traditionally
awarded on a competitive bid basis. Pricing is often the primary factor in
determining which qualified contractor is awarded a job. The competitive
environment has intensified as recent mergers among oil and gas companies have
reduced the number of available customers. Many other offshore drilling
companies are larger than we are and have more diverse fleets, or fleets with
generally higher specifications, and greater resources than we have. This allows
them to better withstand industry downturns, better compete on the basis of
price and build new rigs or acquire existing rigs, all of which could affect our
revenues and profitability. We believe that competition for drilling contracts
will continue to be intense in the foreseeable future.
An excess supply of drilling units currently exists in the U.S. Gulf Coast,
and activation of non-marketed rigs, movement of rigs to this region and
newbuilds could increase this excess.
An excess supply of jackups and other mobile offshore drilling units
currently exists in the U.S. Gulf Coast. If industry conditions improve,
inactive rigs that are not currently being marketed could be reactivated to meet
an increase in demand for drilling rigs. Improved market conditions,
particularly relative to other drilling market segments, could also lead to
jackups and other mobile offshore drilling units being moved into the U.S. Gulf
Coast or could lead to increased rig construction and rig upgrade programs by
our competitors. Some of our competitors have already announced plans to upgrade
existing equipment or build additional jackups with higher specifications than
our jackups. A significant increase in the supply of jackup rigs or other mobile
offshore drilling units could adversely affect both utilization and dayrates.
Our ability to move our rigs to other regions is limited.
Most jackup and submersible rigs can be moved from one region to another,
and in this sense the marine contract drilling market is a global market.
Because the cost of a rig move is significant, there is limited availability of
rig moving vessels and some rigs are designed to work in specific regions, the
demand/supply balance for jackup and submersible rigs may vary somewhat from
region to region. However, significant variations between regions tend not to
exist on a long-term basis due to the ability to move rigs. Because many of our
rigs were designed for drilling in the U.S. Gulf Coast, our ability to move our
rigs to other regions in response to changes in market conditions is limited.
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Our jackup rigs are at a relative disadvantage to higher specification rigs.
Many of our competitors have jackup fleets with generally higher
specification rigs than those in our jackup fleet. Particularly during market
downturns when there is decreased rig demand, higher specification jackups and
other rigs may be more likely to obtain contracts than lower specification
jackups. As a result, our lower specification jackups have in the past been
stacked earlier in the cycle of decreased rig demand than most of our
competitors' jackups and have been reactivated later in the cycle. This pattern
has adversely impacted our business and could be repeated. In addition, higher
specification rigs have greater flexibility to move to areas of demand in
response to changes in market conditions. Because many of our rigs were designed
specifically for drilling in the U.S. Gulf Coast, our ability to move them to
other regions in response to changes in market conditions is limited.
Furthermore, in recent years, an increasing amount of exploration and production
expenditures have been concentrated in deep water drilling programs and deeper
formations, including deep gas prospects, requiring higher specification
jackups, semisubmersible drilling rigs or drillships. This trend is expected to
continue and could result in a decline in demand for lower specification jackup
rigs like ours.
Our business involves numerous operating hazards, and we are not fully insured
against all of them.
Our operations are subject to the usual hazards inherent in the drilling of
oil and gas wells, such as blowouts, reservoir damage, loss of production, loss
of well control, punchthroughs, craterings, fires and pollution. The occurrence
of these events could result in the suspension of drilling operations, claims by
the operator, 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,
failure of subcontractors to perform or supply goods or services and personnel
shortages. In addition, offshore and inland marine 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. Moreover,
pollution and environmental risks generally are not totally insurable.
Following the terrorist attacks on September 11, 2001, insurance
underwriters increased insurance premiums for many of the coverages historically
maintained and issued general notices of cancellation to their customers for war
risk, terrorism and political risk insurance in respect of a wide variety of
insurance coverages, including liability and aviation coverages. Insurance
markets are volatile and the cost of insurance has generally increased
significantly for most companies in 2003 compared to prior years. We have
increased our insurance deductibles in 2003 to mitigate these rising costs.
Insurance premiums and/or deductibles could be increased further or coverages
may be unavailable in the future.
If a significant accident or other event, including terrorist acts, war,
civil disturbances, pollution or environmental damage, occurs and is not fully
covered by insurance or a recoverable indemnity from a customer, it could
adversely affect our financial position or results of operations. Moreover, we
may not 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 September 11, 2001 terrorist attacks.
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 rigs. To the extent that demand for
drilling services and the number of operating rigs increases, shortages of
qualified personnel could arise, creating upward pressure on wages and
difficulty in staffing rigs.
13
Loss of key management could hurt our operations.
Our success is to a considerable degree dependent on the services of our
key management, including Jan Rask, our President and Chief Executive Officer.
The loss of any member of our key management could adversely affect our results
of operations.
Unionization efforts could increase our costs or limit our flexibility.
A small percentage of our employee's worldwide work under collective
bargaining agreements, all of whom work in Venezuela and Trinidad. Efforts have
been made from time to time to unionize other portions of our workforce,
including workers in the Gulf of Mexico. Any such unionization could increase
our costs or limit our flexibility.
Governmental laws and regulations may add to our costs or limit drilling
activity.
Our operations are affected in varying degrees by governmental laws and
regulations. The drilling industry is dependent on demand for services from the
oil and gas industry and, accordingly, is also affected by changing tax and
other laws relating to the energy business generally. We may be required to make
significant capital expenditures to comply with laws and regulations. It is also
possible that these laws and regulations may in the future add significantly to
operating costs or may limit drilling activity.
Compliance with or a breach of environmental laws can be costly and could
limit our operations.
Our operations are subject to regulations that require us to obtain and
maintain specified permits or other governmental approvals, control the
discharge of materials into the environment, require the removal and cleanup of
materials that may harm the environment or otherwise relate 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 or other unauthorized
discharges of chemicals or wastes resulting from 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 or fault on the part of
such person. Some of 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 financial position or results of operations.
Our non-U.S. operations involve additional risks not associated with our U.S.
operations.
We operate in regions 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.
Our insurance policies and indemnity provisions in our drilling contracts
generally do not protect us from loss of revenue. If a significant accident or
other event occurs and is not fully covered by insurance or a recoverable
indemnity from a customer, it could adversely affect our financial position or
results of operations.
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, taxation of offshore
earnings and earnings of expatriate personnel, the use of local employees and
suppliers by foreign contractors and duties on
14
the importation and exportation of drilling units and other equipment.
Governments in some foreign countries have become increasingly active in
regulating and controlling the ownership of concessions and companies holding
concessions, the exploration for oil and gas and other aspects of the oil and
gas industries in their countries. In some areas of the world, this governmental
activity has adversely affected the amount of exploration and development work
done by major oil and gas companies and may continue to do so. Operations in
less developed countries can be subject to legal systems which are not as mature
or predictable as those in more developed countries, which can lead to greater
uncertainty in legal matters and proceedings.
Another risk inherent in our operations is the possibility of currency
exchange losses where revenues are received and expenses are paid in foreign
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.
Our Venezuela operations are subject to adverse political and economic
conditions, and our Venezuelan lake barges would require substantial
refurbishment to return to service.
A portion of our operations is conducted in the Republic of Venezuela,
which has been experiencing political and economic turmoil, including labor
strikes and demonstrations, and in 2002 experienced an attempt to overthrow the
government. The implications and results of the political, economic and social
instability in Venezuela are uncertain at this time, but the instability could
have an adverse effect on our business. Depending on future developments, we
could decide to cease operations in Venezuela. Venezuela has also implemented
foreign exchange controls that limit our ability to convert local currency into
U.S. dollars and transfer excess funds out of Venezuela. Our drilling contracts
in Venezuela typically call for payments to be made in local currency, even when
the dayrate is denominated in U.S. dollars. The exchange controls could also
result in an artificially high value being placed on the local currency. As of
December 31, 2003, we had working capital in Venezuela of approximately $5.1
million, including $3.9 million in U.S. dollar denominated spare parts inventory
and $4.9 million in U.S. dollar denominated accounts receivable, and our total
assets in Venezuela had a net book value of $53.5 million (including a joint
venture interest). One of our nine land rigs located in Venezuela was operating
as of March 1, 2004. None of our lake barges in Venezuela have operated since
January 2000. If or when those barges will return to work is uncertain, and all
of these barges would require substantial refurbishment to be ready for service.
RISKS RELATED TO OUR PRINCIPAL STOCKHOLDER TRANSOCEAN
Transfers of our common stock by Transocean could adversely affect other
stockholders and cause our stock price to decline.
Transocean will be permitted to transfer a controlling interest in us
without allowing other stockholders to participate or realize a premium for
their shares of common stock. For a description of Transocean's current plans
with respect to our common stock that it will continue to own after the closing
of the IPO, see "Management Discussion and Analysis -- IPO and Separation from
Transocean." A sale of a controlling interest to a third party may adversely
affect the market price of our common stock and our business and results of
operations because the change in control may result in a change of management
decisions and business policy.
We will be controlled by Transocean as long as it owns a majority of the
voting power of our outstanding common stock, and other stockholders will be
unable to affect the outcome of stockholder voting during that time.
As long as Transocean owns, directly or indirectly, a majority of the
voting power of our outstanding common stock, Transocean will be able to exert
significant control over us, including the ability to elect or remove and
replace our entire board of directors and take other actions without calling a
special meeting. Other stockholders, by themselves, will not be able to affect
the outcome of any stockholder vote. As a result,
15
Transocean, subject to any fiduciary duty owed to our minority stockholders
under Delaware law, will be able to control all matters affecting us, including:
- the composition of our board of directors and, through it, any
determination with respect to our business direction and policies,
including the appointment and removal of officers,
- the determination of incentive compensation, which may affect our ability
to retain key employees,
- the allocation of business opportunities between Transocean and us,
- any determinations with respect to mergers or other business
combinations,
- our acquisition or disposition of assets,
- our financing decisions and our capital raising activities,
- the payment of dividends on our common stock,
- amendments to our amended and restated certificate of incorporation or
bylaws, and
- determinations with respect to our tax returns.
In addition, Transocean may enter into credit agreements, indentures or other
contracts that limit our activities and the activities of Transocean's other
subsidiaries. Transocean's representatives on our board could direct our
business so as not to breach any of these agreements.
Transocean is generally not prohibited from selling a controlling interest
in us to a third party. Because of exemptions granted under our rights agreement
and because we have elected not to be subject to Section 203 of the General
Corporation Law of the State of Delaware, Transocean, as a controlling
stockholder, may find it easier to sell its controlling interest to a third
party than if we had not taken such actions.
Our interests may conflict with those of Transocean with respect to our past
and ongoing business relationships, and because of Transocean's initial
controlling ownership, we may not be able to resolve these conflicts on terms
commensurate with those possible in arms-length transactions.
Our interests may conflict with those of Transocean in a number of areas
relating to our past and ongoing relationships, including:
- the solicitation and hiring of employees from each other,
- the timing and manner of any sales or distributions by Transocean of all
or any portion of its ownership interest in us,
- agreements with Transocean and its affiliates relating to corporate
services that may be material to our business,
- business opportunities that may be presented to Transocean and to our
officers and directors associated with Transocean,
- competition between Transocean and us within the same lines of business,
and
- our dividend policy.
We may not be able to resolve any potential conflicts with Transocean, and
even if we do, the resolution may be less favorable than if we were dealing with
an unaffiliated party. Our certificate of incorporation provides that Transocean
has no duty to refrain from engaging in activities or lines of business similar
to ours and that Transocean and its officers and directors will not be liable to
us or our stockholders for failing to present specified corporate opportunities
to us. In addition, in the master separation agreement, we agree not to compete
with Transocean in specified lines of business. See "Certain Relationships and
Related Party Transactions -- Relationship Between Us and Transocean -- Master
Separation Agreement -- Noncompetition and Other Covenants."
16
The terms of our separation from Transocean, the related agreements and other
transactions with Transocean were determined in the context of a
parent-subsidiary relationship and thus may be less favorable to us than the
terms we could have obtained from an unaffiliated third party.
Transactions and agreements entered into after our acquisition by
Transocean and on or before the closing of the IPO presented conflicts between
our interests and those of Transocean. These transactions and agreements
included the following:
- agreements related to the separation of our business from Transocean that
will provide for, among other things, the assumption by us of liabilities
related to our business, the assumption by Transocean of liabilities
unrelated to our business, our respective rights, responsibilities and
obligations with respect to taxes and tax benefits and the terms of our
various interim and ongoing relationships, as described under "Certain
Relationships and Related Party Transactions -- Relationship Between Us
and Transocean,"
- the transfer to Transocean of assets that are not related to our
business, as described under "Certain Relationships and Related Party
Transactions -- Asset Transfers to Transocean," "Certain Relationships
and Related Party Transactions -- Relationship Between Us and
Transocean -- Master Separation Agreement -- TODCO Business,
and -- Transfer of Assets and Assignment of Liabilities," and
- charters of drilling units with Transocean, borrowings from Transocean,
administrative support services provided by Transocean to us and other
transactions with Transocean, as described under "Certain Relationships
and Related Party Transactions."
Because these transactions and agreements were entered into in the context
of a parent-subsidiary relationship, their terms may be less favorable to us
than the terms we could have obtained from an unaffiliated third party. In
addition, while we are controlled by Transocean, it is possible for Transocean
to cause us to amend these agreements on terms that may be less favorable to us
than the current terms of the agreements. We may not be able to resolve any
potential conflict, and even if we do, the resolution may be less favorable than
if we were dealing with an unaffiliated party. See "Certain Relationships and
Related Party Transactions -- Relationship Between Us and Transocean."
Most of our executive officers and most of our directors may have potential
conflicts of interest because of their ownership of Transocean ordinary shares
or their role as directors or executive officers of Transocean.
Some of our executive officers and directors own Transocean ordinary shares
or options to purchase Transocean ordinary shares, which are of greater value
than their ownership of our common stock and options. Ownership of Transocean
ordinary shares by our directors and executive officers could create, or appear
to create, potential conflicts of interest when directors and executive officers
are faced with decisions that could have different implications for Transocean
than they do for us.
Most of our directors also serve as directors or executive officers of
Transocean. These directors owe fiduciary duties to the shareholders of each
company. As a result, in connection with any transaction or other relationship
involving both companies, these directors may need to recuse themselves and not
participate in any board action relating to these transactions or relationships.
Our tax sharing agreement with Transocean Holdings could require substantial
payments by us in the event that a third party becomes the owner of a majority
of our voting power or any of our subsidiaries are deconsolidated.
Our tax sharing agreement with Transocean Holdings provides that we must
pay Transocean for substantially all pre-closing tax benefits utilized
subsequent to the closing of the IPO. See "Certain Relationships and Related
Party Transactions -- Relationship Between Us and Transocean -- Tax Sharing
Agreement." As of December 31, 2003, we had approximately $450 million of
pre-closing tax benefits subject to our obligation to reimburse Transocean. This
amount includes approximately $173 million of the tax benefits reflected in our
December 31, 2003 historical financial statements and additional tax benefits
that we
17
expect to result from the closing of the IPO, specified ownership changes,
statutory allocations of the tax benefits among Transocean Holdings'
consolidated group members and other events. See Note 12 to our consolidated
financial statements included in Item 8 of this report. The tax sharing
agreement also provides that if any person other than Transocean or its
subsidiaries becomes the beneficial owner of greater than 50% of the total
voting power of our outstanding voting stock, we will be deemed to have utilized
all of these pre-closing tax benefits, and we will be required to pay Transocean
Holdings an amount for the deemed utilization of these tax benefits adjusted by
a specified discount factor.
If an acquisition of beneficial ownership had occurred on December 31,
2003, the estimated amount that we would have been required to pay to Transocean
would have been approximately $360 million. We may not have the ability to
prevent or influence a transaction requiring this payment, particularly in the
case of an acquisition by a third party of a substantial amount of voting stock
from Transocean. Our requirement to make this payment could have the effect of
delaying or preventing a change of control.
Our tax sharing agreement with Transocean Holdings also provides that if
any of our subsidiaries that join with us in the filing of consolidated returns
ceases to do so, we will be deemed to have used that portion of any pre-closing
tax benefits that will be allocable to the subsidiary following that cessation,
and we will generally be required to pay Transocean Holdings the amount of this
deemed tax benefit, adjusted by a specified discount factor, at the time the
subsidiary ceases to join in the filing of these returns.
Payment of amounts for the deemed utilization of tax benefits by us could
require additional financing. The amount of our payments to Transocean will not
be adjusted for any difference between the tax benefits that we are deemed to
utilize and the tax benefits that we actually utilize, and the difference
between these amounts could be substantial. Among other considerations,
applicable tax laws may, as a result of another person becoming the owner of
greater than 50% of the total voting power of our outstanding voting stock,
significantly limits our use of these tax benefits, and these limitations are
not taken into account in determining the amount of the payment to Transocean.
Additionally, Transocean Holdings' right to receive this payment could result in
a conflict of interest between us and Transocean and for those of our directors
who are officers or directors of Transocean in considering any potential
transaction.
Our tax sharing agreement with Transocean Holdings could delay or preclude us
from realizing tax benefits created after the closing of the IPO.
Our tax sharing agreement with Transocean Holdings provides that we must
pay Transocean Holdings for most pre-closing tax benefits that we utilize on a
tax return with respect to a period after the closing of the IPO. If the
utilization of a pre-closing tax benefit defers or precludes our utilization of
any post-closing tax benefit, our payment obligation with respect to the
pre-closing tax benefit generally will be deferred until we actually utilize
that post-closing tax benefit. This payment deferral will not apply with respect
to, and we will have to pay currently for the utilization of pre-closing tax
benefits to the extent of,
- up to 20% of any deferred or precluded post-closing tax benefit arising
out of our payment of foreign income taxes, and
- 100% of any deferred or precluded post-closing tax benefit arising out of
a carryback from a subsequent year.
Therefore, we may not realize the full economic value of tax deductions, credits
and other tax benefits that arise post-closing until we have utilized all of the
pre-closing tax benefits, if ever.
RISKS RELATED TO OUR SEPARATION FROM TRANSOCEAN
We anticipate incurring substantial losses during industry downturns and may
need additional financing to withstand industry downturns.
Our net losses from continuing operations before cumulative effect of a
change in accounting principle were approximately $222 million and $529 million
during the years ended December 31, 2003 and 2002, respectively, and we
anticipate incurring substantial losses during future cyclical downturns in our
industry. As
18
of December 31, 2003, we had a working capital deficit of approximately $2.6
million. We did not receive any of the proceeds from the IPO. During cyclical
downturns in our industry, we may need additional financing in order to satisfy
our cash requirements. If we are not able to obtain financing in sufficient
amounts and on acceptable terms, we may be required to reduce our business
activities, seek financing on unfavorable terms or pursue a business combination
with another company.
We do not have a recent history of operating as a stand-alone company, we may
encounter difficulties in making the changes necessary to operate as a
stand-alone company, and we may incur greater costs as a stand-alone company
that may adversely affect our results.
Since our merger with Transocean and prior to our separation, Transocean
performed various corporate functions for us, including the following:
- information technology and communications,
- human resource services such as payroll and benefit plan administration,
- legal,
- tax,
- accounting,
- office space and office support,
- risk management,
- treasury and corporate finance, and
- investor services, investor relations and corporate communications.
Since the separation, Transocean has no obligation to provide these
functions to us other than the interim services that will be provided by
Transocean and which are described in "Certain Relationships and Related Party
Transactions -- Relationship Between Us and Transocean." Under the transition
services agreement, we are required to use Transocean's accounting and
information technology systems for so long as Transocean owns at least 50% of
the voting power of our voting stock. We are in the process of creating, or
engaging third parties to provide, our own systems and business functions to
replace many of the systems and business functions Transocean provides and we
may incur difficulties in the replacement process. We may also incur higher
costs for these functions than the amounts we were allocated as a wholly owned
subsidiary of Transocean. If we do not have in place our own systems and
business functions or if we do not have agreements with other providers of these
services once our interim services agreement with Transocean expires, we may
operate our business less efficiently and our results may suffer.
Substantial sales of our common stock by Transocean or us could cause our
stock price to decline and issuances by us may dilute the ownership interest
of existing stockholders in our company.
We are unable to predict whether significant amounts of our common stock
will be sold by Transocean after the IPO. Any sales of substantial amounts of
our common stock in the public market by Transocean or us, or the perception
that these sales might occur, could lower the market price of our common stock.
Further, if we issue additional equity securities to raise additional capital,
investor's ownership interest in our company may be diluted and the value of
their investment may be reduced.
The disparate voting rights of our Class A common stock and Class B common
stock may adversely affect the value and liquidity of our Class A common
stock.
The differential in the voting rights of the Class A common stock and Class
B common stock both prior to and following any spin-off, exchange offer or sale
of Class B common stock by Transocean could adversely affect the value of our
Class A common stock to the extent that investors or any potential future
purchaser of our common stock ascribes value to the superior voting rights of
our Class B common stock. The existence of
19
two separate classes of common stock could result in less liquidity for either
class of common stock than if there were only one class of common stock. In
particular, the consummation of a complete spin-off or exchange offer by
Transocean of its Class B common stock could result in decreased liquidity for
the Class A common stock as investors may prefer the more liquid Class B common
stock. This greater liquidity could also cause the Class B common stock to trade
at a higher market price than the Class A common stock.
We have no plans to pay regular dividends on our common stock, so stockholders
may not receive funds without selling their common stock.
We have no plans to pay regular dividends on our common stock. We generally
intend to invest our future earnings, if any, to fund our growth. Any payment of
future dividends will be at the discretion of our board of directors and will
depend on, among other things, our earnings, financial condition, capital
requirements, level of indebtedness, statutory and contractual restrictions
applying to the payment of dividends, and other considerations that our board of
directors deems relevant. Our credit facility also includes limitations on our
payment of dividends. Accordingly, investors may have to sell some or all of
their common stock in order to generate cash flow from their investment.
Investors may not receive a gain on their investment when they sell our common
stock and may lose the entire amount of the investment.
Our rights agreement, provisions in our charter documents or Delaware law may
inhibit a takeover, which could adversely affect the value of our Class A
common stock.
Our amended and restated certificate of incorporation, bylaws and rights
agreement, as well as Delaware corporate law, contain provisions that could
delay or prevent a change of control or changes in our management that a
stockholder might consider favorable. Many of these provisions, though not our
rights agreement, become effective at the time Transocean ceases to own a
majority of the voting power of our outstanding common stock. These provisions
apply even if the offer may be considered beneficial by some of our
stockholders. If a change of control or change in management is delayed or
prevented, the market price of our Class A common stock could decline.
ITEM 2. PROPERTIES
We maintain our principal executive offices in Houston, Texas and have
operational offices in Houma, Louisiana; Maturin, Venezuela; La Romaine,
Trinidad and Ciudad del Carmen, Mexico. We also have warehouse and yard
facilities in Abbeville, Louisiana; Broussard, Louisiana; La Romaine, Trinidad
and Maturin, Venezuela. We lease all of these facilities, except for the
warehouse and yard facilities in Abbeville and Maturin.
ITEM 3. LEGAL PROCEEDINGS
In October 2001, we were notified by the U.S. Environmental Protection
Agency ("EPA") that the EPA had identified one of our subsidiaries as a
potentially responsible party in connection with the Palmer Barge Line superfund
site located in Port Arthur, Jefferson County, Texas. Based upon the information
provided by the EPA and our review of our internal records to date, we dispute
our designation as a potentially responsible party and do not expect that the
ultimate outcome of this case will have a material adverse effect on our
business or consolidated financial position. We continue to monitor this matter.
In December 2002, we received an assessment for corporate income taxes in
Venezuela of approximately $16 million (based on current exchange rates)
relating to calendar years 1998 through 2000. In March 2003, we paid
approximately $2.6 million of the assessment, plus approximately $0.3 million in
interest, and are contesting the remainder of the assessment. The resolution of
this assessment is not expected to impact us as Transocean is obligated to
indemnify us against any payments so long as we cooperate and provide assistance
to Transocean in the resolution of the assessment. See "Certain Relationships
and Related Party Transactions -- Relationship Between Us and Transocean -- Tax
Sharing Agreement."
In connection with our separation from Transocean, Transocean has agreed to
indemnify us for any losses we incur as a result of the legal proceedings
described in the following three paragraphs. See "Certain
20
Relationships and Related Party Transactions -- Relationship Between Us and
Transocean -- Master Separation Agreement -- Indemnification and Release."
In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and
Samuel Geary and Associates Inc. against our subsidiary Cliffs Drilling, its
underwriters at Lloyd's (the "Underwriters") and its insurance broker in the
16th Judicial District Court of St. Mary Parish, Louisiana. The plaintiffs
alleged damages in excess of $50 million in connection with the drilling of a
turnkey well in 1995 and 1996. The case was tried before a jury in January and
February 2000, and the jury returned a verdict of approximately $30 million in
favor of the plaintiffs for excess drilling costs, loss of insurance proceeds,
loss of hydrocarbons, expenses and interest. We and the Underwriters appealed
such judgment, and the Louisiana Court of Appeals reduced the amount for which
we may be responsible to less than $10 million. The plaintiffs requested that
the Supreme Court of Louisiana consider the matter and reinstate the original
verdict. We and the Underwriters also appealed to the Supreme Court of Louisiana
requesting that the Court reduce the verdict or, in the case of the
Underwriters, eliminate any liability for the verdict. Prior to the Supreme
Court of Louisiana ruling on these petitions, we settled with the St. Mary group
of plaintiffs and the State of Louisiana. Subsequently, the Supreme Court of
Louisiana denied the applications of all remaining parties. We have settled with
all remaining plaintiffs. We believe that any amounts, apart from a small
deductible, paid in settlement are covered by relevant primary and excess
liability insurance policies. However, the insurers and Underwriters have denied
all coverage. We have instituted litigation against those insurers and
Underwriters to enforce our rights under the relevant policies. One group of
insurers has asserted a counterclaim against us claiming that they issued the
policy as a result of a misrepresentation. The settlements did not have a
material adverse effect on our business or consolidated financial position, and
we do not expect that the ultimate outcome of the case involving the insurers
and Underwriters will have a material adverse effect on our business or
consolidated financial position.
In 1984, in connection with the financing of the corporate headquarters, at
that time, for Reading & Bates Corporation ("R&B"), a predecessor to one of our
subsidiaries, in Tulsa, Oklahoma, the Greater Southwestern Funding Corporation
("Southwestern") issued and sold, among other instruments, Zero Coupon Series B
Bonds due 1999-2009 with an aggregate $189 million value at maturity. Paine
Webber Incorporated purchased all of the Series B Bonds for resale and in 1985
acted as underwriter in the public offering of most of these bonds. The proceeds
from the sale of the bonds were used to finance the acquisition and construction
of the headquarters. R&B's rental obligation was the primary source for
repayment of the bonds. In connection with the offering, R&B entered into an
indemnification agreement indemnifying Southwestern and Paine Webber from loss
caused by any untrue statement or alleged untrue statement of a material fact or
the omission or alleged omission of a material fact contained or required to be
contained in the prospectus or registration statement relating to that offering.
Several years after the offering, R&B defaulted on its lease obligations, which
led to a default by Southwestern. Several holders of Series B bonds filed an
action in Tulsa, Oklahoma in 1997 against several parties, including Paine
Webber, alleging fraud and misrepresentation in connection with the sale of the
bonds. In response to a demand from Paine Webber in connection with that lawsuit
and a related lawsuit, R&B agreed in 1997 to retain counsel for Paine Webber
with respect to only that part of the referenced cases relating to any alleged
material misstatement or omission relating to R&B made in certain sections of
the prospectus or registration statement. The agreement to retain counsel did
not amend any rights and obligations under the indemnification agreement. There
has been only limited progress on the substantive allegations of the case. The
trial court has denied class certification, and the plaintiffs' appeal of this
denial to a higher court has been denied. The plaintiffs have further appealed
that decision. We dispute that there are any matters requiring us to indemnify
Paine Webber. In any event, we do not expect that the ultimate outcome of this
matter will have a material adverse effect on our business or consolidated
financial position.
In April 2003, Gryphon Exploration Company ("Gryphon") filed suit against
some of our subsidiaries, Transocean and other third parties in the United
States District Court in Galveston, Texas claiming damages in excess of $6
million. In its complaint, Gryphon alleges the defendants were responsible for
well problems experienced by Gryphon with respect to a well in the Gulf of
Mexico drilled by our subsidiaries in 2001. We dispute the allegations of
Gryphon and intend to vigorously defend this claim. While we continue to
21
investigate this matter, we do not currently expect the ultimate outcome of this
matter to have a material adverse effect on our business or consolidated
financial position.
We and our subsidiaries are involved in a number of other lawsuits, all of
which have arisen in the ordinary course of our business. We do not believe that
ultimate liability, if any, resulting from any such other pending litigation
will have a material adverse effect on our business or consolidated financial
position.
We cannot predict with certainty the outcome or effect of any of the
litigation or regulatory matters specifically described above or of any other
pending 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
There were no matters submitted to a vote of our sole shareholder,
Transocean Holdings, in 2003. On February 2, 2004, Transocean Holdings acted on
several matters by unanimous written consent. The following matters were acted
upon:
1) Related Transactions -- Transocean Holdings ratified all of the
transactions between us and Transocean and its affiliates which took place
during 2003 and 2004 in anticipation of our IPO. See "Certain Relationships
and Related Party Transactions -- Asset Transfers to Transocean," "Debt
Retirement and Debt Exchange Offers," "Revolving Credit Agreement," and
"Administrative Support Services."
2) Third Amended and Restated Certificate of Incorporation -- The
shareholder approved our Third Amended and Restated Certificate of
Incorporation which has been filed with the Secretary of State of Delaware.
3) Long Term Incentive Plan -- The shareholder approved our Long Term
Incentive Plan.
4) Election of Directors -- The shareholder elected Messrs. J. Michael
Talbert, Robert L. Long, Gregory L. Cauthen and Jan Rask as directors of
the Company. There were no other continuing directors at that time.
5) Ratification of Prior Acts -- The shareholder ratified any and all
actions taken by our directors from and after January 31, 2001.
6) Indemnification Agreements -- The shareholder approved the forms of
indemnification agreements to be entered into between us and our directors
and authorized management to deliver executed agreements in such form to
each of our directors.
7) TODCO Rights Plan -- The shareholder approved the rights agreement
between us and the Bank of New York.
Since Transocean Holdings was the Company's sole shareholder at the time of
the meeting, 100% of the Company's shares were voted to approve the matters
considered.
22
PART II
ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS
On February 4, 2004, our initial public offering of 12,000,000 shares of
our Class A common stock was priced at $12.00 per share. Our Class A common
stock began trading on the New York Stock Exchange on February 5, 2004 under the
symbol "THE". On February 10, 2004, the underwriters exercised their over-
allotment option for 1,800,000 shares, and we completed our initial public
offering of 13,800,000 shares of our Class A common stock. We did not receive
any proceeds from the IPO. Prior to the IPO, no public market existed for our
shares. There is no trading market for our Class B common stock, all outstanding
shares of which are owned by Transocean.
Our authorized capital stock consists of (1) 500,000,000 shares of Class A
common stock, par value $.01 per share, and 260,000,000 shares of Class B common
stock, par value $.01 per share, and (2) 50,000,000 shares of preferred stock,
par value $.01 per share. Of the 500,000,000 authorized shares of Class A common
stock, 13,800,000 were issued in connection with the IPO. Of the 50,000,000
shares of preferred stock, 756,000 shares have been designated Series A
preferred stock. In conjunction with the IPO, we granted 294,175 shares of
restricted stock awards to certain employees and directors. At March 1, 2004,
14,092,286 shares of Class A common stock and 46,200,000 shares of Class B
common stock are outstanding. There are no outstanding shares of preferred
stock. The holders of Class A common stock and Class B common stock generally
have identical rights, except that holders of Class A common stock are entitled
to one vote per share while holders of Class B common stock are entitled to five
votes per share on all matters on which stockholders are permitted to vote.
For the period from and including February 5, 2004, to March 1, 2004, the
high sale price for our Class A common stock was $15.15 and the low price was
$13.10.
As of March 1, 2004, our Class A common stock was held of record by
approximately 164 shareholders of record and approximately 3,061 beneficial
owners. On March 1, 2004, the last reported sales price of our Class A common
stock was $15.15 per share.
We do not intend to declare or pay regular dividends on our common stock in
the foreseeable future. Instead, we generally intend to invest any future
earnings in our business. Subject to Delaware law, our board of directors will
determine the payment of future dividends on our common stock, if any, and the
amount of any dividends in light of any applicable contractual restrictions
limiting our ability to pay dividends, our earnings and cash flows, our capital
requirements, our financial condition, and other factors our board of directors
deems relevant. Our credit facility includes limitations on our payment of
dividends. See "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Historical Liquidity and Capital Resources -- Sources
of Liquidity and Capital Expenditures."
In February 2004, prior to our IPO, we exchanged $45,784,000 in principal
amount of our outstanding 7.375% notes held by Transocean Holdings for 359,638
shares of our Class B common stock (4,367,714 shares of Class B common stock
after giving effect to the stock dividend discussed below). Immediately
following this exchange we exchanged $152,463,000 and $289,793,000 principal
amount of our outstanding 6.75% and 9.5% notes, respectively, held by Transocean
for 3,580,768 shares of the Company's Class B common stock (43,487,535 shares of
Class B common stock after giving effect to the stock dividend). Immediately
following these two exchanges, we declared a dividend of 11.145 shares of our
Class B common stock with respect to each share of our Class B common stock
outstanding immediately following the exchanges. As a result, 60,000,000 shares
of our Class B common stock were issued and outstanding immediately prior to our
IPO. Of those 60,000,000 Class B shares, 13,800,000 were converted to Class A
when these were sold in the IPO. Transocean and Transocean Holdings hold the
46,200,000 shares of our Class B common stock which remain outstanding as of
March 1, 2004. The Class B common stock is convertible at any time into shares
of our Class A common stock on a share per share basis at the sole option of
Transocean. The shares for debt exchanges were exempt from registration pursuant
to Section 4(2) of the Securities Act of 1933. See Note 24 to our consolidated
financial statements included in Item 8 of this report.
23
ITEM 6. SELECTED FINANCIAL DATA
We prepared the selected historical financial data in the following table
using our consolidated financial statements. We prepared the historical
statement of operations data for the years ended December 31, 2002 and 2003, the
one month ended January 31, 2001 and the eleven months ended December 31, 2001
and the consolidated balance sheet data as of December 31, 2000, 2001, 2002 and
2003 from our audited financial statements, included in Item 8 of this report.
We prepared the historical statement of operations data for the year ended
December 31, 1999 and the historical balance sheet data as of December 31, 1999
from our unaudited consolidated financial statements.
The following selected historical financial data should be read in
conjunction with "Management's Discussion and Analysis of Financial Condition
and Results of Operations" and our consolidated financial statements and the
related notes included in Item 8 of this report.
On January 31, 2001, we became an indirect wholly owned subsidiary of
Transocean as a result of our merger transaction with Transocean. The merger was
accounted for as a purchase, with Transocean as the accounting acquirer. The
purchase price was allocated to our assets and liabilities based on their
estimated fair values on the date of the merger with the excess accounted for as
goodwill. The purchase price adjustments were "pushed down" to our consolidated
financial statements. Accordingly, our financial statements for periods
subsequent to January 31, 2001 are not comparable to those of prior periods in
material respects since those financial statements report financial position,
results of operations and cash flows using a different basis of accounting.
PRE-TRANSOCEAN MERGER POST-TRANSOCEAN MERGER
-------------------------------- -------------------------------------
ELEVEN
YEARS ENDED ONE MONTH MONTHS YEARS ENDED DECEMBER
DECEMBER 31, ENDED ENDED 31,
------------------ JANUARY 31, DECEMBER 31, ----------------------
1999 2000 2001 2001 2002 2003
------- ------- ----------- ------------ --------- ---------
(IN MILLIONS, EXCEPT PER SHARE)
HISTORICAL STATEMENT OF OPERATIONS DATA:
Operating revenues........................... $ 406.5 $ 406.1 $ 48.5 $ 441.0 $ 187.8 $ 227.7
Operating and maintenance expense............ 324.2 317.4 23.2 270.0 185.7 227.4
Loss from continuing operations before
cumulative effect of a change in accounting
principle.................................. (139.0)(a) (131.9) (90.1)(b) (96.7)(c) (529.1)(d) (222.0)(e)
Loss from continuing operations before
cumulative effect of a change in accounting
principle and after preferred share
dividends per common share basic and
diluted.................................... $ (0.90) $ (1.72) $ (0.43) $ (7.96) $ (43.57) $ (18.28)
Weighted average common shares outstanding:
Basic...................................... 192.7 196.6 211.3 12.1 12.1 12.1
Diluted.................................... 192.7 196.6 211.3 12.1 12.1 12.1
PRE-TRANSOCEAN
MERGER POST-TRANSOCEAN MERGER
------------------- -----------------------------
AS OF DECEMBER 31, AS OF DECEMBER 31,
------------------- -----------------------------
1999 2000 2001 2002 2003
-------- -------- -------- -------- -------
(IN MILLIONS)
BALANCE SHEET DATA:
Total assets.............................................. $4,924.3 $4,804.4 $8,838.8 $2,227.2 $ 778.2
Long-term debt (including current portion) and redeemable
preferred shares........................................ 2,979.5 2,702.9 1,538.0 40.7 26.8
Long-term debt -- related party........................... -- -- 55.0 1,080.1 525.0
Total shareholders' equity................................ 1,194.7 1,373.5 6,496.5 561.9 137.7
---------------
(a)Included in 1999 is a $2.6 million loss on retirement of debt.
(b)Included in the one month ended January 31, 2001 are $58.1 million of merger
related expenses and a $64.0 million impairment loss on long-lived assets
related to the disposal of the marine support vessel business.
(c)Included in the eleven months ended December 31, 2001 are a $1.1 million
impairment loss on long-lived assets and a $27.5 million loss on retirement
of debt.
(d)Included in 2002 are a $17.5 million impairment loss on long-lived assets, a
$381.9 million goodwill impairment and a $18.8 million loss on retirement of
debt.
(e)Included in 2003 is an $11.6 million impairment loss on long-lived assets, a
$21.3 million impairment loss on a note receivable from an unconsolidated
joint venture and a $79.5 million loss on retirement of debt.
24
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following discussion should be read in conjunction with our historical
consolidated financial statements and the related notes included in Item 8 of
this report. Except for the historical financial information contained herein,
the matters discussed below may be considered "forward-looking" statements.
Please see "-- Cautionary Statement About Forward-Looking Statements," for a
discussion of the uncertainties, risks and assumptions associated with these
statements.
OVERVIEW OF OUR BUSINESS
We are a leading provider of contract oil and natural gas drilling
services, primarily in the U.S. Gulf of Mexico shallow water and inland marine
region, an area that we refer to as the U.S. Gulf Coast. We provide these
services primarily to independent oil and natural gas companies, but we also
service major international and government-controlled oil and natural gas
companies. Our customers in the U.S. Gulf Coast typically focus on drilling for
natural gas.
We provide contract oil and gas drilling services and report the results of
those operations in three business segments which correspond to the principal
geographic regions in which we operate:
- U.S. Inland Barge Segment -- Our barge rig fleet currently operating in
this market segment consists of 12 conventional and 18 posted barge rigs.
These units operate in marshes, rivers, lakes and shallow bay or costal
waterways that are known as "transition zone". This area along the U.S.
Gulf Coast, where jackup rigs are unable to operate, is the world's
largest market for this type of equipment.
- U.S. Gulf of Mexico Segment -- We currently operate 19 jackup and three
submersible rigs in the U.S. Gulf of Mexico shallow water market segment
which begins at the outer limit of the transition zone and extends to
water depths of about 350 feet. Our jackup rigs in this market segment
consist of independent leg cantilever type units, mat-supported
cantilever type rigs and mat-supported slot type jackup rigs that can
operate in water depths up to 250 feet.
- Other International Segment -- Our other operations are currently
conducted in Mexico, Trinidad and Venezuela. In Mexico, we operate two
jackup rigs and are preparing our platform rig to operate for PEMEX, the
Mexican national oil company. Additionally, we have two jackup rigs in
Trinidad and one in Venezuela, where we also have nine land rigs and
three Lake Maracaibo barges.
Our operating revenues are based on dayrates received for our drilling
services and the number of operating days during the relevant periods. The level
of our operating revenues depends on dayrates, which in turn are primarily a
function of industry supply and demand for drilling units in the market segments
in which we operate. Supply and demand for drilling units in the U.S. Gulf
Coast, which is our primary operating region, has historically been volatile.
During periods of high demand, our rigs typically achieve higher utilization and
dayrates than during periods of low demand.
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,
freight costs, repair and maintenance, insurance, general taxes and licenses,
boat and helicopter rentals, communications, tool rentals and services. Labor,
repair and maintenance and insurance costs represent the most significant
components of our operating and maintenance costs.
We do not expect operating and maintenance expenses to necessarily
fluctuate in proportion to changes in operating revenues because we seek to
preserve crew continuity and maintain equipment when our rigs are idle. In
general, labor costs increase primarily due to higher salary levels, rig
staffing requirements and inflation. Equipment maintenance expenses fluctuate
depending upon the type of activity the unit is performing and the age and
condition of the equipment. In addition, due to unfavorable insurance market
conditions and the resulting increase in premiums, our insurance deductibles
increased effective December 2002. Our current deductible level under our hull
and machinery and our protection and indemnity policies is $10.0 million per
occurrence, compared to recent historical deductibles that ranged from $0.5
million to $1.0 million per occurrence.
25
INDUSTRY BACKGROUND, TRENDS AND OUTLOOK
The drilling industry in the U.S. Gulf Coast is highly cyclical and is
typically driven by general economic activity and changes in actual or
anticipated oil and gas prices. We believe that both our earnings and demand for
our rigs will typically be correlated to our customers' expectations of energy
prices, particularly natural gas prices, and that sustained energy price
increases will generally have a positive impact on our earnings.
We believe that the drilling industry is emerging from a cyclical low point
and that there are several trends that should benefit our operations, including:
- Increasing Natural Gas Prices. While U.S. natural gas prices are
volatile, the rolling twelve-month average price of natural gas has
generally trended upward from January 1994 to December 2003. We believe
recent increases in natural gas pricing in the United States, if
sustained, should result in more exploration and development drilling
activity and higher utilization and dayrates for drilling companies like
us.
- Need for Increased Natural Gas Drilling Activity. From 1994 to 2002,
U.S. demand for natural gas grew at an annual rate of 1.1% while its
supply grew at an annual rate of 0.2%. We believe that this supply and
demand imbalance will continue if demand for natural gas continues to
increase and production decline rates continue to accelerate. Even though
the number of U.S. gas wells drilled has increased overall in recent
years, a corresponding increase in production has not been realized. We
believe that an increase in U.S. drilling activity will be required for
the natural gas industry to meet the expected increased demand for, and
compensate for the slowing production of, natural gas in the United
States.
- Trend Towards Drilling Deeper Shallow Water Gas Wells. A current trend
by oil and gas companies is to drill deep gas wells along the U.S. Gulf
Coast in search of new and potentially prolific untapped natural gas
reserves. We believe that this trend towards deeper drilling will benefit
premium jackup rigs as well as barge rigs and submersible rigs that are
capable of drilling deep gas wells. In addition, the trend will
indirectly benefit conventional jackup fleets as the use of premium rigs
in the U.S. Gulf Coast to drill deep wells should reduce the supply of
rigs available to drill conventional wells.
- Redeployment of Jackup Rigs. Greater demand for jackup rigs in
international areas over the last two years has reduced the overall
supply of jackups in the U.S. Gulf of Mexico. This has created a more
favorable supply environment for the remaining jackups, including ours.
Beginning in mid-2001, an economic contraction in the United States
contributed to lower natural gas consumption, causing natural gas prices to fall
and, eventually, a decline in the utilization and average dayrates paid for our
jackup and barge drilling rigs operating in the natural gas-sensitive U.S. Gulf
Coast.
Market conditions for our U.S. Gulf Coast jackup fleet improved during 2003
as a result of declining rig supply in the region. These improved conditions
have resulted in increased utilization of our jackup fleet and higher
contractual dayrates. As of March 1, 2004, our nine jackup rigs working in the
U.S. Gulf Coast were contracted at dayrates ranging from $25,000 to $30,000. We
anticipate that the declining jackup rig supply in the U.S. Gulf Coast will
continue to result in increased utilization and ultimately higher dayrates. We
have experienced reduced utilization and dayrates in our U.S. Gulf Coast barge
market since early 2003 as a result of reduced demand for these rigs. With
respect to our Venezuelan operations, we experienced some increase in
utilization during the first half of 2003, but political unrest and exchange
controls continue to negatively impact our results of operations there. As a
result, we have experienced some decrease in utilization in Venezuela during the
second half of 2003 and the first quarter of 2004.
The following table shows our average revenue per day and utilization for
the quarterly periods ending on or prior to December 31, 2003 with respect to
each of our three business segments. Average revenue per day is defined as
operating revenue earned per revenue earning day in the period. 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
26
calendar days in the period for all drilling rigs in our fleet, as adjusted to
include calendar days available for rigs that were held for sale during the
periods ended on or prior to December 31, 2002.
THREE MONTHS ENDED
-----------------------------------------------------------------------------------------
DECEMBER 31, MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
2001 2002 2002 2002 2002 2003 2003
------------ --------- -------- ------------- ------------ --------- --------
AVERAGE REVENUE PER DAY:
U.S. Gulf Coast Jackups
and Submersibles..... $30,500 $21,900 $19,900 $22,400 $21,000 $22,600 $20,200
Inland Barges.......... 22,800 19,200 20,200 20,700 19,600 19,100 17,600
Mexico, Trinidad and
Venezuela Rigs....... 20,800 21,000 24,100 23,500 19,400 19,700 19,100
UTILIZATION:
U.S. Gulf Coast
Jackups and
Submersibles....... 38% 21% 29% 32% 34% 31% 44%
Inland Barges........ 55% 41% 24% 47% 44% 47% 39%
Mexico, Trinidad
and Venezuela Rigs..... 46% 39% 27% 23% 27% 35% 44%
THREE MONTHS ENDED
----------------------------
SEPTEMBER 30, DECEMBER 31,
2003 2003
------------- ------------
AVERAGE REVENUE PER DAY:
U.S. Gulf Coast Jackups
and Submersibles..... $22,900 $26,700
Inland Barges.......... 18,300 18,700
Mexico, Trinidad and
Venezuela Rigs....... 21,000 25,600
UTILIZATION:
U.S. Gulf Coast
Jackups and
Submersibles....... 54% 50%
Inland Barges........ 38% 40%
Mexico, Trinidad
and Venezuela Rigs..... 38% 28%
In the third quarter of 2003, we were awarded contracts with PEMEX, the
Mexican national oil company, for two of our jackup rigs and a platform rig.
After upgrades to comply with contract specifications, one rig began operating
on a 720-day contract in early November 2003 at a contract dayrate of
approximately $42,000. The other jackup rig began operating in early December
2003 on a 1,081-day contract at a contract dayrate of approximately $39,000. The
cost to prepare the two jackup rigs to work in Mexico, including mobilization
costs, which are deferred and will be recognized over the primary contract term,
was approximately $22 million in the aggregate. The platform rig contract is
1,289 days in duration beginning in mid-2004 at a contract dayrate of
approximately $29,000. We expect the upgrade to the platform rig necessary to
comply with contract specifications to occur in 2004 and cost approximately $8
million to $10 million. Each of the contracts can be terminated by PEMEX on five
days' notice, subject to certain conditions.
Another of our jackup rigs began operating in Venezuela in mid-December
2003 under a 120-day contract with ConocoPhillips at a contract dayrate of
$48,000. The cost of the upgrades to the rig to comply with contract
specifications and the cost of mobilization to Venezuela was approximately $5
million in the aggregate.
In January 2003, we renewed our principal insurance coverages for property
damage, liability, and occupational injury and illness. Premiums for such
coverages would have increased substantially were it not for us taking
significantly higher deductibles. The increased premiums were a result of
increased rates demanded by the insurance markets for most insurance coverages
as a result of losses in the insurance industry has sustained in the past
several years and perceived increased risks following the terrorist attacks on
September 11, 2001. In addition, such increased deductibles have become common
within the industry. The renewal of these coverages was for the period January
1, 2003 through March 1, 2004.
We renewed these insurance coverages as of March 1, 2004 for a 14 month
period ending May 1, 2005. Although premiums for these coverages were somewhat
lower, we again chose to increase deductibles to reduce premiums further. If our
occupational illness claim experience in 2004 is comparable to 2003 we would not
expect a significant increase in our insurance and claims related expense.
Because of the increase in our deductible exposure for 2004, an increase in our
loss experience would result in higher insurance and claims related expense for
the period.
IPO AND SEPARATION FROM TRANSOCEAN
We were incorporated in Delaware on July 7, 1997 as R&B Falcon Corporation.
On January 31, 2001, we became an indirect wholly owned subsidiary of Transocean
as a result of the Transocean Merger. The merger was accounted for as a
purchase, with Transocean as the accounting acquirer. Accordingly, the purchase
price was allocated to our assets and liabilities based on estimated fair values
as of January 31, 2001 with the excess accounted for as goodwill. The purchase
price adjustments were "pushed down" to our consolidated financial
27
statements, which affects the comparability of the consolidated financial
statements for periods before and after the merger. Accordingly, the financial
statements for the periods ended on or before January 31, 2001 were prepared
using our historical basis of accounting and the financial statements for the
periods subsequent to January 31, 2001 include the effects of the merger. See
Note 4 to our consolidated financial statements included in Item 8 of this
report. On December 13, 2002, we changed our name from R & B Falcon Corporation
to TODCO.
In July 2002, Transocean announced plans to divest its Shallow Water
business through an initial public offering of TODCO. In 2003, we completed the
transfer of the Transocean Assets to Transocean, including the transfer of all
revenue-producing assets. Accordingly, the Transocean Assets and related
operations have been reflected as discontinued operations in our historical
financial statements. See "Certain Relationships and Related Party
Transactions -- Asset Transfers to Transocean" and "Relationship between Us and
Transocean -- Master Separation Agreement -- TODCO Business" and "-- Transfer of
Assets and Assignment of Liabilities" for a description of the separation of our
respective businesses.
In February 2004, we completed the initial public offering of 13,800,000
shares of our Class A common stock as part of our separation from Transocean. We
did not receive any proceeds from the initial sale of our Class A common stock.
Transocean currently owns 100% of our outstanding Class B common stock
giving it 94% of the combined voting power of our outstanding common stock.
Transocean does not own any of our outstanding Class A common stock. Transocean
has advised us that its current long term intent is to dispose of our Class B
common stock owned by it.
CHANGES IN FINANCIAL REPORTING OF FUTURE RESULTS OF OPERATIONS
As a result of our separation from Transocean, including the transfer of
the Transocean Assets to Transocean in 2003 and the completion of our IPO in
February 2004, our reporting of certain aspects of our future results of
operations will differ from our historical reporting of results of operations.
The following discussion describes these and other differences.
General and administrative expense includes costs related to our corporate
executives, corporate accounting and reporting, engineering, health, safety and
environment, information technology, marketing, operations management, legal,
tax, treasury, risk management and human resource functions. Prior to June 30,
2003 and the transfer of the Transocean Assets to Transocean general and
administrative expense also included an allocation from Transocean for certain
administrative support. After June 30, 2003, general and administrative expense
includes costs for services provided to us under our transition services
agreement with Transocean. In 2004, we expect to incur approximately an
additional $3 million of general and administrative expense annually as a result
of additional costs associated with being a separate public company. In
addition, we expect to incur additional general and administrative expense
associated with the vesting of stock options and restricted stock granted in
conjunction with the IPO.
In conjunction with the closing of the IPO, we granted restricted stock and
stock options to certain employees and non-employee directors. Based upon the
IPO price of $12.00 per share, the value of these awards that we will recognize
as compensation expense is approximately $17.2 million. We expect to recognize
approximately $6.5 million in the first quarter of 2004. We will amortize to
compensation expense the remaining $10.7 million over the vesting period of the
awards and options with $4.2 million recognized during the second quarter
through the fourth quarter of 2004, $4.8 million in 2005 and $1.7 million in
2006 and thereafter. In addition, certain of our employees held options to
acquire the Transocean ordinary shares that were granted prior to the IPO. In
accordance with the employee matters agreement, the employees holding such
options were treated as terminated for the convenience of Transocean on the IPO
date. As a result, these options became fully vested and will remain exercisable
over the original contractual life. In connection with the modification of the
options, we will recognize approximately $1.5 million in additional compensation
expense in the first quarter of 2004.
28
Interest income consists of interest earned on our cash balances and, for
periods before December 31, 2003, on notes receivable from Delta Towing. Because
of the adoption of FASB Interpretation No. 46, Consolidation of Variable
Interest Entities, an Interpretation of Accounting Research Bulletin No. 51
("FIN 46") (see "-- Relationships with Variable Interest Entities" and
"-- Related Party Transactions -- Delta Towing") and the resulting consolidation
of Delta Towing in our consolidated balance sheet effective December 31, 2003,
in the future we expect interest income to consist of interest earned on our
cash balances. For periods before the IPO, interest expense consisted of
financing cost amortization and interest associated with our senior notes, other
debt and other related party debt as described in the notes to our consolidated
financial statements included in Item 8 of this report. We expect our debt
levels and, correspondingly, our interest expense to be substantially lower in
2004 than historical debt levels and interest expense reflected in our
historical operating results as a result of the retirement of notes payable to
Transocean prior to the IPO. After the closing of the IPO, we expect interest
expense to include interest on the approximately $24 million face value of our
senior notes and any borrowings under our credit facility, commitment fees on
the unused portion of our line of credit and the amortization of financing
costs.
Transocean will indemnify us against substantially all income tax
liabilities accruing on or before the IPO. However, we must pay Transocean for
substantially all income tax benefits created on or before the IPO that we
utilize after the IPO, including those utilized in determining any installment
of estimated taxes. For purposes of our tax sharing agreement, deferred tax
liabilities reflected in our financial statements, which represent the
anticipated future tax effects of temporary differences between the financial
statement basis and the tax basis of our assets and liabilities, are not
considered to constitute income tax liabilities accrued on or before the IPO.
See "Certain Relationships and Related Party Transactions -- Relationship
Between Us and Transocean -- Tax Sharing Agreement." As of December 31, 2003 we
had approximately $450 million of income tax benefits subject to our obligation
to reimburse Transocean. This amount includes approximately $200 million of tax
benefits reflected in our December 31, 2003 historical financial statements. See
Note 12 to our consolidated financial statements included in Item 8 of this
report. The tax basis in most of our assets is substantially lower than their
book value, and our tax depreciation will be substantially lower than the
depreciation reflected in our financial statements. As a result, we could be
required to pay income taxes or utilize income tax benefits that are
disproportionate to the income or loss reflected on our financial statements for
the applicable period following the IPO.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of
operations is based on our consolidated financial statements, which have been
prepared in accordance with accounting principles generally accepted in the
United States. The preparation of these financial statements requires us to make
estimates and judgments that affect the reported amounts of assets, liabilities,
operating revenues, expenses and related 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,
property, equipment and other long-lived assets, income taxes, workers' injury
claims, 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 these estimates 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.
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.
Property and Equipment. Our property and equipment represent approximately
85% of our total assets as of December 31, 2003. 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. We review our property and
equipment for impairment when events or changes in circumstances indicate that
the carrying value of these assets or asset groups may be impaired or when
reclassifications are made between property and equipment and assets held for
sale as prescribed by the Financial Accounting Standards Board's ("FASB")
Statement of Financial
29
Accounting Standards ("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. Our estimates,
assumptions and judgments used in the application of our property and equipment
accounting policies reflect both historical experience and expectations
regarding future industry conditions and operations. Using different estimates,
assumptions and judgments, especially those involving the useful lives of our
rigs and expectations regarding future industry conditions and operations, would
result in different carrying values of assets and results of operations.
Allowance for Doubtful Accounts. We establish reserves for doubtful
accounts on a case-by-case basis when we believe the collection of specific
amounts owed to us is unlikely to occur. Our operating revenues are principally
derived from services to U.S. independent oil and natural gas companies and
international and government-controlled oil companies and our receivables are
concentrated in the United States. We generally do not require collateral or
other security to support customer receivables. If the financial condition of
our customers deteriorates, we may be required to establish additional reserves.
Provision for Income Taxes. Our 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. Determination of taxable income in
any jurisdiction requires the interpretation of the related tax laws. 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. Currently payable income tax expense represents either nonresident
withholding taxes or the liabilities expected to be reflected on our income tax
returns for the current year while the net deferred tax expense or benefit
represents the change in the balance of deferred tax assets or liabilities as
reported on the balance sheet.
Valuation allowances are established to reduce deferred tax assets when it
is more likely than not that some portion or all of the deferred tax assets will
not be realized in the future. While we have considered estimated future taxable
income and ongoing prudent and feasible tax planning strategies in assessing the
need for the valuation allowances, changes in these estimates and assumptions,
as well as changes in tax laws could require us to adjust the valuation
allowances for our deferred tax assets. These adjustments to the valuation
allowance would impact our income tax provision in the period in which such
adjustments are identified and recorded.
Contingent Liabilities. We establish reserves for estimated loss
contingencies when we believe a loss is probable and we can reasonably estimate
the amount of the loss. Revisions to contingent liabilities 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, we would make
revisions to the estimated reserves for contingent liabilities, and such
revisions could be material.
30
RESULTS OF CONTINUING OPERATIONS
The following table sets forth our operating days, average rig utilization
rates, average revenue per day, revenues and operating expenses by operating
segment for the periods indicated:
FOR THE YEARS ENDED
DECEMBER 31,
---------------------------
2003 2002 2001
------- ------- -------
(IN MILLIONS EXCEPT PER DAY
DATA)
U.S. GULF OF MEXICO SEGMENT:
Operating days............................................ 4,388 3,061 6,420
Utilization(a)............................................ 44% 28% 56%
Average revenue per day(b)................................ $23,100 $21,500 $38,100
Revenue................................................... $ 101.2 $ 65.7 $ 244.6
Operating and maintenance expenses(c)..................... 98.6 87.1 138.8
Depreciation.............................................. 55.3 58.1 66.2
Impairment loss on long-lived assets...................... 10.6 1.1 --
(Gain) loss on disposal of assets, net.................... (0.1) 0.1 (2.7)
Operating income (loss)................................... (63.2) (80.7) 42.3
U.S. INLAND BARGE SEGMENT:
Operating days............................................ 4,558 4,392 7,672
Utilization(a)............................................ 41% 39% 66%
Average revenue per day(b)................................ $18,500 $19,900 $22,500
Revenue................................................... $ 84.2 $ 87.5 $ 172.9
Operating and maintenance expenses(c)..................... 95.8 67.7 96.2
Depreciation.............................................. 23.3 23.3 23.1
Impairment loss on long-lived assets...................... -- -- --
Gain loss on disposal of assets, net...................... (0.4) (1.2) (3.1)
Operating income (loss)................................... (34.5) (2.3) 56.7
OTHER INTERNATIONAL SEGMENT:
Operating days............................................ 2,007 1,648 4,051
Utilization(a)............................................ 36% 37% 79%
Average revenue per day(b)................................ $21,100 $21,000 $17,800
Revenue................................................... $ 42.3 $ 34.6 $ 72.0
Operating and maintenance expenses(c)..................... 33.0 30.9 58.2
Depreciation.............................................. 13.6 10.5 13.5
Impairment loss on long-lived assets...................... 0.7 16.4 1.1
(Gain) loss on disposal of assets, net.................... (0.3) 0.1 2.1
Operating loss............................................ (4.7) (23.3) (2.9)
TOTAL COMPANY:
Operating days............................................ 10,953 9,101 18,143
Utilization(a)............................................ 41% 34% 64%
Average revenue per day(b)................................ $20,800 $20,600 $27,000
Revenue................................................... $ 227.7 $ 187.8 $ 489.5
Operating and maintenance expenses(c)..................... 227.4 185.7 293.2
Depreciation and amortization............................. 92.2 91.9 145.9
General and administrative expenses....................... 16.3 28.9 80.2
Impairment loss on long-lived assets...................... 11.3 17.5 65.1
Impairment loss on goodwill............................... -- 381.9 --
Gain on disposal of assets, net........................... (0.8) (1.0) (3.7)
Operating loss............................................ (118.7) (517.1) (91.2)
---------------
(a)Utilization is the total 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.
(b)Average revenue per day is defined as operating revenue earned per revenue
earning day in the period.
(c)Excludes depreciation, amortization and general and administrative expenses.
31
YEARS ENDED DECEMBER 31, 2003 AND 2002
Revenue. Total revenue increased $39.9 million or 21% during 2003 as
compared to 2002. Overall average revenue per day and utilization increased
slightly from $20,600 and 34%, respectively, in 2002 to $20,800 and 41%,
respectively, in 2003. The increase in average revenue per day and utilization
reflects improving market conditions in the U.S. Gulf of Mexico, as well as the
addition of two of our jackup rigs which began operating offshore Mexico in late
2003 and a jackup rig that is currently working offshore Venezuela.
Revenue for our U.S. Gulf of Mexico Segment increased $35.5 million in 2003
as compared to 2002. Increased utilization for our jackup and submersible fleet
for 2003 as compared to the prior year, increased revenue by $30.3 million.
Additionally, we were able to achieve a slightly higher average revenue per day
in this market segment in 2003, as compared to 2002, which resulted in an
additional $6.9 million of operating revenues. This segment's results for 2002
included $1.7 million relating to a jackup rig that was transferred to
Transocean in the second quarter of 2002.
Revenue for our U.S. Inland Barge Segment decreased $3.3 million in 2003,
as compared to 2002, primarily due to a lower average revenue per day earned by
our fleet of barge rigs due to a continued softening in this market segment. The
decrease in average revenue per day resulted in a $6.6 million decrease in
revenue that was partly offset by an increase in revenue of $3.3 million due to
increased utilization.
The $7.7 million increase in revenue in 2003, as compared to 2002, for our
Other International Segment includes $3.5 million of revenue related to our two
jackup rigs which began working offshore Mexico in late 2003 under long-term
contracts and the effect of slightly higher utilization of our Venezuela rigs
($7.3 million), including the newly upgraded THE 156 which began operating under
a 120-day contract with ConocoPhillips in late December 2003. These favorable
variances were partly offset by the effect of lower average revenues per day
earned by our Venezuela land rigs, which resulted in a $2.4 million decrease in
revenues. Revenues attributable to our Trinidad rigs remained unchanged between
the periods.
Operating and Maintenance Expenses. Operating and maintenance expenses
increased $41.7 million or 22% in 2003, as compared to 2002. Operating expenses
in 2003 increased approximately $31 million associated with an increase in
overall average utilization and client reimbursable costs. Operating costs for
2003 also included one-time charges relating to a well control incident and fire
on two of our inland barges ($11.0 million), a write-down of other receivables
($3.6 million) and an insurance provision for damages sustained to the mat
finger on jackup rig THE 207 ($2.3 million). These increased costs were
partially offset by a decrease in the provision for doubtful accounts ($1.7
million) in 2003 as a result of the collection of amounts previously reserved,
reduced expense relating to our insurance program in 2003 compared to 2002 ($2.9
million), lower expenses ($1.5 million) resulting from the transfer of a jackup
rig to Transocean during the second quarter of 2002, and lower maintenance
expenses related to our Trinidad operations.
General and Administrative Expense. The $12.6 million decrease in general
and administrative expense is primarily attributable to lower allocations and
charges from Transocean in 2003 for support provided related to the Transocean
Assets ($8.3 million) since these assets had been sold or transferred prior to
June 30, 2003 and a decrease in severance-related costs, other restructuring
charges and compensation-related expenses incurred in 2002 ($4.4 million), with
no comparable activity in 2003, associated with the late 2002 closure of our
administrative office and warehouse in Louisiana and relocation of most of the
operations and administrative functions to Houston, Texas (see "-- Restructuring
Charges). Additionally, during the first half of 2002, we incurred $1.8 million
of costs in connection with the exchange of our notes for Transocean Assets as
more fully described in Note 6 of our consolidated financial statements included
in Item 8 of this report. Partly offsetting these cost decreases were increased
costs in 2003 related to the hiring of additional Houston-based staff to perform
managerial and other administrative functions in connection with our anticipated
separation from Transocean.
Impairment Loss on Long-Lived Assets. During 2003, we recorded a non-cash
impairment charge of $10.6 million resulting from our decision to take five
jackup rigs out of drilling service and market the rigs for alternative uses. We
do not anticipate returning these rigs to drilling service, as we believe it
would be cost
32
prohibitive to do so. As a result of this decision, and in accordance with SFAS
144, the carrying value of these assets was adjusted to fair market value. The
fair market value of these units as non-drilling rigs was based on third party
valuations. Additionally in 2003, we recorded a $1.0 million non-cash impairment
resulting from our determination that assets of entities in which we have an
investment did not support our recorded investment. The impairment was
determined and measured based upon the remaining book value of the assets and
our assessment of the fair value at the time the decision was made. The entities
are currently in process of being liquidated, and, in December 2003, we received
$0.3 million in proceeds from certain assets sold by the entities, which was
recorded as a reduction to the impairment charge.
In 2002, we recorded non-cash impairment charges of $1.1 million relating
to an asset held for sale. The impairment resulted from deterioration in market
conditions and was determined and measured based on an estimate of fair market
value derived from an offer from a potential buyer. In 2002 we also recorded
non-cash impairment charges totaling $16.4 million relating to the
reclassification of assets held for sale to assets held and used. The impairment
of these assets resulted from management's assessment that the assets no longer
met the held for sale criteria under SFAS 144. In accordance with SFAS 144, the
carrying value of the rig was adjusted to the lower of fair market value or
carrying value adjusted for depreciation from the date the assets were
classified as held for sale. The fair market value of the assets was based on
third party valuations.
Impairment Loss on Goodwill. As a result of our adoption of SFAS 142 as of
January 1, 2002, goodwill is no longer amortized but reviewed at least annually
for impairment. During the fourth quarter of 2002, we completed our annual
impairment test and recognized a non-cash impairment of our remaining goodwill
balance of $381.9 million. As of December 31, 2002, we had no goodwill balance.
See Note 2 to our consolidated financial statements included in Item 8 of this
report.
Equity in Loss of Joint Ventures. In 2003, we recognized $6.5 million in
equity losses related to our 25% ownership interest in Delta Towing as compared
to equity losses of $3.2 million in 2002. The results for Delta Towing continue
to be impacted by the downturn in the Gulf of Mexico oil and gas exploration and
production market and related downturn in the energy services market, including
the marine support vessel business, which has been slower to recover than other
types of service providers. In addition, our 2003 results for Delta Towing
include our share of a $2.5 million non-cash impairment charge on the carrying
value of idle equipment recorded in the first quarter of 2003 and a December
2003 non-cash impairment charge of $1.9 million as a result of Delta Towing's
annual test of impairment of long-lived assets. See "Relationships with Variable
Interest Entities."
Our 2002 results reflect $0.5 million in earnings attributable to our other
investments in unconsolidated affiliates, which were written off in 2003.
Interest Income. Interest income decreased $32.7 million in 2003 as
compared to 2002. Our 2002 results included $27.0 million of interest income
related to our notes receivable from Transocean, which was repaid by Transocean
in December 2002. In addition, we have previously recorded interest income
related to our notes receivable from Delta Towing; however, in the second half
of 2003 we established a reserve on interest earned on our notes receivable due
to Delta Towing's continued default on the notes. Interest income related to our
notes receivable from Delta Towing decreased $3.3 million in 2003 as compared to
2002 as a result of this reserve. See "-- Relationships with Variable Interest
Entities" for a discussion of the effects of FIN 46 on our investment in Delta
Towing.
Interest Expense. The $55.6 million decrease in third party interest
expense and interest expense-related party in 2003, as compared to 2002, is
attributable to lower debt balances owed to third parties and Transocean. In
2003, we repaid $15.2 million of debt and, in conjunction with the transfer of
the Transocean Assets, we retired $529.7 million in related party debt to
Transocean during 2003.
Loss on Retirement of Debt. In conjunction with the retirement of debt
held by Transocean, we recorded a $79.5 million and $18.8 million loss on
retirement of related party debt in 2003 and 2002, respectively. For a further
discussion of these retirements, see "-- Related Party Transactions and Note 6
to our consolidated financial statements included in Item 8 of this report.
33
Income Tax Benefit. The $24.5 million decrease in the income tax benefit
for 2003 as compared to 2002 is the result of valuation allowances recorded on
net operating loss carryforwards and foreign tax credits in 2003.
YEARS ENDED DECEMBER 31, 2002 AND 2001
Revenue. Total revenue decreased $301.7 million or 62% during 2002 as
compared to 2001 due primarily to the further weakening in 2002 of the U.S. Gulf
of Mexico shallow and inland water market sector, a decline that began in
mid-2001. Overall average revenue per day and utilization decreased from $27,000
and 64%, respectively, in 2001 to $20,600 and 34%, respectively, in 2002. Also,
contributing to this decrease is the absence of revenue attributable to three
jackup rigs that were transferred to Transocean in late 2001 as further
discussed in "-- Related Party Transactions."
Revenue for our U.S. Gulf of Mexico Segment decreased $178.9 million in
2002, as compared to 2001, due to decreased utilization and average revenue per
day for our jackup and submersible fleet as compared to the prior year, which
resulted in a $103.7 million and $47.4 million decrease in revenues,
respectively. This segment's decrease in revenue for 2002 also reflects the
effect of transferring three jackup rigs to Transocean in late 2001 and in the
second quarter of 2002 ($27.8 million).
Revenue for our U.S. Inland Barge Segment decreased $85.4 million in 2002,
as compared to 2001, primarily due to both a lower average revenue per day
earned by our fleet of barge rigs and a 27% decrease in utilization as a result
of the continued weakening in this market segment. The decrease in utilization
and average revenue per day resulted in a $73.9 million and $11.5 million
decrease in revenue, respectively, in 2002 compared to 2001.
Revenue for our Other International Segment decreased $37.4 million or 52%
in 2002, as compared to 2001, primarily due to the stacking of idle rigs in
response to weakened market conditions and an increasingly unstable political
environment in Venezuela ($31.9 million). The decline in revenue for our Other
International Segment also reflects the stacking of a rig in Mexico ($3.5
million). Only our Trinidad operations reflected an increase in revenue ($2.4
million) in 2002, as compared to 2001, due to the award of a three-year contract
for our jackup rig.
Operating and Maintenance Expenses. Operating and maintenance expenses
decreased $107.5 million or 37% in 2002, as compared to 2001, primarily as a
result of the stacking of idle rigs ($74.1 million) in response to weakening
market conditions in the U.S. Gulf of Mexico jackup and inland barge markets.
Our transfer of three jackup rigs to Transocean in late 2001 and in the second
quarter of 2002 ($17.6 million) also contributed to the decrease in operating
and maintenance expenses in 2002 compared to 2001.
General and Administrative Expense. The $51.3 million decrease in general
and administrative expense is primarily attributable to expenses incurred in
connection with the closing of our merger transaction with Transocean in January
2001 of approximately $58 million with no comparable expenses in 2002. The
January 2001 expenses included an investment advisory fee, termination benefits
to seven employees in accordance with employment contracts and an additional
expense due to the acceleration of vesting of certain stock options and unearned
compensation of restricted stock grants previously awarded to certain employees.
General and administrative expense in 2001 also included a reduction in
unemployment tax expense related to a claim settlement. General and
administrative expense in 2002 included severance-related costs, other
restructuring charges and compensation-related expenses ($4.4 million)
associated with the late 2002 closure of our administrative office and warehouse
in Louisiana and relocation of most of the operations and administrative
functions to Houston, Texas (see "-- Restructuring Charges) and $1.8 million of
costs in connection with the exchange of our notes for Transocean notes as more
fully described in Note 6 of our consolidated financial statements included in
Item 8 of this report.
Depreciation Expense. The $10.9 million decrease in depreciation expense
is primarily the result of depreciation on rigs sold, scrapped or classified as
held for sale from late 2001 and during 2002 ($3.2 million), the transfer of
three rigs to Transocean in late 2001 and in mid-2002 ($12.7 million) and the
contribution of our marine support vessel business to Delta Towing ($0.8
million), partially offset by increased expense as a
34
result of conforming estimated rig lives and salvage values to Transocean's
policies ($3.4 million) subsequent to the merger.
Impairment Loss on Long-Lived Assets. During 2002, we recorded non-cash
impairment charges of $16.4 million relating to the reclassification of assets
held for sale to assets held and used. The impairment of these assets resulted
from management's assessment that these assets no longer met the held for sale
criteria under SFAS 144. In accordance with SFAS 144, the carrying value of
these assets was adjusted to the lower of fair market value or carrying value
adjusted for depreciation from the date the assets were classified as held for
sale. The fair market values were based on third party valuations. We also
recorded non-cash impairment charges of $1.1 million in 2002 relating to an
asset held for sale. The impairment resulted from deterioration in market
conditions and was determined and measured based on an offer from a potential
buyer. During 2001, we recorded non-cash impairment charges of $64.0 million
related to the contribution of our marine support vessel business to Delta
Towing. We also recorded a non-cash impairment charge related to an asset held
and used of $1.1 million as a result of deterioration in market conditions.
Impairment Loss on Goodwill. As a result of our adoption of SFAS 142 as of
January 1, 2002, goodwill is no longer amortized but reviewed at least annually
for impairment. During the fourth quarter of 2002, we completed our annual
impairment test and recognized a non-cash impairment of our remaining goodwill
balance of $381.9 million. As of December 31, 2002, we had no goodwill balance.
See Note 2 to our consolidated financial statements included in Item 8 of this
report.
Interest Income. Interest income increased $13.9 million in 2002, as
compared to 2001, primarily due to interest earned on our notes receivable from
Transocean ($10.6 million) and interest earned on our notes from Delta Towing
($6.6 million). The increase in interest income -- related party was partially
offset by lower interest earned due to lower cash balances available for
investment in 2002 as compared to 2001.
Interest Expense. Interest expense, net of amounts capitalized, decreased
$42.7 million in 2002, as compared to 2001. Third party interest expense
decreased $85.6 million due to the early retirement of debt in 2001 and the
exchange by Transocean of third party debt for notes issued by Transocean,
partially offset by an increase in interest expense in 2002 due to the absence
of capitalized interest associated with the construction of Transocean newbuild
deepwater rigs in 2001. The increase in related party interest expense of $42.9
million is the result of interest earned on the exchanged notes and additional
interest on the two-year revolver with Transocean, partially offset by a
decrease in interest expense from the early retirement of debt in 2001.
Loss on Retirement of Debt. In conjunction with the retirement of debt
held by Transocean, we recorded a $18.8 million and $27.5 million loss on
retirement of related party debt in 2002 and 2001, respectively. For a further
discussion of these retirements, see "-- Related Party Transactions" and Note 6
to our consolidated financial statements included in Item 8 of this report.
Income Tax Benefit. The amount of tax benefit recognized is primarily
dependent on the loss realized and the valuation of operating loss carryforwards
during the period. The $19.6 million increase in the income tax benefit
recognized in 2002, as compared to 2001, is primarily attributable to the
inclusion of a larger amount of expenses not deductible for tax purposes than
the 2001 period such as the impairment charge to goodwill in 2002, partially
offset by goodwill amortization expense in 2001.
DISCONTINUED OPERATIONS
In 2002, Transocean announced plans to divest its Shallow Water business
through an initial public offering of TODCO. During 2003, we completed the
transfer to Transocean of the Transocean Assets, including all revenue-producing
Transocean Assets. Accordingly, the Transocean Assets and related operations
have been reflected as discontinued operations in our historical financial
statements. See Note 23 to our consolidated financial statements included in
Item 8 of this report, for a discussion of discontinued operations. See "Certain
Relationships and Related Party Transactions -- Asset Transfers to Transocean,"
and "Certain Relationships and Related Party Transactions -- Relationship
between Us and Transocean -- Master Separation Agreement -- TODCO Business,
and -- Transfer of Assets and Assignment of Liabilities" for a description of
the separation of our respective businesses.
35
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE
As a result of our adoption of FIN 46 as of December 31, 2003, we
recognized a $0.8 million gain as a cumulative effect of a change in accounting
principle related to our consolidation of Delta Towing (see "-- Relationships
with Variable Interest Entities").
During the year ended December 31, 2002, we recognized a non-cash
impairment charge to goodwill of $1,363.7 million as a cumulative effect of a
change in accounting principle related to the implementation of SFAS 142.
Additionally, due to a general decline in market conditions and other factors,
we recorded a $3,153.3 million impairment charge to goodwill related to our
discontinued operations as a cumulative effect of a change in accounting
principle. See Note 2 to our consolidated financial statements included in Item
8 of this report.
RESTRUCTURING CHARGE
In September 2002, we committed to a restructuring plan to consolidate some
functions and offices. The plan resulted in the closure of an administrative
office and warehouse in Louisiana and relocation to Houston, Texas of most of
the operations and administrative functions previously conducted at that
location. We established a liability of $1.2 million for the estimated
severance-related costs associated with the involuntary termination of 57
employees pursuant to this plan. The charge was reported as operating and
maintenance expense in our consolidated statements of operations for the year
ended December 31, 2002. As of December 31, 2003, substantially all
severance-related costs had been paid. We do not currently expect other
significant restructuring plans in the near term.
FINANCIAL CONDITION
At December 31, 2003 and December 31, 2002, we had total assets of $778.2
million and $2,227.2 million, respectively. The $1,449.0 million decrease in
assets in 2003, as compared to 2002, is primarily attributable to the
distribution and sale of Transocean Assets ($891.5 million) (see "Certain
Relationships and Related Party Transactions -- Asset Transfers to Transocean")
and the transfer of $103.9 million in cash in connection with the distribution
of some of our subsidiaries to Transocean. The remaining decrease in assets is
primarily attributable to normal depreciation of $92.2 million and a $344.8
million decrease in amounts receivable from Transocean.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES AND USE OF CASH
The following discussion relates to our historical sources and uses of cash
which includes components from both continuing operations and discontinued
operations.
2003 Compared to 2002. Net cash provided by operating activities was
$103.1 million for year ended December 31, 2003 compared to $14.1 million for
the same period in 2002. The $89.0 million increase is primarily related to a
$754.2 million greater loss before cumulative effect of a change in accounting
principle in 2002, as compared to the same period in 2003, a $60.7 million
greater non-cash loss from the retirement of debt in 2003, as compared to 2002,
a $21.3 million non-cash impairment charge of our investment in and advance to
Delta Towing recorded in June 2003, and a $21.6 million decrease in deferred
income tax benefits in 2003, as compared to 2002. These increases in net cash
provided by operating activities are partially offset by a $932.2 million
impairment loss on goodwill in 2002, $44.1 million of greater impairment losses
on other long-lived assets recorded in 2002, as compared to 2003, and $66.8
million lower depreciation expense in 2003. Cash provided by changes in
operating assets and liabilities, net of effect of distributions to affiliates,
was $224.0 million for the year ended 2003 as compared to a usage of $(50.4)
million for the same period in 2002. The $274.4 million increase cash provided
by changes in operating assets and liabilities is primarily due to lower
activity with related parties, the settlement of outstanding balances with
Transocean and the working capital effect of reduced operating levels in 2003 as
compared to 2002, as a result of the transfer of the Transocean Assets to
Transocean.
36
Net cash provided by investing activities amounted to $59.5 million for the
year ended December 31, 2003 compared to $555.8 million for the same period in
2002. The $496.9 million decrease in net cash provided by investing activities
relates primarily to the $518.0 million repayment by Transocean of notes
receivable by us in December 2002, partly offset by $21.6 million higher
proceeds from the disposal of assets as a result of the sale of some of the
Transocean Assets to Transocean in 2003 as compared to the same period in 2002.
Net cash used in financing activities amounted to $245.5 million for the
year ended December 31, 2003, compared to $535.5 million for the same period in
2002. The $290.0 million decrease in net cash used in financing activities in
2003 compared to 2002 is primarily due to the 2002 repayment of $529.2 million
of debt payable to Transocean and $8.3 million in consent payments made in
connection with the exchange offer for our senior notes. These decreases in cash
used in financing activities was partly offset by a $93.5 million increase in
cash balances transferred to Transocean in connection with the sale and
distribution of subsidiaries to Transocean in 2003, higher net repayment of
long-term advances from Transocean of $101.3 million and $50.5 million higher
repayments of other debt in 2003 compared to 2002. See "-- Related Party
Transactions".
2002 Compared to 2001. Net cash provided by operating activities amounted
to $14.1 million for the year ended December 31, 2002 compared to $63.0 million
for the same period in 2001. The $48.9 million decrease in net cash provided by
operating activities is primarily related to a $797.8 million greater loss
before cumulative effect of a change in accounting principle and $186.4 million
lower depreciation and amortization for the year ended December 31, 2002, as a
result of the transfer to Transocean of Transocean Assets in the second half of
2002 and the write-off of goodwill in 2002. Additionally, other non-cash
adjustments to net income related to deferred taxes, gain on disposal of assets,
impairment losses on long-lived assets, equity in losses of joint ventures and
other deferred items were $87.0 million lower in 2002 as compared to 2001, which
further decreased net cash provided by operating activities. These decreases
were partially offset by a $932.2 non-cash impairment loss on goodwill
recognized in 2002 and an $89.5 million increase in cash provided by changes in
operating assets and liabilities, net of effect of distributions to affiliates
for the year ended December 31, 2002.
Net cash provided by investing activities amounted to $555.8 million for
the year ended December 31, 2002 compared to a use of $79.4 million for the same
period in 2001 primarily as a result of $518.0 million in proceeds from
settlement of notes receivable with Transocean, coupled with significantly lower
capital expenditures due to the completion of the Transocean rig expansion
program in 2001.
Net cash used in financing activities amounted to $535.5 million for the
year ended December 31, 2002 compared to a use of $273.1 million for the same
period in 2001 primarily as a result of $529.2 million in repayments of debt to
Transocean (See "-- Related Party Transactions"). During the year ended December
31, 2001, we made $1.5 billion of early repayments of debt instruments,
partially offset by proceeds from long-term advances from Transocean of $1.2
billion in 2001 to finance the early repayment of debt. We also made net
repayments of our debt of $38.6 million during 2002 compared to $35.9 million in
2001. During the year ended December 31, 2002, we paid $8.3 million in financing
costs related to the exchange of our notes for Transocean notes.
SOURCES OF LIQUIDITY AND CAPITAL EXPENDITURES
Our primary sources of liquidity for the year ended December 31, 2003 were
our cash flows from operations and asset sales. Our primary sources of liquidity
for the year ended December 31, 2002 were our cash flows from operations, asset
sales, repayment of notes receivable from Transocean and proceeds from long-term
debt with related party. Primary uses of cash for the year ended December 31,
2003 were debt repayments and the transfer of cash balances in conjunction with
the sale or distribution of Transocean Assets to Transocean. Primary uses of
cash for the year ended December 31, 2002 were capital expenditures and debt
repayments. At December 31, 2003, we had $20.0 million in cash and cash
equivalents.
During 2002 and until April 6, 2003, we had access to a $1.8 billion
revolving line of credit with Transocean of which $100.0 million was outstanding
at December 31, 2002. At expiration, on April 6, 2003,
37
the approximately $81.2 million then outstanding under this line of credit was
converted to a two year, 2.76% fixed rate note to Transocean that was
subsequently cancelled in connection with the transfer of some of the Transocean
Assets to Transocean.
Capital expenditures were $16.1 million and $17.7 million for the years
ended December 31, 2003 and 2002, respectively. Capital expenditures in 2003
related to upgrades and replacements of equipment including approximately $9
million for rig upgrades on two of our jackup rigs that were awarded contracts
for work in Mexico. Additionally, we incurred approximately $22 million in
mobilization and other contract preparation costs relating to these rigs that
have been deferred and will be recognized over the primary contract term. The
majority of our capital expenditures in 2002 related to upgrades and
replacements of equipment.
We anticipate that we will rely primarily on internally generated cash
flows to maintain liquidity. From time to time, we may also make use of our
revolving line of credit for cash liquidity. In December 2003, we entered into a
two-year $75 million floating-rate secured revolving credit facility that will
decline to $60 million in December 2004.
The facility is secured by most of our drilling rigs, our receivables, the
stock of most of our U.S. subsidiaries and is guaranteed by some of our
subsidiaries. Borrowings under the facility bear interest at our option at
either (1) the higher of (A) the prime rate and (B) the federal funds rate plus
0.5%, plus a margin in either case of 2.50% or (2) the Eurodollar rate plus a
margin of 3.50%. Commitment fees on the unused portion of the facility are 1.50%
of the average daily balance and are payable quarterly. Borrowings and letters
of credit issued under the facility are limited by a borrowing base equal to the
lesser of (A) 20% of the orderly liquidated value of the drilling rigs securing
the facility, as determined from time to time by a third party selected by the
agent under the facility, and (B) the sum of 10% of the orderly liquidated value
of the drilling rigs securing the facility plus 80% of the U.S. accounts
receivable outstanding less than 90 days, net of any provision for bad debt
associated with such U.S. accounts receivable.
Financial covenants include maintenance of the following:
- a ratio of (1) current assets plus unused availability under the facility
to (2) current liabilities (excluding specified subordinated liabilities
owed to Transocean) of at least 1.2 to 1,
- a ratio of total debt to total capitalization of not more than 20%
(excluding specified subordinated liabilities owed to Transocean from
debt but including those liabilities in total capitalization),
- tangible net worth plus specified subordinated liabilities owed to
Transocean of not less than the sum of (1) $425 million plus (2) to the
extent positive, 50% of net income after December 31, 2003,
- a ratio of (1) the orderly liquidation value of the drilling rigs
securing the facility to (2) the amount of borrowings and letters of
credit outstanding under the facility of not less than 3 to 1, and
- in the event liquidity (defined as working capital (excluding specified
subordinated liabilities owed to Transocean) plus availability under the
facility) is less than $25 million, a ratio of (1) EBITDA minus capital
expenditures during the preceding 12 fiscal months to (2) interest
expense (excluding interest on specified subordinated debt owed to
Transocean) during such period of not less than 2 to 1.
The revolving credit facility provides, among other things, for the
issuance of letters of credit that we may utilize to guarantee our performance
under some drilling contracts, as well as insurance, tax and other obligations
in various jurisdictions. The facility also provides for customary fees and
expense reimbursements and includes other covenants (including limitations on
the incurrence of debt, mergers and other fundamental changes, asset sales and
dividends) and events of default (including a change of control) that are
customary for similar secured non-investment grade facilities.
We expect capital expenditures to be approximately $8 million in 2004,
primarily for rig refurbishments and the purchase of capital equipment. The
timing and amounts we actually spend in connection with our plans to upgrade and
refurbish other selected rigs, including rigs requiring substantial
refurbishment, is subject to our discretion and will depend on our view of
market conditions and our cash flows. We would expect capital expenditures to
increase as market conditions improve. Our rigs requiring substantial
refurbishment to
38
be ready for service are noted in the tables in "Business -- Drilling Rig
Fleet." Our ability to fund capital expenditures would be adversely affected if
conditions deteriorate in our business, we experience poor results in our
operations or we fail to meet covenants under the line of credit described in
the previous paragraph.
We anticipate that our available funds, together with our cash generated
from operations and amounts that we may borrow, will be sufficient to fund our
required capital expenditures, working capital and debt service requirements for
the foreseeable future. Future cash flows and the availability of outside
funding sources, however, are subject to a number of uncertainties, especially
the condition of the oil and natural gas industry. Accordingly, these resources
may not be available or sufficient to fund our cash requirements.
As of December 31, 2003, our scheduled debt maturities and other
contractual obligations are presented in the table below with debt obligations
presented at face value:
FOR THE PERIODS ENDING DECEMBER 31,
--------------------------------------
2005 2007
TO TO
TOTAL 2004 2006 2008 THEREAFTER
------ ---- ------ --------- ----------
(IN MILLIONS)
CONTRACTUAL OBLIGATIONS
Debt.................................. $ 23.6 $ -- $ 7.7 $ 12.4 $ 3.5
Debt -- Related Party(a).............. 491.1 3.0 152.5 289.8 45.8
Capital Leases........................ 1.9 1.2 0.7 -- --
Operating Leases...................... 5.6 1.9 1.9 1.2 0.6
------ ---- ------ --------- -----
Total Contractual Obligations...... $522.2 $6.1 $162.8 $ 303.4 $49.9
====== ==== ====== ========= =====
---------------
(a) In February 2004, we completed a non-cash exchange of $488.1 million of our
senior notes payable to Transocean for 3,940,406 shares of our Class B
common stock (47,855,249 shares of Class B common stock after giving effect
to the stock dividend). See a further discussion of the exchange of debt
for stock and stock dividend in Note 24 to our consolidated financial
statements included in Item 8 of this report.
At December 31, 2003, 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. These obligations could be called at
any time prior to their expiration dates. The obligations that are the subject
of these surety bonds are geographically concentrated in the United States and
Mexico.
FOR THE PERIODS ENDING DECEMBER 31,
------------------------------------
2005 2007
TO TO
TOTAL 2004 2006 2008 THEREAFTER
----- ----- ------ ----- -----------
(IN MILLIONS)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit(a).................. $ 0.7 $0.7 $ -- $ -- $ --
Surety Bonds.................................. 13.4 1.5 -- 7.8 4.1
----- ---- ----- ---- ----
Total...................................... $14.1 $2.2 $ -- $7.8 $4.1
===== ==== ===== ==== ====
---------------
(a) Consists of standby letters of credit related to Transocean's business.
Transocean is indemnifying us for these obligations under the master
separation agreement. See "Certain Relationships and Related Party
Transactions -- Relationship Between Us and Transocean -- Master Separation
Agreement -- Letters of Credit and Guarantees."
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 board of
directors. 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.
39
We do not plan to 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 as
accounting hedges are deferred as accumulated other comprehensive income and
recognized when the underlying foreign exchange exposure is realized. Gains and
losses on foreign exchange derivative instruments that 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, 2003, we did not have any
outstanding foreign exchange derivative instruments.
From time to time, we may use interest rate swaps to manage the effect of
interest rate changes on future income. Interest rate swaps would be designated
as a hedge of underlying future interest payments and would not be used for
speculative purposes. 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, the gain or loss is
amortized over the life of the underlying debt. At December 31, 2003, we did not
have any outstanding interest rate swaps.
RELATIONSHIPS WITH VARIABLE INTEREST ENTITIES
We own a 25% equity interest in Delta Towing, which was formed to own and
operate our U.S. marine support vessel business consisting primarily of shallow
water tugs, crewboats and utility barges. We contributed this business to Delta
Towing in return for a 25% ownership interest and secured notes issued by Delta
Towing with a face value of $144.0 million. No value was assigned to the
ownership interest in Delta Towing.
The note agreement was subsequently amended to provide for a $4.0 million,
three-year revolving credit facility (the "Delta Towing Revolver"). Delta
Towing's property and equipment, with a net book value of $50.6 million at
December 31, 2003, are collateral for the Company's notes receivable. The
carrying value of the notes receivable, net of allowance for credit losses and
equity losses in Delta Towing was $49.0 million at December 31, 2003 and has
been eliminated in consolidation. The remaining 75% ownership interest is held
by Beta Marine Services, L.L.C. ("Beta Marine"), which also loaned Delta Towing
$3.0 million.
In January 2003, the FASB issued FIN 46 which requires that an enterprise
consolidate a variable interest entity ("VIE") if the enterprise has a variable
interest that will absorb a majority of the entity's expected losses and/or
receives a majority of the entity's expected residual returns as a result of
ownership, contractual or other financial interests in the entity, if such loss
or residual return occurs. If one enterprise absorbs a majority of a VIE's
expected losses and another enterprise receives a majority of that entity's
expected residual returns, the enterprise absorbing a majority of the losses is
required to consolidate the VIE and will be deemed the primary beneficiary. We
adopted and applied the provisions of FIN 46 effective December 31, 2003.
Under FIN 46, Delta Towing is considered a VIE because its equity is not
sufficient to absorb the joint venture's expected future losses. TODCO is the
primary beneficiary of Delta Towing for accounting purposes because we have the
largest percentage of investment at risk through the secured notes held by us
and would thereby absorb the majority of the expected losses of Delta Towing. We
have consolidated Delta Towing in our December 31, 2003 consolidated financial
statements. The consolidation of Delta Towing resulted in an increase in our net
assets and a corresponding gain of $0.8 million, which has been presented as a
cumulative effect of a change in accounting principle in our consolidated
statement of operations included in Item 8 of this report.
RELATED PARTY TRANSACTIONS
ALLOCATION OF ADMINISTRATIVE COSTS
Transocean has historically provided specified administrative support to
us. Transocean has charged us a proportional share of its administrative costs
based on estimates of the percentage of work each Transocean department performs
for us. The amount of expense allocated to us was $1.4 million and $9.7 million
for the years ended December 31, 2003 and 2002, respectively, and was classified
as general and administrative --
40
related party expense. Following the IPO, some of these functions are provided
to us under the transition services agreement described under "Certain
Relationships and Related Party Transactions -- Relationship Between Us and
Transocean -- Transition Services Agreement."
DELTA TOWING
Our note receivable from Delta Towing and amounts owed to us under the
Delta Towing Revolver (see "-- Relationships with Variable Interest Entities")
accrue interest at 8% per annum. During the years ended December 31, 2003 and
2002, we earned interest income on the notes and the Delta Towing Revolver of
$3.3 million and $6.6 million, respectively.
In 2001, Delta Towing paid approximately $1.1 million in principal payments
on the notes from net proceeds on assets sold during the year. During the years
ended December 31, 2003 and 2002, Delta Towing paid approximately $1.8 million
and $0.1 million, respectively, on the Delta Towing Revolver.
During the years ended December 31, 2003, 2002 and 2001, our equity in
losses of Delta Towing reduced the carrying value of the notes by $6.6 million,
$3.2 million and $0.9 million, respectively.
As a result of its issuance of notes to us, Delta Towing is highly
leveraged. Delta Towing defaulted on the notes in January 2003 by failing to
make its scheduled quarterly interest payment and remains in default as a result
of its continued failure to make its quarterly interest payments. As a result of
our continued evaluation of the collectibility of the notes, we recorded a $21.3
million impairment of the notes 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 notes in the event of default, we began offsetting a portion
of the amount owed by us to Delta Towing against the interest due under the
notes. Additionally, we established a reserve of $1.6 million for interest
income earned during 2003 on the notes receivable.
Effective December 31, 2003, we have consolidated Delta Towing (see
"-- Relationships with Variable Interest Entities and -- New Accounting
Pronouncements"), and, accordingly, the amounts due from Delta Towing have been
eliminated in consolidation. The outstanding carrying amount of the notes and
the Delta Towing Revolver at December 31, 2002, was $78.7 million. Interest
receivable on the notes and the Delta Towing Revolver was $1.7 million at
December 31, 2002.
As part of the formation of the joint venture on January 31, 2001, we
entered into a charter arrangement with Delta Towing under which we 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 date of delivery 10
crewboats then under construction, all of which were in service as of December
31, 2003. We also entered into an alliance agreement with Delta Towing under
which we agreed to treat Delta Towing as a preferred supplier for the provision
of marine support services. During the year ended December 31, 2003, we incurred
charges totaling $11.7 million from Delta Towing for services rendered, which
were reflected in operating and maintenance -- related party expense. During the
year ended December 31, 2002, we incurred charges totaling $10.7 million from
Delta Towing for services rendered, of which $1.6 million was rebilled to our
customers and $9.1 million was reflected in operating and maintenance -- related
party expense.
As a result of restrictions on the ownership or operation of vessels
involved in the coastwise trade by non-U.S. citizens, our ability to take
ownership of the assets owned by Delta Towing in connection with its default
under its notes issued to us would be restricted. These restrictions apply to us
because Transocean, a company organized under the laws of the Cayman Islands,
currently owns the majority of our common stock, and our chief executive officer
is not a U.S. citizen.
LONG-TERM DEBT -- TRANSOCEAN
We were a party to a $1.8 billion two-year revolving credit agreement (the
"Two-Year Revolver") with Transocean, dated April 6, 2001. During the years
ended December 31, 2003 and 2002, we recognized $0.8 million and $1.8 million,
respectively, in interest expense related to the Two-Year Revolver. See "Certain
Relationships and Related Party Transactions -- Revolving Credit Agreement."
This line of credit expired on
41
April 6, 2003. As of that date, the approximately $81.2 million then outstanding
under the line was converted to a 2.76% fixed rate promissory note issued by us
to Transocean which was scheduled to mature on April 6, 2005. This note was
cancelled in 2003 in connection with the series of transactions described below.
In March 2002, together with Transocean, we completed exchange offers and
consent solicitations for our 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, Transocean
exchanged approximately $234.5 million, $342.3 million, $247.8 million, $246.5
million, $76.9 million and $289.8 million principal amount of our outstanding
6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, for
newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Transocean notes having
the same principal amount, interest rate, redemption terms and payment and
maturity dates. As of September 30, 2003, we had approximately $7.7 million,
$2.2 million, $3.5 million, $10.2 million and $10.2 million principal amount of
the 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively,
outstanding that were not exchanged in the Exchange Offer. Both the exchanged
notes and the notes not exchanged remained our obligation. As a result of the
consent payments made in connection with the Exchange Offer, interest expense
for 2003 and 2002 increased by approximately $0.5 million and $1.3 million,
respectively.
In June 2003, we sold to Transocean our membership interests in our wholly
owned subsidiary, R&B Falcon Drilling (International & Deepwater) Inc. LLC. As
consideration for the interests sold, Transocean cancelled $238.8 million of our
debt held by Transocean.
In May 2003, we sold Cliffs Platform Rig 1 to Transocean in consideration
for the cancellation of $13.9 million of our debt held by Transocean.
In May 2003, we sold to Transocean our 50% interest in Deepwater Drilling
LLC and our 60% interest in Deepwater Drilling II LLC in consideration for the
cancellation of $43.7 million principal amount of our debt held by Transocean.
In March 2003, we sold our investment in Arcade Drilling AS. In
consideration for the sale of our investment, Transocean cancelled $233.3
million principal amount outstanding of our debt held by Transocean.
In December 2002, we repurchased all of the approximately $234.5 million
and $76.9 million principal amount outstanding of our 6.5% and 9.125% Senior
Notes held by Transocean, respectively, and approximately $189.8 million
principal amount outstanding of our 6.75% Senior Notes held by Transocean plus
accrued and unpaid interest. We recorded a net after-tax loss of $12.2 million
in conjunction with the repurchase of these notes. We funded the repurchase from
cash received from Transocean's repayment of approximately $518.0 million
aggregate principal amount of outstanding notes receivable plus accrued and
unpaid interest.
The book value of the senior notes Transocean acquired in the Exchange
Offer was $522.0 million at December 31, 2003 and $980.1 million at December 31,
2002. We recognized $42.7 million and $77.9 million in interest expense related
to these notes for the years ended December 31, 2003 and 2002, respectively.
Prior to the closing of the IPO, these notes were retired, and we have expensed
$1.9 million of unamortized consent payments in connection with the Exchange
Offer. See "Certain Relationships and Related Party Transactions -- Debt
Retirement and Debt Exchange Offers" and "Certain Relationships and Related
Party Transactions -- Asset Transfers to Transocean" and Note 24 to our
consolidated financial statements included in Item 8 of this report.
TRANSFER OF TRANSOCEAN ASSETS
We transferred the Transocean Assets to Transocean primarily as in-kind
dividends and transfers in exchange for the cancellation of debt to Transocean
and, in some instances, for cash. Specified contracts were assigned to
Transocean for no consideration. These transactions had no effect on our results
of continuing operations except to the extent that debt was retired and any gain
or loss was recognized. See "Certain Relationships and Related Party
Transactions -- Asset Transfers to Transocean."
42
LONG-TERM DEBT -- BETA MARINE
In connection with the acquisition of the marine business, Delta Towing
entered into a $3.0 million note agreement with Beta Marine dated January 30,
2001. The note bears interest at 8%, payable quarterly. In January 2004, Delta
Towing failed to make its scheduled principal payment to Beta Marine. The $3.0
million principal amount of the note payable has been classified as a current
obligation in our consolidated balance sheet included in Item 8 of this report.
CAUTIONARY STATEMENT ABOUT FORWARD -- LOOKING STATEMENTS
This report contains both historical and forward-looking statements. All
statements other than statements of historical fact are, or may be deemed to be,
forward-looking statements. Forward-looking statements include information
concerning our possible or assumed future financial performance and results of
operations, including statements about the following subjects:
- our strategy,
- improvement in the fundamentals of the oil and gas industry,
- the supply and demand imbalance in the oil and gas industry,
- the correlation between demand for our rigs and our bonds, earnings and
customers' expectations of energy prices,
- our plans, expectations and any effects of focusing on agreements and marine
assets and drilling for natural gas along the U.S. Gulf Coast, pursuing
efficient, low-cost operations and a disciplined approach to capital spending,
maintaining high operating standards and maintaining a conservative capital
structure,
- the emergence of the drilling industry from a low point in the cycle,
- estimated tax benefits,
- expected capital expenditures,
- expected general and administrative expense,
- refurbishment costs,
- our ability to take advantage of opportunities for growth and our ability to
respond effectively to market matters downturns,
- sufficiency of funds for required capital expenditures, working capital and
debt service,
- deep gas drilling opportunities,
- operating standards,
- payment of dividends,
- competition for drilling contracts,
- matters relating to derivatives,
- matters related to our letters of credit and surety bonds,
- future restructurings,
- matters relating to our future transactions, relationship with Transocean,
- payments under agreements with Transocean,
- liabilities under laws and regulations protecting the environment,
- results and effects of legal proceedings,
- future utilization rates,
- future dayrates, and
- expectations regarding improvements in offshore activity, demand for our
drilling rigs, our plan to primarily in the U.S. Gulf Coast, operating
revenues, operating and maintenance expense, insurance expense and
deductibles, interest expense, debt levels and other with regard to outlook.
Forward-looking statements in this Form 10-K are identifiable by use of the
following words and other similar expressions:
- "anticipate,"
- "believe,"
- "budget,"
- "could,"
- "estimate,"
- "expect,"
- "forecast,"
- "intent,"
- "may,"
- "might,"
- "plan,"
- "predict,"
- "project," and
- "should."
The following factors could affect our future results of operations and
could cause those results to differ materially from those expressed in the
forward-looking statements included in this prospectus:
- worldwide demand for oil and gas,
- exploration success by producers,
43
- demand for offshore and inland water rigs,
- our ability to enter into and the terms of future contracts,
- labor relations,
- political and other uncertainties inherent in non-U.S. operations (including
exchange controls and currency fluctuations),
- the impact of governmental laws and regulations,
- the adequacy of sources of liquidity,
- uncertainties relating to the level of activity in offshore oil and gas
exploration and development,
- oil and natural gas prices (including U.S. natural gas prices),
- competition and market conditions in the contract drilling
- work stoppages,
- the availability of qualified personnel,
- operating hazards,
- war, terrorism and cancellation or unavailability of insurance coverage,
- compliance with or breach of environmental laws,
- the effect of litigation and contingencies,
- our inability to achieve our plans or carry out our strategy,
- the matters discussed in "Business -- Risk Factors," and
- other factors discussed in this prospectus.
Should one or more of these risks or uncertainties materialize, or should
underlying assumptions prove incorrect, actual results may vary materially from
those indicated. Shareholders 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.
44
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
The table below presents scheduled debt maturities and related
weighted-average interest rates for each of the twelve month periods ending
December 31, relating to debt obligations as of December 31, 2003:
SCHEDULED MATURITY DATE FAIR VALUE
-------------------------------------------------------------- DECEMBER 31,
2004 2005 2006 2007 2008 THEREAFTER TOTAL 2003
---- ------ ------ ------ ------ ---------- ------ ------------
(IN MILLIONS, EXCEPT INTEREST RATE PERCENTAGES)
TOTAL DEBT
Fixed Rate(a)(b)............. $3.0 $160.2 $ -- $ -- $302.2 $49.3 $514.7 $599.0
Average interest rate...... 8.0% 6.8% -- -- 9.5% 7.4% 8.4%
---------------
(a) Expected maturity amounts are based on the face value of debt and do not
reflect fair market value of debt.
(b) In February 2004, we completed a non-cash exchange of $488.1 million of our
senior notes payable to Transocean for 3,940,406 shares of our Class B
common stock (47,855,249 shares of Class B common stock after giving effect
to the stock dividend). See a further discussion of the exchange of debt
for stock and stock dividend in Note 24 to our consolidated financial
statements included in Item 8 of this report.
FOREIGN EXCHANGE RISK
Our international operations in Mexico, Trinidad and Venezuela, 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 and local currency. The payment portion denominated in local
currency is based on anticipated local currency requirements over the contract
term. We may also use foreign exchange derivative instruments or spot purchases.
We do not enter into derivative transactions for speculative purposes. At
December 31, 2003, we did not have any outstanding foreign exchange contracts.
In January 2003, Venezuela implemented foreign exchange controls that
limited our ability to convert local currency into U.S. dollars and transfer
excess funds out of Venezuela. Our drilling contracts in Venezuela typically
call for payments to be made in local currency, even when the dayrate is
denominated in U.S. dollars. In August 2003, we negotiated an agreement with our
principal customer in Venezuela to pay the majority of the U.S. dollar
denominated amounts in U.S. dollars to one of our banks in the United States.
The exchange controls could also result in an artificially high value being
placed on the local currency.
Due to the continuation of these foreign exchange controls as well as
continuing political instability in Venezuela, we established a currency
valuation allowance pertaining to cash receivables in Venezuela of $2.4 million
in the second quarter of 2003 to adjust our Venezuelan financial assets to net
realizable value. As of December 31, 2003, no additional currency valuation
allowance was deemed necessary, and we do not anticipate having to continue to
provide a currency valuation allowance related to our Venezuelan operations.
45
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
PAGE
REFERENCE
---------
Report of Ernst & Young LLP, Independent Auditors........... 47
Consolidated Balance Sheets at December 31, 2003 and 2002... 48
Consolidated Statements of Operations for the Years Ended
December 31, 2003 and 2002, the One Month Ended January
31, 2001 and the Eleven Months Ended December 31, 2001.... 49
Consolidated Statements of Comprehensive Loss for the Years
Ended December 31, 2003 and 2002, the One Month Ended
January 31, 2001 and the Eleven Months Ended December 31,
2001...................................................... 50
Consolidated Statements of Equity for the Years Ended
December 31, 2003 and 2002, the One Month Ended January
31, 2001 and the Eleven Months Ended December 31, 2001.... 51
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2003 and 2002, the One Month Ended January
31, 2001 and the Eleven Months Ended December 31, 2001.... 52
Notes to Consolidated Financial Statements.................. 53
Schedule II -- Valuation and Qualifying Accounts for the
Years Ended December 31, 2003 and 2002, the One Month
Ended January 31, 2001, and the Eleven Months Ended
December 31, 2001......................................... 89
46
REPORT OF INDEPENDENT AUDITORS
To the Shareholders and Board of Directors
TODCO
We have audited the accompanying Post-Transocean Merger consolidated
balance sheets of TODCO and Subsidiaries as of December 31, 2003 and 2002 and
the related Post-Transocean Merger consolidated statements of operations,
comprehensive loss, equity and cash flows for each of the two years in the
period ended December 31, 2003, and the period from February 1, 2001 to December
31, 2001, and the related Pre-Transocean Merger consolidated statements of
operations, comprehensive loss, equity and cash flows for the period from
January 1, 2001 to January 31, 2001. Our audits also included the financial
statement schedule listed in Item 15(a) of this Form 10-K. 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 auditing standards generally
accepted in the 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 Post-Transocean Merger consolidated financial
position of TODCO and Subsidiaries at December 31, 2003 and 2002, and the
Post-Transocean Merger consolidated results of their operations and their cash
flows for each of the two years in the period ended December 31, 2003, and the
period from February 1, 2001 to December 31, 2001, and the Pre-Transocean Merger
consolidated results of their operations and their cash flows for the period
from January 1, 2001 to January 31, 2001, in conformity with accounting
principles generally accepted in the United States. 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 Notes 1 and 4 to the consolidated financial statements,
effective January 31, 2001, the Company completed a merger transaction resulting
in a change of control and a new basis of accounting. As discussed in Note 2 to
the consolidated financial statements, the Company adopted Statement of
Financial Accounting Standards ("SFAS") 142 effective January 1, 2002, SFAS 123
effective January 1, 2003 and Financial Accounting Standards Board
Interpretation No. 46 effective December 31, 2003.
/s/ ERNST & YOUNG LLP
Houston, Texas
February 4, 2004
47
TODCO AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
POST-TRANSOCEAN MERGER
-----------------------
DECEMBER 31,
-----------------------
2003 2002
---------- ----------
(IN MILLIONS, EXCEPT
SHARE DATA)
ASSETS
Cash and cash equivalents................................... $ 20.0 $ --
Accounts receivable
Trade..................................................... 52.3 40.8
Related party............................................. 0.9 345.7
Other..................................................... 4.6 13.4
Interest receivable -- related party........................ -- 1.7
Materials and supplies...................................... 4.5 4.9
Other current assets........................................ 3.2 17.5
Current assets related to discontinued operations........... 0.1 152.9
--------- ---------
Total current assets................................... 85.6 576.9
--------- ---------
Property and equipment...................................... 924.9 871.6
Less accumulated depreciation............................... 264.0 165.2
--------- ---------
Property and equipment, net............................... 660.9 706.4
--------- ---------
Investments in and advances to joint ventures............... 0.1 79.7
Other assets................................................ 31.6 21.6
Non-current assets related to discontinued operations....... -- 842.6
--------- ---------
Total assets........................................... $ 778.2 $ 2,227.2
========= =========
LIABILITIES AND SHAREHOLDER'S EQUITY
Accounts payable
Trade..................................................... $ 24.7 $ 11.6
Related party............................................. -- 70.1
Accrued income taxes........................................ 11.1 22.5
Debt due within one year.................................... 1.2 15.5
Debt due within one year -- related party................... 3.0 100.0
Interest payable -- related party........................... 4.3 5.7
Other current liabilities................................... 43.4 49.8
Current liabilities related to discontinued operations...... 0.5 102.6
--------- ---------
Total current liabilities.............................. 88.2 377.8
--------- ---------
Long-term debt.............................................. 25.6 25.2
Long-term debt -- related party............................. 522.0 980.1
Deferred income taxes....................................... -- 67.1
Other long-term liabilities................................. 4.7 5.0
Non-current liabilities related to discontinued
operations................................................ -- 210.1
--------- ---------
Total long-term liabilities............................ 552.3 1,287.5
--------- ---------
Commitments and contingencies
Common stock, Class A, $0.01 par value, 500,000,000 shares
authorized, none outstanding at December 31, 2003 and
2002...................................................... -- --
Common stock, Class B, $0.01 par value, 260,000,000 shares
authorized, 12,144,751 shares issued and outstanding at
December 31, 2003 and 2002................................ 0.1 0.1
Additional paid-in capital.................................. 6,136.3 6,276.3
Accumulated other comprehensive loss........................ -- (2.0)
Retained deficit............................................ (5,998.7) (5,712.5)
--------- ---------
Total shareholder's equity............................. 137.7 561.9
--------- ---------
Total liabilities and shareholder's equity............. $ 778.2 $ 2,227.2
========= =========
See accompanying notes.
48
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
----------------------------------------------- ------------ ------------ ------------- --------------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
OPERATING REVENUES............................. $ 227.7 $ 187.8 $ 441.0 $ 48.5
COSTS AND EXPENSES
Operating and maintenance.................... 215.7 176.6 260.9 23.2
Operating and maintenance -- related party... 11.7 9.1 9.1 --
Depreciation................................. 92.2 91.9 96.5 6.3
Goodwill amortization........................ -- -- 42.9 0.2
General and administrative................... 14.9 19.2 17.4 60.8
General and administrative -- related
party...................................... 1.4 9.7 2.0 --
Impairment loss on long-lived assets......... 11.3 399.4 1.1 64.0
Gain on disposal of assets, net.............. (0.8) (1.0) (3.3) (0.4)
------- --------- ------- -------
346.4 704.9 426.6 154.1
OPERATING INCOME (LOSS)........................ (118.7) (517.1) 14.4 (105.6)
OTHER INCOME (EXPENSE), NET
Equity in loss of joint ventures............. (6.6) (2.7) (0.9) --
Interest income.............................. 0.6 3.0 4.9 1.4
Interest income -- related party............. 3.3 33.6 16.2 0.2
Interest expense, net of amounts
capitalized................................ (3.0) (22.4) (88.2) (19.8)
Interest expense -- related party............ (43.5) (79.7) (36.8) --
Loss on retirement of debt................... (79.5) (18.8) (27.5) --
Impairment of investment in and advance to
joint venture.............................. (21.3) -- -- --
Other, net................................... (2.8) 0.3 (0.4) 0.3
------- --------- ------- -------
(152.8) (86.7) (132.7) (17.9)
LOSS FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES, MINORITY INTEREST AND CUMULATIVE
EFFECT OF A CHANGE IN ACCOUNTING PRINCIPLE... (271.5) (603.8) (118.3) (123.5)
Income tax benefit............................. (50.1) (74.6) (21.6) (33.4)
Minority interest.............................. 0.6 (0.1) -- --
------- --------- ------- -------
LOSS FROM CONTINUING OPERATIONS BEFORE
CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE.................................... (222.0) (529.1) (96.7) (90.1)
DISCONTINUED OPERATIONS:
(Loss) income from operations of discontinued
segment...................................... (43.9) (480.8) (12.1) 2.7
Income tax expense........................... 19.9 27.6 44.6 1.2
Minority interest............................ 1.2 3.7 0.7 0.7
------- --------- ------- -------
Net (loss) income from discontinued
operations before cumulative effect of a
change in accounting principle........... (65.0) (512.1) (57.4) 0.8
LOSS BEFORE CUMULATIVE EFFECT OF A CHANGE IN
ACCOUNTING PRINCIPLE......................... (287.0) (1,041.2) (154.1) (89.3)
Cumulative effect of a change in accounting
principle -- continuing operations........... 0.8 (1,363.7) -- --
Cumulative effect of a change in accounting
principle -- discontinued operations......... -- (3,153.3) -- --
------- --------- ------- -------
NET LOSS....................................... $(286.2) $(5,558.2) $(154.1) $ (89.3)
======= ========= ======= =======
NET LOSS PER COMMON SHARE BASIC AND DILUTED
Continuing operations........................ $(18.28) $ (43.57) $ (7.96) $ (0.43)
Discontinued operations...................... (5.35) (42.16) (4.73) 0.01
Cumulative effect of a change in accounting
principle.................................. 0.07 (371.92) -- --
------- --------- ------- -------
Net loss per common share basic and
diluted.................................. $(23.56) $ (457.65) $(12.69) $ (0.42)
======= ========= ======= =======
WEIGHTED AVERAGE COMMON SHARES OUTSTANDING:
Basic and diluted............................ 12.1 12.1 12.1 211.3
------- --------- ------- -------
See accompanying notes.
49
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE LOSS
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
----------------------------------------- ------------ ------------ ------------- --------------
(IN MILLIONS)
Net loss................................. $(286.2) $(5,558.2) $(154.1) $(89.3)
------- --------- ------- ------
Other comprehensive income (loss)
Change in share of unrealized income
(loss) in unconsolidated joint
venture's accumulated other
comprehensive loss (net of tax
(expense) benefit of $(1.1), $(0.1),
and $1.2 for each of the years ended
December 31, 2003 and 2002 and the
eleven months ended December 31,
2001, respectively)................. 2.0 0.3 (2.3) --
Change in unrealized (loss) on
securities held for sale, net of
tax................................. -- -- (0.2) (0.1)
------- --------- ------- ------
Other comprehensive income (loss)...... -- 0.3 (2.5) (0.1)
------- --------- ------- ------
Total comprehensive loss................. $(284.2) $(5,557.9) $(156.6) $(89.4)
======= ========= ======= ======
See accompanying notes.
50
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
ACCUMULATED
OTHER
COMMON STOCK ADDITIONAL COMPREHENSIVE RETAINED
--------------- PAID-IN INCOME EARNINGS UNEARNED TOTAL
SHARES AMOUNT CAPITAL (LOSS) (DEFICIT) COMPENSATION EQUITY
------ ------ ---------- ------------- --------- ------------ ---------
(IN MILLIONS)
PRE-TRANSOCEAN MERGER
Balance at December 31,
2000........................ 212.0 $ 2.1 $1,458.1 $ 0.3 $ (82.9) $(4.1) $ 1,373.5
Net loss.................... (89.3) (89.3)
Activity in stock plans..... 0.1 6.3 4.1 10.4
Change in unrealized gain on
securities held for
sale...................... (0.1) (0.1)
Contribution to employee
savings plans............. 0.6 0.6
------ ----- -------- ----- --------- ----- ---------
Balance at January 31, 2001... 212.1 2.1 1,465.0 0.2 (172.2) -- 1,295.1
-------------------------------------------------------------------------------------------------------------------
POST-TRANSOCEAN MERGER
Net loss.................... (154.1) (154.1)
Merger with Transocean...... (200.0) (2.0) 5,178.8 172.2 5,349.0
Tax benefit from options
exercised................. 9.0 9.0
Other comprehensive loss
related to unconsolidated
joint venture............. (2.3) (2.3)
Change in unrealized gain on
securities held for
sale...................... (0.2) (0.2)
------ ----- -------- ----- --------- ----- ---------
Balance at December 31,
2001........................ 12.1 0.1 6,652.8 (2.3) (154.1) -- 6,496.5
Net loss.................... (5,558.2) (5,558.2)
Net distributions to
parent.................... (376.8) (376.8)
Tax benefit from options
exercised................. 0.3 0.3
Change in other
comprehensive loss related
to unconsolidated joint
venture................... 0.3 0.3
Other....................... (0.2) (0.2)
------ ----- -------- ----- --------- ----- ---------
Balance at December 31,
2002........................ 12.1 0.1 6,276.3 (2.0) (5,712.5) -- 561.9
Net loss.................... (286.2) (286.2)
Net distributions to
parent.................... (224.6) (224.6)
Equity contribution from
parent.................... 84.6 84.6
Change in other
comprehensive loss related
to unconsolidated joint
venture................... 2.0 2.0
------ ----- -------- ----- --------- ----- ---------
Balance at December 31,
2003........................ 12.1 $ 0.1 $6,136.3 $ -- $(5,998.7) $ -- $ 137.7
====== ===== ======== ===== ========= ===== =========
See accompanying notes.
51
TODCO AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
---------------------------------------------------- ------------ ------------ ------------- --------------
(IN MILLIONS)
CASH FLOWS FROM OPERATING ACTIVITIES -- CONTINUING
OPERATIONS AND DISCONTINUED OPERATIONS
Net loss.......................................... $(286.2) $(5,558.2) $ (154.1) $(89.3)
Adjustments to reconcile net loss to net cash
provided by (used in) operating activities:
Cumulative effect of a change in accounting
principle..................................... (0.8) 4,517.0 -- --
Depreciation.................................... 102.5 169.3 209.6 17.7
Goodwill amortization........................... -- -- 128.2 0.2
Impairment loss on goodwill..................... -- 932.2 -- --
Deferred income taxes........................... (34.9) (56.5) 1.3 (33.3)
Equity in earnings of joint ventures............ 1.1 (3.6) (11.5) (0.4)
Net loss from disposal of assets................ 9.1 2.9 32.2 --
Impairment loss on long-lived assets............ 11.3 55.4 27.8 64.0
Amortization of debt fair value adjustments..... (3.0) (10.6) (19.9) --
Deferred compensation........................... -- -- -- 9.8
Deferred income, net............................ (5.5) (2.9) 6.3 (1.0)
Deferred expenses, net.......................... (15.3) 0.7 (13.7) 1.5
Loss from retirement of debt.................... 79.5 18.8 27.5 --
Impairment of investment in and advance to joint
venture....................................... 21.3 -- -- --
Changes in operating assets and liabilities, net
of effects from the Transocean Merger
Accounts receivable, net...................... 41.2 106.0 37.8 (20.1)
Accounts payable and other current
liabilities................................ (20.3) (45.5) (121.7) (14.3)
Accounts receivable/payable to related party,
net........................................ 202.9 (116.8) (64.8) --
Income taxes receivable/payable, net.......... (4.2) (7.9) (3.9) 2.9
Other, net.................................... 4.4 13.8 17.6 26.6
------- --------- --------- ------
Net cash provided by (used in) operating
activities........................................ 103.1 14.1 98.7 (35.7)
------- --------- --------- ------
CASH FLOWS FROM INVESTING ACTIVITIES -- CONTINUING
OPERATIONS AND DISCONTINUED OPERATIONS
Capital expenditures.............................. (16.1) (17.7) (216.3) (16.5)
Proceeds from settlement of notes receivable from
related party................................... -- 518.0 -- --
Proceeds from disposal of assets, net............. 75.0 53.4 90.6 0.2
Proceeds from sale of subsidiary, net............. -- -- 85.6 --
Purchase of minority interest in subsidiary....... -- -- -- (34.7)
Joint ventures and other investments, net......... 0.6 2.1 13.6 (1.9)
------- --------- --------- ------
Net cash provided by (used in) investing
activities........................................ 59.5 555.8 (26.5) (52.9)
------- --------- --------- ------
CASH FLOWS FROM FINANCING ACTIVITIES -- CONTINUING
OPERATIONS AND DISCONTINUED OPERATIONS
Net proceeds from long-term debt with related
party........................................... (54.0) 47.3 1,245.0 --
Repayments on other debt instruments.............. (89.1) (38.6) (1,516.3) (8.1)
Repayments on other debt instruments to related
party........................................... -- (529.2) -- --
Decrease in cash dedicated to debt service........ -- -- 3.7 2.7
Cash of subsidiaries at disposition to
affiliates...................................... (103.9) (10.4) -- --
Exchange offer consent payments................... -- (8.3) -- --
Other, net........................................ 1.5 3.7 (1.1) 1.0
------- --------- --------- ------
Net cash used in financing activities............... (245.5) (535.5) (268.7) (4.4)
------- --------- --------- ------
Net (decrease) increase in cash and cash
equivalents....................................... (82.9) 34.4 (196.5) (93.0)
Cash and cash equivalents at beginning of period --
continuing operations and discontinued
operations........................................ 102.9 68.5 265.0 358.0
------- --------- --------- ------
Cash and cash equivalents at end of
period -- continuing operations and discontinued
operations........................................ $ 20.0 $ 102.9 $ 68.5 $265.0
======= ========= ========= ======
See accompanying notes.
52
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1 -- NATURE OF BUSINESS AND PRINCIPLES OF CONSOLIDATION
TODCO (formerly known as "R&B Falcon Corporation", together with its
subsidiaries and predecessors, unless the context requires otherwise, the
"Company," "we" or "our") is a leading provider of offshore and inland marine
contract oil and gas drilling services. At December 31, 2003, the Company owned,
had partial ownership interests in or operated 70 drilling rigs. As of this
date, the Company's active fleet of drilling rigs consisted of 24 jackup rigs,
30 barge rigs, three submersible rigs and one platform rig as well as nine land
rigs and three lake barge rigs in Venezuela. The Company contracts its drilling
rigs, related equipment and work crews primarily on a dayrate basis to drill oil
and natural gas wells. The Company wound up its turnkey operations in the second
quarter of 2001 and no longer provides turnkey services.
Intercompany transactions and accounts have been eliminated. For
investments in joint ventures that either do not meet the criteria of being a
variable interest entity or where the Company is not deemed to be the primary
beneficiary for accounting purposes, the equity method of accounting is used for
investments in joint ventures where the Company's ownership is between 20
percent and 50 percent and for investments in joint ventures owned more than 50
percent where the Company does not have control of the joint venture. The cost
method of accounting is used for investments in joint ventures where the
Company's ownership is less than 20 percent and the Company does not have
significant influence over the joint venture. For investments in joint ventures
that meet the criteria of a variable interest entity and where the Company is
deemed to be the primary beneficiary for accounting purposes, such entities are
consolidated (see Note 2).
Effective January 31, 2001, the merger transaction between the Company and
Transocean Inc. ("Transocean", formerly known as Transocean Sedco Forex Inc.)
was completed (the "Transocean Merger"). A change of control occurred and the
Company became an indirect wholly owned subsidiary of Transocean. See Note 4.
The merger was accounted for as a purchase with Transocean as the accounting
acquirer. Accordingly, the purchase price was allocated to the assets and
liabilities of the Company based on estimated fair values as of January 31, 2001
with the excess accounted for as goodwill. The purchase price adjustments were
"pushed down" to the consolidated financial statements of the Company, which
affects the comparability of the consolidated financial statements for periods
before and after the Transocean Merger. The accompanying financial statements
for the periods ended on January 31, 2001 were prepared using the Company's
historical basis of accounting and are designated as "Pre-Transocean Merger."
The accompanying consolidated financial statements for the periods subsequent to
January 31, 2001 include the effects of the Transocean Merger and are designated
as "Post-Transocean Merger."
In July 2002, Transocean announced plans to divest of its Gulf of Mexico
shallow and inland water ("Shallow Water") business through an initial public
offering of the Company. During 2003, the Company completed the transfer to
Transocean of all assets not related to its Shallow Water business ("Transocean
Assets"), including the transfer of all revenue-producing assets. Accordingly,
the Transocean Assets and related operations have been reflected as discontinued
operations in the Company's historical financial statements and the notes
thereto. The Company's historical financial statements and the notes thereto
have been restated for the effect of discontinued operations for all periods
presented, except for the statement of cash flows and related Note 12 for which
restatement is not required. See Note 23.
In February 2004, the Company completed its initial public offering of
13,800,000 shares of its Class A common stock ("IPO"), see Notes 14 and 24.
NOTE 2 -- SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Accounting Estimates -- The preparation of consolidated financial
statements in conformity with accounting principles generally accepted in the
United States ("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, the
Company evaluates its 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 post-
53
retirement and employment benefits and contingent liabilities. The Company bases
its 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 could differ
from such estimates.
Segments -- As a result of the IPO and the resulting change in the
Company's chief operating decision maker as defined by the Financial Accounting
Standards Board's ("FASB") Statement of Financial Accounting Standards ("SFAS")
131, "Disclosures about Segments of an Enterprise and Related Information", the
Company has redefined its reportable segments on a basis representative of how
the Company evaluates its operating performance and makes resource allocation
decisions (see Note 24). Accordingly, the Company's operations have been
aggregated into three reportable business segments, which correspond to the
Company's principal geographic regions in which we operate:
- U.S. Inland Barge Segment -- The Company's barge rig fleet currently
operating in this market segment consists of 12 conventional and 18
posted barge rigs. These units operate in marshes, rivers, lakes and
shallow bay or coastal waterways that are known as "transition zone".
This area along the U.S. Gulf Coast, where jackup rigs are unable to
operate, is the world's largest market for this type of equipment.
- U.S. Gulf of Mexico Segment -- The Company currently operates 19 jackup
and three submersible rigs in the U.S. Gulf of Mexico shallow water
market segment which begins at the outer limit of the transition zone and
extends to water depths of about 350 feet. The Company's jackup rigs in
this market segment consist of independent leg cantilever type units,
mat-supported cantilever type rigs and mat-supported slot type jackup
rigs that can operate in water depths up to 250 feet.
- Other International Segment -- The Company's other operations are
currently conducted in Mexico, Trinidad and Venezuela. In Mexico, the
Company operates two jackup rigs and is preparing a platform rig to
operate for PEMEX, the Mexican national oil company. Additionally, the
Company has two jackup rigs in Trinidad and one in Venezuela, where the
Company also has nine land rigs and three Lake Maracaibo barges.
The Company's historical presentation of reportable business segments for
the year ended December 31, 2002, the eleven months ended December 31, 2001 and
the one month ended January 31, 2001 have been restated to reflect the current
presentation. See Note 19.
Cash and Cash Equivalents -- Cash equivalents are stated at cost plus
accrued interest, which approximates fair value. Cash equivalents are highly
liquid investments with an original maturity of three months or less. Generally,
the maturity date of the Company's cash equivalent investments is the next
business day.
Accounts and Notes Receivable -- Accounts receivable trade 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. Notes
receivable, included in investments in and advances to joint ventures, are
carried at their historical carrying amount net of write-offs and allowance for
loan loss. Interest income on notes receivable, which is included in interest
receivable-related party, is accrued and recognized as interest income monthly
on the unimpaired loan balance. The Company's notes receivable do not have any
associated premiums or discounts. Uncollectible loans and accounts receivable
trade are written off when a settlement is reached for an amount that is less
than the outstanding historical balance. As a result of the Company's
consolidation of Delta Towing Holdings, LLC ("Delta Towing"), a joint venture
formed to own and operate the Company's U.S. marine support vessel business, the
Company's notes receivable and related interest receivable have been eliminated
in the Company's consolidated balance sheet at December 31, 2003 (see "-- New
Accounting Pronouncements" and Note 17).
Allowance for Doubtful Accounts -- The Company establishes an allowance for
doubtful accounts receivable on a case-by-case basis when it believes the
collection of specific amounts owed is unlikely to occur. This allowance was
$5.0 million and $6.7 million at December 31, 2003 and 2002, respectively. An
allowance
54
for loan loss is established when events or circumstances indicate that both the
contractual interest and principal for a note receivable are not fully
collectible. A loan is considered delinquent when principal and/or interest
payments have not been made in accordance with the payment terms of the loan.
Collectibility is determined based on estimated future cash flows discounted at
the respective loan's effective interest rate with the excess of the loan's
total contractual interest and principal over the estimated discounted future
cash flows recorded as an allowance for loan loss. During the year ended
December 31, 2003, the Company recorded an allowance for loan loss of $21.3
million related to its notes receivable from Delta Towing, see Note 18. As a
result of the consolidation of Delta Towing, the allowance, together with the
note receivable were eliminated from the Company's consolidated balance sheet at
December 31, 2003.
Materials and Supplies -- Materials and supplies are carried at the lower
of average cost or market less an allowance for obsolescence. Such allowance was
$0.3 million at December 31, 2003. There was no allowance for obsolescence at
December 31, 2002.
Property and Equipment -- Property and equipment, consisting primarily of
offshore drilling rigs and related equipment, represented approximately 85
percent of the Company's total assets at December 31, 2003. The carrying values
of these assets are based on estimates, assumptions and judgments relative to
capitalized costs, useful lives and salvage values of the Company's rigs. These
estimates, assumptions and judgments reflect both historical experience and
expectations regarding future industry conditions and operations. The Company
provides for 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 to third parties, 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.
As a result of the Transocean Merger, property and equipment were adjusted
to fair value and the Company conformed its policies relating to estimated rig
lives and salvage values to Transocean's policies. Estimated useful lives of
drilling units now range from 10 to 15 years for the majority of our drilling
units, compared to 12 to 18 years prior to the Transocean Merger. Depreciation
expense for the eleven months ended December 31, 2001 increased approximately
$36.9 million as a result of conforming these policies, primarily due to a
decrease in the useful lives of the inland barges.
Assets Held for Sale -- Assets are classified as held for sale when the
Company has a plan for disposal of certain assets and those assets meet the held
for sale criteria of SFAS 144, Accounting for Impairment or Disposal of
Long-Lived Assets. Prior to the Company's adoption of SFAS 144 (see "-- New
Accounting Pronouncements"), certain assets were classified as held for sale
under SFAS 121, Accounting for Impairment of Long-Lived Assets and for
Long-Lived Assets to be Disposed of. Effective with the Transocean Merger, the
Company established a plan to sell certain assets that were considered non-core
to Transocean's business with the disposition of these assets expected to be
complete by December 31, 2002. At December 31, 2002, the Company had either
disposed of these non-core assets, including certain drilling rigs, surplus
equipment and an office building, or reclassified them to property and equipment
in accordance with SFAS 144. There were no assets classified as held for sale at
December 31, 2003.
Goodwill -- Prior to the adoption of SFAS 142, Goodwill and Other
Intangible Assets effective January 1, 2002, the excess of the purchase price
over the estimated fair value of net assets acquired was accounted for as
goodwill and was amortized on a straight-line basis over a 40-year life. The
amortization period was based on the nature of the offshore drilling industry
and the Company's long-lived drilling equipment.
During the first quarter of 2002, the Company implemented SFAS 142 and
performed the initial test of impairment of goodwill. The test was applied
utilizing the estimated fair value of the Company as of January 1, 2002 and was
determined based on a combination of the Company's discounted cash flows and
publicly traded company multiples and acquisition multiples of comparable
businesses. Because of deterioration in the Gulf of Mexico shallow and inland
water market sector since the completion of the Transocean Merger, a $1,363.7
million impairment of goodwill was recognized as a cumulative effect of a change
in accounting principle in the first quarter of 2002. Additionally, due to a
general decline in market conditions and other factors, the Company recognized a
$3,153.3 million impairment of goodwill related to discontinued
55
operations, which was recognized as a cumulative effect of a change in
accounting principle in the first quarter of 2002.
During the fourth quarter of 2002, the Company performed its annual test of
goodwill impairment. Due to a general decline in market conditions, the Company
recognized a non-cash impairment charge of $381.9 million. After giving effect
to the goodwill write-downs, the Company had no goodwill balance as of December
31, 2002 or December 31, 2003.
Net loss for the year ended December 31, 2002, the eleven months ended
December 31, 2001 and the one month ended January 31, 2001, adjusted for
goodwill amortization, was as follows (in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
---------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, JANUARY 31,
2002 2001 2001
--------------------------------------------- ------------ ------------- --------------
Reported net loss before cumulative effect of
a change in accounting principle........... $(1,041.2) $(154.1) $(89.3)
Add back: goodwill amortization.............. -- 42.9 0.2
--------- ------- ------
Adjusted reported net loss before cumulative
effect of a change in accounting
principle.................................. (1,041.2) (111.2) (89.1)
Cumulative effect of a change in accounting
principle.................................. (4,517.0) -- --
--------- ------- ------
Adjusted net loss............................ $(5,558.2) $(111.2) $(89.1)
========= ======= ======
Basic and diluted loss per share Reported net
loss applicable to common shareholders
before cumulative effect of a change in
accounting principle....................... $ (85.73) $(12.69) $(0.42)
Add back: goodwill amortization.............. -- 3.53 --
--------- ------- ------
Adjusted reported net loss before cumulative
effect of a change in accounting
principle.................................. (85.73) (9.16) (0.42)
Cumulative effect of a change in accounting
principle.................................. (371.92) -- --
--------- ------- ------
Adjusted net loss per share basic and
diluted.................................... $ (457.65) $ (9.16) $(0.42)
========= ======= ======
Impairment of Long-Lived Assets -- The carrying value of long-lived assets,
principally goodwill and 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 net realizable value. See Note 10. Prior to January 1, 2002,
recoverability of goodwill was determined based upon a comparison of the
Company's net book value to the undiscounted cash flows associated with the
related assets. See "-- Goodwill."
Operating Revenues and Expenses -- Operating revenues are recognized as
earned, based on contractual daily rates or on a fixed price basis. Although the
Company ceased providing turnkey drilling services in 2001, turnkey profits were
recognized on completion of the well and acceptance by the customer. Events
occurring after the date of the financial statements and before the financial
statements are issued that are within the normal exposure and risk aspects of
the turnkey contracts are considered refinements of the estimation process of
the prior year and are recorded as adjustments at the date of the financial
statements. Provisions for losses are made on contracts in progress when losses
are anticipated. In connection with drilling contracts, the Company 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
56
incurred directly related to the preparation and mobilization of the rig are
deferred and recognized over the primary contract term of the drilling project
for contracts that have a primary contract term of two months or longer and
where such amounts are material. 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 remaining useful life of the asset.
At December 31, 2003, $21.2 million in deferred preparation and
mobilization costs were included in other assets in the Company's consolidated
balance sheet. There were no similar deferred costs at December 31, 2002. During
2003, the Company amortized $1.2 million of these costs, which is included in
operating and maintenance expense in the Company's consolidated statement of
operations.
Foreign Currency Translation -- The Company accounts for translation of
foreign currency in accordance with SFAS 52, Foreign Currency Translation. The
majority of the Company's revenues and expenditures are denominated in U.S.
dollars to limit the Company's exposure to foreign currency fluctuations,
resulting in the use of the U.S. dollar as the functional currency for all of
the Company's operations. Foreign currency translations and exchange gains and
losses are included in other income (expense), net as incurred. Net foreign
currency exchange gains (losses) were $(2.7) million, $0.4 million, $(0.3)
million and $0.3 million for the years ended December 31, 2003 and 2002, the
eleven months ended December 31, 2001 and the one month ended January 31, 2001,
respectively.
Income Taxes -- Income taxes have been provided based upon the tax laws and
rates in the countries in which operations are conducted and income is earned.
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 the Company's 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 12.
Stock-Based Compensation -- In accordance with the provisions of SFAS 123,
Accounting for Stock-based Compensation, the Company has elected to follow the
Accounting Principles Board Opinion ("APB") 25, Accounting for Stock Issued to
Employees, and related interpretations in accounting for its employee
stock-based compensation plans through December 31, 2002. Under the intrinsic
value method of APB 25, if the exercise price of employee stock options equals
or exceeds the fair value of the underlying stock on the date of grant, no
compensation expense is recognized. If an employee stock option is modified
subsequent to the original grant date, and the exercise price is less than the
fair value of the underlying stock on the date of the modification, compensation
expense equal to the excess of the fair value over the exercise price is
recognized over the remaining vesting period. Compensation expenses for grants
of restricted shares to employees is calculated based on the fair value of the
shares on the date of grant and is recognized over the vesting period. Stock
appreciation rights are considered variable grants and are recorded at fair
value, with the change in the recorded fair value recognized as compensation
expense.
Effective January 1, 2003, the Company 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, Accounting for
Stock-Based Compensation -- Transition and Disclosure, the recognition
provisions are applied to all employee awards granted, modified or settled after
January 1, 2003. See Notes 15 and 24.
The compensation expense related to stock-based employee compensation
included in the determination of net income for the years ended December 31,
2003 and 2002 and the eleven months ended December 31, 2001 is less than that
which would have been recognized if the fair value method had been applied to
all awards granted after the original effective date of SFAS 123. If the Company
had elected to adopt the fair
57
value recognition provisions of SFAS 123 as of its original effective date pro
forma net income and diluted net income per share would have been as follows (in
millions, except per share amounts):
POST-TRANSOCEAN MERGER
-------------------------------------------
ELEVEN MONTHS
YEAR ENDED YEAR ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31,
2003 2002 2001
------------ ------------ -------------
Net loss applicable to common stockholders as
reported..................................... $(286.2) $(5,558.2) $(154.1)
Add: stock-based employee compensation included
in reported net income, net of related tax
effects...................................... -- -- --
Deduct: total stock-based employee compensation
expense under fair value based method for all
awards, net of tax........................... 0.5 1.8 0.6
------- --------- -------
Pro forma net loss applicable to common
stockholders................................. $(286.7) $(5,560.0) $(154.7)
======= ========= =======
Basic and diluted loss per share
As reported.................................. $(23.56) $ (457.65) $(12.69)
Pro forma.................................... $(23.61) $ (457.80) $(12.74)
The pro forma effect on net loss for the one month ended January 31, 2001
was not significant. The pro forma net loss effects of applying SFAS 123
recognition of compensation expense for the periods shown above may not be
representative of the effects on reported net income for future years.
There were no options granted to the Company's employees under the
Transocean Incentive Plan for the year ended December 31, 2003. The fair value
of each option grant under the Transocean Incentive Plans for the years ended
December 31, 2003 and 2002 and the eleven months ended December 31, 2001 was
estimated using the Black-Scholes options pricing model with the following
weighted-average assumptions:
POST-TRANSOCEAN MERGER
----------------------------
ELEVEN MONTHS
YEAR ENDED ENDED
DECEMBER 31, DECEMBER 31,
2002 2001
------------ -------------
Dividend yield............................................. 0.00% 0.30%
Expected price volatility.................................. 50.7% 50.2%
Risk-free interest rate.................................... 3.49% 4.25%
Expected life of options (in years)........................ 3.9 4.1
Weighted-average fair value of options granted............. $12.24 $16.45
There were no outstanding awards under the Company's long-term incentive
plan at December 31, 2003. See Note 24.
New Accounting Pronouncements -- In April 2002, the FASB issued SFAS 145,
Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No.
13, and Technical Corrections. This statement eliminates the requirement under
SFAS 4 to aggregate and classify all gains and losses from extinguishment of
debt as an extraordinary item, net of related income tax effect. This statement
also amends SFAS 13 to require certain lease modifications with economic effects
similar to sale-leaseback transactions be accounted for in the same manner as
sale-leaseback transactions. In addition, SFAS 145 requires reclassification of
gains and losses in all prior periods presented in comparative financial
statements related to debt extinguishment that do not meet the criteria for
extraordinary item in APB 30. The statement is effective for fiscal years
beginning after May 15, 2002 with early adoption encouraged. The Company adopted
SFAS 145 effective January 1, 2002. The adoption of this statement had no effect
on the Company's consolidated financial position or results of operations.
In December 2002, the FASB issued SFAS 148, Accounting for Stock-Based
Compensation -- Transition and Disclosure, which is effective for fiscal years
ending after December 15, 2002. SFAS 148
58
amends SFAS 123, Accounting for Stock-Based Compensation, to permit two
additional transition methods for a voluntary change to the fair value based
method of accounting for stock-based employee compensation from the intrinsic
method under APB 25. The prospective method of transition under SFAS 123 is an
option for entities adopting the recognition provisions of SFAS 123 in a fiscal
year beginning before December 15, 2003. In addition, SFAS 148 amends the
disclosure requirements of SFAS 123 to require prominent disclosures in both
annual and interim financial statements concerning the method of accounting used
for stock-based employee compensation and the effects of that method on reported
results of operations. Under SFAS 148, pro forma disclosures are required in a
specific tabular format in the "Summary of Significant Accounting Policies". The
Company has adopted the disclosure requirements of this statement effective
December 31, 2002. The adoption had no effect on the Company's consolidated
financial position or results of operations. The Company adopted the fair value
method of accounting for stock-based compensation using the prospective method
of transition under SFAS 123 effective January 1, 2003. As a result of the
completion of the Company's initial public offering in February 2004 (see Notes
1 and 24), management expects compensation expense will increase approximately
$11 million in 2004 as a result of the adoption. See "-- Stock-Based
Compensation".
In January 2003, the FASB issued Interpretation No. 46, Consolidation of
Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51 ("FIN 46"). FIN 46 requires that an enterprise consolidate a variable
interest entity ("VIE") if the enterprise has a variable interest that will
absorb a majority of the entity's expected losses and/or receives a majority of
the entity's expected residual returns as a result of ownership, contractual or
other financial interests in the entity, if such loss or residual return occurs.
If one enterprise absorbs a majority of a VIE's expected losses and another
enterprise receives a majority of that entity's expected residual returns, the
enterprise absorbing a majority of the losses is required to consolidate the VIE
and will be deemed the primary beneficiary. FIN 46 is effective immediately for
those VIEs created after January 31, 2003. The provisions, as amended, are
effective for the first interim or annual period ending after December 15, 2003
for those VIEs held prior to February 1, 2003 that are considered to be special
purpose entities. The provisions, as amended, are to be applied no later than
the end of the first reporting period that ends after March 14, 2004 for all
other VIEs held prior to February 1, 2003. Early is adoption is allowed. The
Company adopted and applied the provisions of FIN 46 effective December 31,
2003. See Note 17.
Reclassifications -- Certain reclassifications have been made to prior
period amounts to conform with the current period's presentation.
In connection with the IPO, certain components of costs previously
classified in operating and maintenance expense were reviewed and reclassified
to general and administrative expense to be consistent with the ongoing
classification of the Company's corporate support costs. The aggregate costs
reclassified totaled $17.1 million for the year ended December 31, 2002 and
$12.7 million for the eleven months ended December 31, 2001. This
reclassification had no effect on the Company's previously reported operating
income or net income.
59
NOTE 3 -- OTHER COMPREHENSIVE INCOME (LOSS)
The components of accumulated other comprehensive income (loss) are as
follows (in millions):
OTHER
UNREALIZED COMPREHENSIVE TOTAL OTHER
GAINS ON LOSS RELATED TO COMPREHENSIVE
AVAILABLE-FOR-SALE UNCONSOLIDATED INCOME
SECURITIES JOINT VENTURE (LOSS)
------------------ ---------------- -------------
PRE-TRANSOCEAN MERGER
Balance at December 31, 2000.............. $ 0.3 $ -- $ 0.3
Other comprehensive loss................ (0.1) -- (0.1)
Balance at January 31, 2001............... 0.2 -- 0.2
-------------------------------------------------------------------------------------------------
POST-TRANSOCEAN MERGER
Other comprehensive loss................ (0.2) (2.3) (2.5)
----- ----- -----
Balance at December 31, 2001.............. -- (2.3) (2.3)
Other comprehensive income.............. -- 0.3 0.3
----- ----- -----
Balance at December 31, 2002.............. -- (2.0) (2.0)
Other comprehensive income.............. -- 2.0 2.0
----- ----- -----
Balance at December 31, 2003.............. $ -- $ -- $ --
===== ===== =====
NOTE 4 -- TRANSOCEAN MERGER
On August 19, 2000, the Company entered into an Agreement and Plan of
Merger with Transocean, whereby each share of the Company's common stock would
convert into 0.5 ordinary shares of Transocean. The Company's common
shareholders approved the Transocean Merger at a special meeting on December 12,
2000. On January 31, 2001, the Transocean Merger was completed and the Company
became an indirect wholly owned subsidiary of Transocean and a new board of
directors was elected. In connection with the merger, Transocean assumed
warrants and options exercisable for the Company's common stock prior to the
Transocean Merger. At the merger date such warrants and options were exercisable
for approximately 13 million Transocean ordinary shares.
The purchase price of $6.7 billion was comprised of $6.1 billion market
value of Transocean's ordinary shares issued in the merger and the estimated
fair value of Transocean's stock options and warrants that replaced the
Company's stock options and warrants at the time of the merger of $0.6 billion.
The market capitalization of Transocean's ordinary shares was calculated using
the average closing price of Transocean's ordinary shares for a period
immediately before and after August 21, 2000, the date the merger was announced.
In January 2001, in connection with the Transocean Merger, the Company
recorded a pre-tax expense of approximately $58 million including: (1) a $19.6
million investment advisory fee, (2) $25.1 million of termination benefits to
seven employees in accordance with employment contracts, and (3) a $9.5 million
charge due to the acceleration of vesting of certain stock options and
restricted stock grants previously awarded to certain employees. In addition, in
connection with the Transocean Merger, the Company was required to dispose of
its marine support vessel business, consisting primarily of shallow water tugs,
crewboats and utility barges. As a result, the Company contributed its marine
support vessel business to a joint venture, Delta Towing Holdings, LLC ("Delta
Towing"), in return for secured contingent notes with a face value of $144.0
million and a 25 percent ownership interest in Delta Towing. The Company
recorded a pre-tax charge of $64.0 million in January 2001, which is included in
impairment loss on long-lived assets to reflect the fair value of the
consideration received in the exchange. See Note 18.
In conjunction with the Transocean Merger, the Company established a
liability of $16.5 million for the estimated severance-related costs associated
with the involuntary termination of 569 of the Company's employees pursuant to
management's plan to consolidate operations and administrative functions and to
60
dispose of the Venezuela operations post-merger. Included in the 569 planned
involuntary terminations were 387 employees engaged in the Company's land
drilling business in Venezuela. The Company has suspended active marketing
efforts to divest this business and, as a result, reduced the estimated
liability by $4.3 million in the third quarter of 2001 with an offset to
goodwill. As of December 31, 2002, all required severance-related costs were
paid to 182 employees whose positions were eliminated as a result of this plan.
NOTE 5 -- VENEZUELAN FINANCIAL ASSETS
Due to continuing political instability in Venezuela and the continuation
of recent foreign exchange controls, the Company established a currency
valuation allowance of $2.4 million pertaining to cash and receivables in
Venezuela in the second quarter of 2003 to adjust the Company's Venezuelan
financial assets to net realizable value as of June 30, 2003. As of December 31,
2003, the Company had financial assets denominated in local currency with a net
carrying value of $3.7 million. The foreign exchange controls limit the
Company's ability to convert local currency into U.S. dollars and transfer
excess funds out of Venezuela. In August 2003, the Company negotiated an
agreement with its principal customer in Venezuela to pay the majority of the
contracted U.S. dollar denominated dayrate in U.S. dollars to one of our banks
in the United States.
NOTE 6 -- DEBT AND CAPITAL LEASE OBLIGATIONS
THIRD PARTY OBLIGATIONS
Third party debt and capital lease obligations, which excludes debt to
Transocean and its affiliates, net of unamortized discounts, premiums and fair
value adjustments, is comprised of the following (in millions):
POST-TRANSOCEAN
MERGER
DECEMBER 31,
---------------
2003 2002
------ ------
6.5% Senior Notes, due April 2003........................... $ -- $ 5.0
9.125% Senior Notes, due December 2003...................... -- 10.5
6.75% Senior Notes, due April 2005.......................... 7.8 7.8
6.95% Senior Notes, due April 2008.......................... 2.2 2.2
9.5% Senior Notes, due December 2008........................ 11.4 11.7
7.375% Senior Notes, due April 2018......................... 3.5 3.5
Capital Lease Obligations................................... 1.9 --
----- -----
Total..................................................... 26.8 40.7
Less debt due within one year............................. 1.2 15.5
----- -----
Total long-term debt...................................... $25.6 $25.2
===== =====
The expected maturity of the face value of the Company's third party debt,
excluding capital lease obligations, is as follows (in millions):
YEARS ENDED
DECEMBER 31,
------------
2004........................................................ $ --
2005........................................................ 7.7
2006........................................................ --
2007........................................................ --
2008........................................................ 12.4
Thereafter.................................................. 3.5
-----
Total..................................................... $23.6
=====
61
Third Party Debt -- Revolving Credit Facility. In December 2003, the
Company entered into a two-year $75 million floating-rate secured revolving
credit facility that will decline to $60 million in December 2004.
The facility is secured by most of the Company's drilling rigs,
receivables, the stock of most of its U.S. subsidiaries and is guaranteed by
some of its subsidiaries. Borrowings under the facility bear interest at our
option at either (1) the higher of (A) the prime rate and (B) the federal funds
rate plus 0.5%, plus a margin in either case of 2.50% or (2) the Eurodollar rate
plus a margin of 3.50%. Commitment fees on the unused portion of the facility
are 1.5% of the average daily balance and are payable quarterly. Borrowings and
letters of credit issued under the facility are limited by a borrowing base
equal to the lesser of (A) 20% of the orderly liquidated value of the drilling
rigs securing the facility, as determined from time to time by a third party
selected by the agent under the facility, and (B) the sum of 10% of the orderly
liquidated value of the drilling rigs securing the facility plus 80% of the U.S.
accounts receivable outstanding less than 90 days, net of any provision for bad
debt associated with such U.S. accounts receivable.
Financial covenants include maintenance of the following:
- a ratio of (1) current assets plus unused availability under the facility
to (2) current liabilities (excluding specified subordinated liabilities
owed to Transocean) of at least 1.2 to 1,
- a ratio of total debt to total capitalization of not more than 20%
(excluding specified subordinated liabilities owed to Transocean from
debt but including those liabilities in total capitalization),
- tangible net worth plus specified subordinated liabilities owed to
Transocean of not less than the sum of (1) $425 million plus (2) to the
extent positive, 50% of net income after December 31, 2003,
- a ratio of (1) the orderly liquidation value of the drilling rigs
securing the facility to (2) the amount of borrowings and letters of
credit outstanding under the facility of not less than 3 to 1, and
- in the event liquidity (defined as working capital (excluding specified
subordinated liabilities owed to Transocean) plus availability under the
facility) is less than $25 million, a ratio of (1) EBITDA minus capital
expenditures during the preceding 12 fiscal months to (2) interest
expense (excluding interest on specified subordinated debt owed to
Transocean) during such period of not less than 2 to 1.
The revolving credit facility provides, among other things, for the
issuance of letters of credit that the Company may utilize to guarantee its
performance under some drilling contracts, as well as insurance, tax and other
obligations in various jurisdictions. The facility also provides for customary
fees and expense reimbursements and includes other covenants (including
limitations on the incurrence of debt, mergers and other fundamental changes,
asset sales and dividends) and events of default (including a change of control)
that are customary for similar secured non-investment grade facilities.
As of December 31, 2003, the Company had no borrowings outstanding under
the facility.
Third Party Debt -- 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior
Notes and Exchange Offer -- In April 1998, the Company issued 6.5% Senior Notes,
6.75% Senior Notes, 6.95% Senior Notes and 7.375% Senior Notes with an aggregate
principal amount of $1.1 billion. In December 1998, the Company issued 9.125%
Senior Notes and 9.5% Senior Notes with an aggregate principal amount of $400.0
million. Each of these notes was recorded at fair value on January 31, 2001 in
conjunction with the Transocean Merger.
In March 2002, Transocean and the Company completed exchange offers and
consent solicitations for the Company'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 the Company's outstanding
6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% notes, respectively, were exchanged
by Transocean for newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Transocean notes having the same principal amount, interest rate, redemption
terms and payment and maturity dates (and accruing interest from the last date
for which interest had been paid on the Company's notes). Because the holders of
a majority in principal amount of each of these series of notes
62
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. Both
the exchanged notes and the notes not exchanged remained the obligation of the
Company. In connection with the Exchange Offer, an aggregate of $8.3 million in
consent payments was made by the Company to holders of the Company'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 $0.5 million and $1.3 million for the years ended December 31,
2003 and 2002, respectively. Transocean is now the holder of the notes that were
exchanged for Transocean notes in the Exchange Offer. Correspondingly, the
Company had debt obligations to Transocean for those exchanged notes. See
"-- Related Party Debt" below for amounts due to Transocean.
In December 2003, the Company repaid all of the $10.2 million outstanding
principal amount of the 9.125% Senior Notes, plus accrued and unpaid interest,
in accordance with their scheduled maturities. In April 2003, the Company repaid
the entire $5.0 million principal amount outstanding of the 6.5% Senior Notes,
plus accrued and unpaid interest, in accordance with their scheduled maturities.
At December 31, 2003, approximately $7.7 million, $2.2 million, $3.5
million, and $10.2 million principal amount of the 6.75%, 6.95%, 7.375%, and
9.5% Senior Notes, respectively, due to third parties were outstanding. The fair
value of these notes at December 31, 2003 was approximately $8.1 million, $2.4
million, $4.0 million, and $12.5 million, respectively, based on the estimated
yield to maturity as of that date.
Third Party Debt -- Redeemed and Repurchased Debt -- In November and
December of 2001, the Company repurchased and retired approximately $11.3
million principal amount of the 9.125% Senior Notes due 2003 and $10.5 million
principal amount of the 6.5% Senior Notes due 2003. The Company funded the
repurchases from cash on hand. The Company recognized a net after-tax loss on
retirement of debt of approximately $0.6 million in the fourth quarter of 2001
relating to the early retirement of this debt.
On April 10, 2001, the Company acquired, pursuant to a tender offer, all of
the approximately $400.0 million principal amount outstanding 11.375% Senior
Secured Notes due 2009 of its affiliate, RBF Finance Co., at 122.51 percent of
principal amount, or $1,225.10 per $1,000 principal amount, plus accrued and
unpaid interest. On April 6, 2001, RBF Finance Co. also redeemed all of the
approximately $400.0 million principal amount outstanding 11% Senior Secured
Notes due 2006 at 125.282 percent, or $1,252.82 per $1,000 principal amount,
plus accrued and unpaid interest. In the second quarter of 2001, the Company
recognized a net after-tax loss on retirement of debt of $14.4 million on the
early retirement of this debt.
On April 6, 2001, the Company redeemed all of the approximately $200.0
million principal amount outstanding 12.25% Senior Notes due 2006 at 130.675
percent or $1,306.75 per $1,000 principal amount, plus accrued and unpaid
interest. In the second quarter of 2001, the Company recognized a net after-tax
loss on retirement of debt of $4.5 million on the early retirement of this debt.
On March 30, 2001, pursuant to an offer made in connection with the
Transocean Merger, Cliffs Drilling Company ("Cliffs Drilling"), a wholly owned
subsidiary of the Company, acquired approximately $0.1 million of the 10.25%
Senior Notes due 2003 at an amount equal to 101 percent of the principal amount.
On May 18, 2001, Cliffs Drilling redeemed all of the approximately $200.0
million principal amount outstanding 10.25% Senior Notes due 2003, at 102.5
percent, or $1,025.00 per $1,000 principal amount, plus interest accrued to the
redemption date. The Company recognized a net after-tax gain on retirement of
debt of $1.6 million in the second quarter of 2001 relating to the early
retirement of this debt.
The Company obtained sufficient funds to pay for the March and April 2001
offers and redemptions from borrowings under a revolving credit agreement with
Transocean (see "-- Related Party Debt" below).
Capital Lease Obligations -- The Company leases certain drilling equipment
under two-year capital lease agreements. During 2003, the Company entered into
two capital lease agreements in the amounts of $1.0 million and $1.1 million
with final maturity dates of September 2005 and October 2005, respectively. Both
lease agreements bear interest at a rate of 10 percent per annum. Assets
recorded under capital leases are included in property and equipment in the
consolidated balance sheets and amounted to $2.1 million at December 31, 2003.
Accumulated depreciation of these assets was not significant for 2003 and is
included in
63
accumulated depreciation combined with the Company's owned assets. Depreciation
expense on these assets was not significant during the year ended December 31,
2003 and is included in depreciation expense.
Future minimum lease payments under scheduled capital leases that have
initial or remaining noncancellable terms in excess of one year are as follows
(in millions):
YEARS ENDING
DECEMBER 31,
------------
2004........................................................ $1.3
2005........................................................ 0.7
----
Total minimum lease payments................................ 2.0
Amount representing interest................................ 0.1
----
Capital lease obligations................................... 1.9
Less amounts due within one year............................ 1.2
----
Long-term capital lease obligations......................... $0.7
====
RELATED PARTY DEBT
Related party debt, net of unamortized discounts, premiums, and fair value
adjustments, is comprised of the following (in millions):
POST-TRANSOCEAN
MERGER
-----------------
DECEMBER 31,
-----------------
2003 2002
------ --------
Revolving Credit Agreement, maturing April 2003............. $ -- $ 100.0
6.75% Senior Notes, due April 2005.......................... 153.2 153.9
6.95% Senior Notes, due April 2008.......................... -- 249.7
9.5% Senior Notes, due December 2008........................ 322.9 329.5
7.375% Senior Notes, due April 2018......................... 45.9 247.0
Other Debt.................................................. 3.0 --
------ --------
Total..................................................... 525.0 1,080.1
Less debt due within one year............................. 3.0 100.0
------ --------
Total long-term debt...................................... $522.0 $ 980.1
====== ========
The expected maturity of the face value of the Company's related party debt
is as follows (in millions):
YEARS ENDED
DECEMBER 31,
------------
2004........................................................ $ 3.0
2005........................................................ 152.5
2006........................................................ --
2007........................................................ --
2008........................................................ 289.8
Thereafter.................................................. 45.8
------
Total..................................................... $491.1
======
Revolving Credit Agreement -- The Company was party to a $1.8 billion
two-year revolving credit agreement (the "Two-Year Revolver") with Transocean,
dated April 6, 2001. Amounts outstanding under the Two-Year Revolver bore
interest quarterly at a rate of the London Interbank Offered Rate ("LIBOR") plus
0.575 percent to 1.3 percent depending on Transocean's non-credit enhanced
senior unsecured public debt
64
rating. On April 6, 2003 the approximately $81.2 million then outstanding under
the Two-Year Revolver was converted into a 2.76% fixed rate promissory note
issued by the Company to Transocean which was scheduled to mature on April 6,
2005. This note was cancelled in full in connection with the sales of the
Company's interest in a wholly-owned subsidiary and interests in two joint
ventures. See "-- 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes" and
Note 13.
During the years ended December 31, 2003 and 2002 and the eleven months
ended December 31, 2001, the Company recognized interest expense of $0.8
million, $1.8 million and $25.4 million, respectively, related to the Two-Year
Revolver.
6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes -- In March 2002
and in conjunction with the Exchange Offer (see "-- Third Party Debt -- 6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes and Exchange Offer" above),
Transocean became the holder of $1,437.8 million aggregate principal amount of
6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes that had previously
been publicly held. In December 2002, the Company repurchased from Transocean
and retired approximately $234.5 million and $76.9 million principal amount
outstanding of the 6.5% and 9.125% Senior Notes, respectively, and approximately
$189.8 million principal amount outstanding of the 6.75% Senior Notes, plus
accrued and unpaid interest. The market values attributed to the repurchased
notes were provided by an independent third party. The repurchased 6.5%, 9.125%
and 6.75% Senior Notes were acquired at market values equal to 101.15 percent,
105.83 percent and 107.91 percent of the principal amount, respectively,
resulting in the recognition of an aggregate loss on retirement of debt, net of
tax, of $12.2 million in the fourth quarter of 2002. The repayment was funded
from cash received from Transocean's repayment to the Company of approximately
$518.0 million aggregate principal amount outstanding notes receivable plus
accrued and unpaid interest.
In March 2003, the Company sold to Transocean its approximate 75 percent
ownership interest in Arcade Drilling AS. In consideration for the sale of this
stock, Transocean cancelled $233.3 million principal amount outstanding of the
6.95% Senior Notes held by Transocean. Interest accrued on these notes was
settled in cash. The market value attributed to the cancelled notes, 113.21
percent of the principal amount, was based on an independent third party
appraisal. The Company recognized a net pre-tax loss on retirement of debt of
$30.0 million in the first quarter of 2003 relating to the early retirement of
this debt.
In May 2003, the Company acquired, and then retired, $13.9 million
principal amount of the 6.95% senior notes in exchange for the sale of Cliffs
Platform Rig 1 to Transocean. The Company recorded a pre-tax loss on retirement
of debt of $1.5 million.
In June 2003, the Company sold to Transocean its membership interests in
its wholly owned subsidiary, R&B Falcon Drilling (International & Deepwater)
Inc. LLC. As consideration for the interests sold, Transocean cancelled $238.8
million principal amount of the Company's outstanding debt held by Transocean
($37.5 million of the 2.76% fixed note (see "-- Revolving Credit Agreement"),
$0.6 million of 6.95% Senior Notes and $200.7 million of 7.375% Notes). The
Company recorded a pre-tax loss on the retirement of debt of $48.0 million in
connection with this transaction. See Note 23.
During the years ended December 31, 2003 and 2002, the Company recognized
$42.7 million and $77.9 million, respectively, in interest expense -- related
party related to these notes held by Transocean.
At December 31, 2003, approximately $152.5 million, $45.8 million and
$289.8 million principal amount of 6.75%, 7.375%, and 9.5% Senior Notes,
respectively, due to Transocean were outstanding. The fair value of these Senior
Notes due to Transocean at December 31, 2003 was approximately $161.3 million,
$52.2 million, and $355.4 million, respectively, based on the estimated yield to
maturity as of that date. See Note 24.
Other Debt -- In connection with the acquisition of the marine business,
Delta Towing entered into a $3.0 million note agreement with Beta Marine
Services, L.L.C. ("Beta Marine") dated January 30, 2001. The note bears interest
at 8%, payable quarterly. In January 2004, Delta Towing failed to make its
scheduled principal payment to Beta Marine. The $3.0 million note has been
classified as a current obligation in the Company's consolidated balance sheet.
65
NOTE 7 -- FINANCIAL INSTRUMENTS AND RISK CONCENTRATION
Foreign Exchange Risk -- The Company's international operations expose the
Company to foreign exchange risk. This risk is primarily associated with
employee compensation costs denominated in currencies other than the U.S. dollar
and with purchases from foreign suppliers. The Company uses a variety of
techniques to minimize exposure to foreign exchange risk, including customer
contract payment terms and foreign exchange derivative instruments.
The Company's 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. Foreign exchange
derivative instruments, specifically foreign exchange forward contracts, may be
used to minimize foreign exchange risk in instances where the primary strategy
is not attainable. A foreign exchange forward contract obligates the Company 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.
Gains and losses on foreign exchange derivative instruments that 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 that 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, 2003 and 2002, the Company did
not have any foreign exchange derivative instruments not qualifying as
accounting hedges.
Interest Rate Risk -- The Company's use of debt directly exposes the
Company to interest rate risk. Fixed rate debt, in which the rate of interest is
fixed over the life of the instrument and the instrument's maturity is greater
than one year, exposes the Company to changes in market rates of interest should
the Company refinance maturing debt with new debt.
In addition, the Company is exposed to interest rate risk in its cash
investments, as the interest rates on these investments change with market
interest rates.
The Company, from time to time, may use interest rate swap agreements to
manage the effect of interest rate changes on future income. These derivatives
would be used as hedges and would not be used for speculative or trading
purposes.
The major risks in using interest rate derivatives include changes in
interest rates affecting the value of such instruments, potential increases in
the interest expense of the Company due to market increases in floating interest
rates, in the case of derivatives that exchange fixed interest rates for
floating interest rates, and the creditworthiness of the counterparties in such
transactions.
At December 31, 2003 and 2002, the Company did not have any interest rate
swap agreements outstanding.
Credit Risk -- Financial instruments that potentially subject the Company
to concentrations of credit risk are primarily cash and cash equivalents and
trade receivables and, prior to December 31, 2003, notes receivable from Delta
Towing (see Note 18). It is the Company's practice to place its cash and cash
equivalents in time deposits at commercial banks with high credit ratings or
mutual funds that invest exclusively in high quality money market instruments.
In foreign locations, local financial institutions are generally utilized for
local currency needs. The Company limits the amount of exposure to any one
institution and does not believe it is exposed to any significant credit risk.
The Company derives the majority of its revenue from services to
international oil companies and government-owned and government-controlled oil
companies. Receivables are concentrated in various countries (see Note 19). The
Company maintains an allowance for doubtful accounts receivable based upon
expected collectibility. The Company is not aware of any significant credit
risks relating to its customer base and does not generally require collateral or
other security to support customer receivables.
66
NOTE 8 -- 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 -- The carrying amount of cash and cash
equivalents approximates fair value because of the short maturity of those
instruments.
Notes receivable from related parties -- The fair value of notes receivable
from related parties and advances to joint ventures with a carrying amount of
$78.7 million at December 31, 2002 could not be determined because there is no
available market price for such notes. Due to the adoption of FIN 46 (see Notes
2 and 18) the notes receivable have been eliminated in consolidation at December
31, 2003.
Debt -- The fair value of the Company's debt, including capital lease
obligations, is estimated based on the current rates offered to the Company for
debt of the same remaining maturities.
POST-TRANSOCEAN MERGER
----------------------------------------------
DECEMBER 31, 2003 DECEMBER 31, 2002
--------------------- ----------------------
CARRYING CARRYING
AMOUNT FAIR VALUE AMOUNT FAIR VALUE
-------- ---------- --------- ----------
(IN MILLIONS)
Cash and cash equivalents.................. $ 20.0 $ 20.0 $ -- $ --
Debt -- third party........................ (26.8) (28.9) (40.7) (43.3)
Debt -- related party...................... (525.0) (571.9) (1,080.1) (1,175.9)
NOTE 9 -- OTHER CURRENT LIABILITIES
Other current liabilities are comprised of the following (in millions):
POST-TRANSOCEAN
MERGER
----------------
DECEMBER 31,
----------------
2003 2002
------ ------
Accrued workers' insurance.................................. $28.0 $33.5
Accrued payroll and employee benefits....................... 5.7 14.2
Accrued interest............................................ 0.2 0.4
Accrued taxes, other than income............................ 1.6 1.1
Deferred income............................................. 7.3 --
Other....................................................... 0.6 0.6
----- -----
Total other current liabilities........................... $43.4 $49.8
===== =====
NOTE 10 -- IMPAIRMENT OF LONG-LIVED ASSETS
In the second quarter of 2003, the Company decided to remove five jackup
rigs from drilling service and market the rigs for alternative uses. The Company
does not anticipate returning the five rigs to drilling service as it would be
cost prohibitive. As a result of this decision and in accordance with SFAS 144,
the Company tested the carrying value of the rigs for impairment during the
second quarter of 2003 and recorded a pre-tax $10.6 million non-cash impairment
charge as a result of the impairment test.
As a result of the lack of success of the original business strategy of
Energy Virtual Partners, Inc. and Energy Virtual Partners, LP, the Company
determined that the assets of those entities did not support the Company's $1.0
million recorded investment and recorded a pre-tax $1.0 million non-cash
impairment charge in the second quarter of 2003. These entities are currently in
the process of being liquidated, and, in December 2003, the Company received
$0.3 million in proceeds from the sale of certain assets of the joint venture.
These proceeds were recorded as a reduction of the impairment charge previously
recorded.
67
In 2002, the Company recorded non-cash impairment charges of $16.4 million
relating to the reclassification of assets held for sale to assets held and
used. The impairment of these assets resulted from management's assessment that
they no longer met the held for sale criteria under SFAS 144. In accordance with
SFAS 144, the carrying values of these assets were adjusted to the lower of fair
market value or carrying value adjusted for depreciation from the date the
assets were classified as held for sale. The fair market value of these assets
was based on third party valuations.
In 2002, the Company recorded a non-cash impairment charge of $1.1 million
relating to an asset held for sale. The impairment resulted from deterioration
in market conditions. The impairment was determined and measured based on an
offer from a potential buyer.
The Company performed its annual test of goodwill as of October 1, 2002. As
a result of that test and a general decline in market conditions, the Company
recorded a non-cash impairment of $381.9 million in the fourth quarter of 2002.
See Note 2.
During the fourth quarter of 2001, the Company recorded a non-cash
impairment charge of $1.1 million. The impairment related to certain non-core
assets to be held and used as a result of deterioration in market conditions.
The impairment losses noted above have been included in the Company's
reportable segments results based on the segment of each of the assets impaired.
See Note 19.
NOTE 11 -- SUPPLEMENTARY CASH FLOW INFORMATION
Supplementary cash flow information relating to both continuing and
discontinued operations is as follows (in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
--------------------------------- ------------ ------------ ------------- --------------
Interest paid, net of capitalized
interest....................... $ 8.7 $ 55.3 $ 191.0 $ 1.5
Interest paid to related party... 50.7 73.6 23.6 --
Income taxes paid, net........... 11.1 23.2 15.3 1.1
Noncash investing activities
Sales of assets to related
party in exchange for
debt(a)(b).................. -- (87.6) (1,676.2) --
Net reclassification of
property and equipment from
(to) assets held for
sale(c)..................... -- 29.5 (171.9) --
Noncash financing activities
Fair value adjustments related
to the Transocean Merger.... -- -- -- 5,354.0
Net distribution of assets to
parent(d)(e)................ (224.7) (371.8) -- --
Debt exchanged in Exchange
Offer(f).................... -- (1,437.8) -- --
Equity contribution from
parent(g)................... (84.7) -- -- --
---------------
(a) In August 2001, the Company sold certain drilling units to a related party
(see Note 18). This was reflected in the consolidated balance sheet as a
decrease in non-current assets related to discontinued operations of
$1,676.2 million, a decrease in long-term advances from related party of
$1,190.0 million and an increase in note receivable from related party of
$425.0 million. The sale of these drilling units resulted in a net loss
from discontinued operations of $61.2 million.
68
(b) In April 2002, the Company sold two rigs to a related party (see Note 23).
The excess of the sales price over the net book value of the units was
treated as a capital contribution to the Company. This was reflected in the
consolidated balance sheet as a decrease to non-current assets related to
discontinued operations of $87.6 million, an increase in note receivable
from related party of $93.0 million and an increase in additional paid-in
capital of $5.4 million.
(c) Concurrent with and subsequent to the Transocean Merger (see Note 4), the
Company removed certain non-strategic assets from the active fleet and
categorized them as assets held for sale. This was reflected as a decrease
in property and equipment with a corresponding increase in other assets. In
the third quarter of 2002, the Company reclassified certain assets 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 (see Note 10). This was reflected as an increase in property and
equipment with a corresponding decrease in other assets.
(d) In the third and fourth quarters of 2002, nine rigs, 15 subsidiaries and
certain other assets were sold or distributed to affiliated companies (see
Note 23). The $10.4 million net reduction in cash held by subsidiaries at
the time of the sales or distributions was reflected in financing
activities in the consolidated statement of cash flows. The non-cash effect
on the consolidated balance sheet was reflected as a decrease in accounts
receivable-trade and other of $59.4 million, an increase in accounts
receivable-related party of $30.2 million, a decrease in materials and
supplies of $7.2 million, a decrease in non-current assets related to
discontinued operations of $383.4 million, a decrease in accounts
payable-trade of $5.6 million, a decrease in accounts payable-related party
of $56.6 million, a decrease in accrued income taxes of $2.4 million, a
decrease in other current liabilities of $5.6 million, an increase in
deferred income taxes of $45.2 million, a decrease in non-current
liabilities related to discontinued operations of $23.0 million and a
decrease in additional paid-in capital of $371.8 million.
(e) In the first half of 2003, four subsidiaries, ownership interests in two
majority-owned subsidiaries, a platform rig and certain other assets were
sold or distributed to affiliated companies (see Note 23). The $103.9
million in cash held by subsidiaries at the time of the sales or
distributions was reflected in financing activities in the consolidated
statement of cash flows. The non-cash effect on the consolidated balance
sheet was reflected as a decrease in accounts receivable-trade and other
receivables of $21.4 million, a decrease in accounts receivable-related
party of $298.8 million, an $8.3 million decrease in other current assets,
a $752.2 million decrease in non-current assets related to discontinued
operations, a $39.0 million decrease in other assets, a decrease in
accounts payable trade and other current liabilities of $31.9 million, a
decrease in accounts payable-related party of $108.4 million, a $15.5
million decrease in deferred taxes, a decrease in other long-term
liabilities of $28.3 million, a decrease in notes payable of $88.0 million,
a $524.7 million decrease in long-term debt-related party, a $98.2 million
decrease in minority interest and a decrease in additional paid-in capital
of $224.7 million.
(f) In March 2002 and in conjunction with the Exchange Offer, Transocean became
the holder of $1,437.8 aggregate principal amount senior notes (see Note
6). The effect on the consolidated balance sheet was a decrease in
long-term debt and an increase to long-term debt -- related party.
(g) In December 2003, Transocean contributed to the Company $84.7 million in
net accounts payable-related party owed to Transocean.
NOTE 12 -- INCOME TAXES
Income tax expense (benefit) from continuing operations before minority
interest and cumulative effect of a change in accounting principle consisted of
the following (in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
------------ ------------ ------------- --------------
Current:
Foreign........................ $ 0.9 $ 0.6 $ 3.7 $ --
State.......................... -- -- 0.8 --
------ ------ ------ ------
Total current.................. 0.9 0.6 4.5 --
------ ------ ------ ------
Deferred federal................. (51.0) (75.2) (26.1) (33.4)
------ ------ ------ ------
Income tax benefit before
minority interest and
cumulative effect of a
change in accounting
principle................... $(50.1) $(74.6) $(21.6) $(33.4)
====== ====== ====== ======
69
The domestic and foreign components of income (loss) from continuing
operations before income taxes, minority interest and cumulative effect of a
change in accounting principle were as follows (in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
------------ ------------ ------------- --------------
Domestic......................... $(264.3) $(580.4) $(118.6) $(124.3)
Foreign.......................... (7.2) (23.4) 0.3 0.8
------- ------- ------- -------
$(271.5) $(603.8) $(118.3) $(123.5)
======= ======= ======= =======
The effective tax rate, as computed on income (loss) from continuing
operations before income taxes, minority interest and cumulative effect of a
change in accounting principle differs from the statutory U.S. income tax rate
due to the following:
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
------------ ------------ ------------- --------------
Statutory tax rate............... 35.0% 35.0% 35.0% 35.0%
Use of previously reserved tax
benefits....................... -- -- -- --
Foreign tax expense (net of
federal benefit)............... (0.3) -- (1.9) --
State tax expense (net of federal
benefit)....................... -- -- (0.3) --
Non-deductible merger expenses... -- -- -- (7.4)
Non-deductible
expenses -- goodwill
amortization and other......... -- -- (12.8) (0.2)
Non-deductible
expenses -- goodwill impairment
losses......................... -- (22.1) -- --
Increase in valuation
allowance...................... (14.6) -- -- --
Expiration of net tax operating
loss carryforwards............. (2.1) (0.4) (1.5) (0.2)
Other............................ 0.5 (0.1) (0.2) (0.2)
----- ----- ----- ----
Effective tax rate............. 18.5% 12.4% 18.3% 27.0%
===== ===== ===== ====
70
Deferred income taxes result from those transactions that affect financial
and taxable income in different years. The nature of these transactions and the
income tax effect of each were as follows (in millions):
POST-TRANSOCEAN
MERGER
-----------------
DECEMBER 31,
-----------------
2003 2002
------- -------
DEFERRED TAX ASSETS
Net tax operating and other loss carryforwards(a)......... $ 310.1 $ 190.3
Foreign tax credit carryforwards.......................... 157.0 157.0
Accrued expenses.......................................... 16.7 15.8
Debt issue costs.......................................... 0.4 26.3
Other..................................................... 8.4 6.3
Valuation allowance....................................... (148.6) (109.0)
------- -------
Total deferred tax assets................................. 344.0 286.7
------- -------
DEFERRED TAX LIABILITIES
Depreciation.............................................. (190.7) (218.9)
Deferred gains............................................ (151.9) (117.7)
Other..................................................... (1.4) --
------- -------
Total deferred tax liabilities............................ (344.0) (336.6)
------- -------
Net deferred tax liabilities(a)........................... $ -- $ (49.9)
======= =======
---------------
(a) The December 31, 2002 net operating loss carryforwards balances have been
increased by $9.3 million, for the deferred tax benefits from stock option
exercises with corresponding increases in additional paid-in capital. Such
adjustments had no effect on the historical statements of operations or
cash flows for all periods presented.
At December 31, 2002, $17.2 million of current deferred tax assets were
included in other current assets in the accompanying consolidated balance sheet.
The valuation allowance reflects the possible expiration of tax benefits
(primarily foreign tax credit carryforwards) prior to their utilization because,
in the opinion of management, it is more likely than not that some or all of the
benefits will not be realized. The change in the valuation allowance was $39.6
million, $13.1 million, $15.2 million, and $0.5 million for the years ended
December 31, 2003 and 2002, the eleven months ended December 31, 2001, and the
one month ended January 31, 2001, respectively.
The Company is a member of an affiliated group that includes its parent
company, Transocean Holdings Inc. ("THI"), which files a consolidated United
States tax return. The Company's tax provision, including the deferred taxes
reflected above, is computed as if it were a stand alone entity.
Recapitalizations of Reading & Bates Corporation ("R&B") in 1989 and 1991,
the merger of R&B and Falcon Drilling Company, Inc. in 1997 and the Transocean
Merger in 2001 resulted in ownership changes for federal income tax purposes. As
a result of these ownership changes, the amount of tax benefit carryforwards
generated prior to the ownership changes, which may be utilized to offset
federal taxable income, is limited by the Internal Revenue Code. The amount of
consolidated United States net tax operating loss carryforwards ("NOLs")
allocated to the Company and available after consideration of the ownership
change limitation was approximately $1.2 billion as of December 31, 2003, before
adjustments to these NOLs for the impact of discontinued operations. These NOLs
expire in years 2004 through 2023.
There were no NOLs utilized for the years ended December 31, 2003 and 2002,
the eleven months ended December 31, 2001 and the one month ended January 31,
2001.
There was no income tax effect on the cumulative effect of a change in
accounting principle relating to the adoption of FIN 46 in 2003 or the adoption
of SFAS 142 in 2002. See Note 2.
71
In conjunction with the closing of the Company's initial public offering,
the Company entered into a tax sharing agreement with Transocean that has a
significant effect on the Company's ability to utilize the majority of its tax
benefits included in the Company's consolidated financial statements at December
31, 2003. See Note 24.
NOTE 13 -- COMMITMENTS AND CONTINGENCIES
Operating Leases -- The Company has operating leases covering premises and
equipment. Certain operating leases contain renewal options. Lease expense was
$13.8 million, $15.3 million, $17.1 million, and $1.7 million for the years
ended December 31, 2003 and 2002, the eleven months ended December 31, 2001 and
the one month ended January 31, 2001, respectively. As of December 31, 2003,
future minimum lease payments relating to operating leases were as follows (in
millions):
YEARS ENDED
DECEMBER 31,
------------
2004........................................................ $1.9
2005........................................................ 1.0
2006........................................................ 0.9
2007........................................................ 0.6
2008........................................................ 0.6
Thereafter.................................................. 0.6
----
Total..................................................... $5.6
====
Litigation -- In March 1997, an action was filed by Mobil Exploration and
Producing U.S. Inc. and affiliates, St. Mary Land & Exploration Company and
affiliates and Samuel Geary and Associates, Inc. against a subsidiary of the
Company, Cliffs Drilling, its underwriters at Lloyd's (the "Underwriters") and
an insurance broker in the 16th Judicial District Court of St. Mary Parish,
Louisiana. The plaintiffs alleged damages amounting to in excess of $50 million
in connection with the drilling of a turnkey well in 1995 and 1996. The case was
tried before a jury in January and February 2000, and the jury returned a
verdict of approximately $30 million in favor of the plaintiffs for excess
drilling costs, loss of insurance proceeds, loss of hydrocarbons, expenses and
interest. The Company and the Underwriters appealed such judgment, and the
Louisiana Court of Appeals has reduced the amount for which the Company may be
responsible to less than $10 million. The plaintiffs requested that the Supreme
Court of Louisiana consider the matter and reinstate the original verdict. The
Company and the Underwriters also appealed to the Supreme Court of Louisiana
requesting that the Court reduce the verdict or, in the case of the
Underwriters, eliminate any liability for the verdict. Prior to the Supreme
Court of Louisiana ruling on these petitions, the Company settled with the St.
Mary group of plaintiffs and the State of Louisiana. Subsequently, the Supreme
Court of Louisiana denied the applications of all remaining parties. The Company
has settled with all remaining plaintiffs. The Company believes that any
amounts, apart from a small deductible, paid in settlement are covered by
relevant primary and excess liability insurance policies. However, the insurers
and Underwriters have denied all coverage. The Company has instituted litigation
against those insurers and Underwriters to enforce its rights under the relevant
policies. One group of insurers has asserted a counterclaim against the Company
claiming that they issued the policy as a result of a misrepresentation. The
settlements did not have a material adverse effect on the Company's business or
consolidated financial position, and the Company does not expect the ultimate
outcome of the case involving the insurers and Underwriters will have a material
adverse effect on its business or consolidated financial position. In connection
with the Company's separation from Transocean, Transocean has agreed to
indemnify the Company of any losses it incurs as a result of this legal
proceeding. See Note 24.
In October 2001, the Company was notified by the U.S. Environmental
Protection Agency ("EPA") that the EPA had identified a subsidiary of the
Company as a potentially responsible party in connection with the Palmer Barge
Line superfund site located in Port Arthur, Jefferson County, Texas. Based upon
the information provided by the EPA and the Company's review of its internal
records to date, the Company disputes its designation as a potentially
responsible party and does not expect that the ultimate outcome of this
72
case will have a material adverse effect on its business or consolidated
financial position. The Company continues to investigate the matter.
In December 2002, the Company received an assessment for corporate income
taxes in Venezuela of approximately $16.0 million (based on current exchange
rates) relating to calendar years 1998 through 2000. In March 2003 the Company
paid approximately $2.6 million of the assessment, and the Company is contesting
the remainder of the assessment. The resolution of this assessment is not
expected to impact the Company as Transocean has agreed to indemnify the Company
against any payments as long as it cooperates and provides assistance to
Transocean in resolution of the assessment.
In 1984, in connection with the financing of the corporate headquarters, at
that time, for R&B, a predecessor to one of our subsidiaries, in Tulsa,
Oklahoma, the Greater Southwestern Funding Corporation ("Southwestern") issued
and sold, among other instruments, Zero Coupon Series B Bonds due 1999 through
2009 with an aggregate $189 million value at maturity. Paine Webber Incorporated
purchased all of the Series B Bonds for resale and in 1985 acted as underwriter
in the public offering of most of these bonds. The proceeds from the sale of the
bonds were used to finance the acquisition and construction of the headquarters.
R&B's rental obligation was the primary source for repayment of the bonds. In
connection with the offering, R&B entered into an indemnification agreement to
indemnify Southwestern and Paine Webber from loss caused by any untrue statement
or alleged untrue statement of a material fact or the omission or alleged
omission of a material fact contained or required to be contained in the
prospectus or registration statement relating to that offering. Several years
after the offering, R&B defaulted on its lease obligations, which led to a
default by Southwestern. Several holders of Series B bonds filed an action in
Tulsa, Oklahoma in 1997 against several parties, including Paine Webber,
alleging fraud and misrepresentation in connection with the sale of the bonds.
In response to a demand from Paine Webber in connection with that lawsuit and a
related lawsuit, R&B agreed in 1997 to retain counsel for Paine Webber with
respect to only that part of the referenced cases relating to any alleged
material misstatement or omission relating to R&B made in certain sections of
the prospectus or registration Statement. The agreement to retain counsel did
not amend any rights and obligations under the indemnification agreement. There
has been only limited progress on the substantive allegations in the case. The
trial court has denied class certification, and the plaintiffs have appealed
this denial to a higher court. The Company disputes that there are any matters
requiring the Company to indemnify Paine Webber. In any event, the Company does
not expect that the ultimate outcome of this matter will have a material adverse
effect on its business or consolidated financial position. In addition,
Transocean has agreed to indemnify the Company for any losses that may be
incurred as a result of this litigation. See Note 24.
In April 2003, Gryphon Exploration Company ("Gryphon") filed suit against
some of our subsidiaries, Transocean and other third parties in the United
States District Court in Galveston, Texas claiming damages in excess of $6
million. In its complaint, Gryphon alleges the defendants were responsible for
well problems experienced by Gryphon with respect to a well in the Gulf of
Mexico drilled by our subsidiaries in 2001. We dispute the allegations of
Gryphon and intend to vigorously defend this claim. While we continue to
investigate this matter, we do not currently expect the ultimate outcome of this
matter to have a material adverse effect on our business or consolidated
financial position. In addition, Transocean has agreed to indemnify the Company
for any losses that may be incurred as a result of this litigation. See Note 24.
The Company and its subsidiaries are involved in a number of other
lawsuits, all of which have arisen in the ordinary course of the Company's
business. The Company does not believe that ultimate liability, if any,
resulting from any such other pending litigation will have a material adverse
effect on its business or consolidated financial position.
The Company cannot predict with certainty the outcome or effect of any of
the litigation matters specifically described above or of any such other pending
litigation. There can be no assurance that the Company's belief 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.
73
Letters of Credit and Surety Bonds -- The Company had letters of credit
outstanding at December 31, 2003 totaling $0.7 million. These outstanding
letters of credit guarantee performance against certain claims not related to
the Company's Shallow Water business. Transocean has agreed to indemnify us
against any liabilities unrelated to the Shallow Water business. See Note 24.
As is customary in the contract drilling business, the Company also has
various surety bonds totaling $13.4 million in place as of December 31, 2003
that secure customs obligations and certain performance and other obligations.
Self-Insurance -- The Company is self-insured for the deductible portion of
its insurance coverage. In the opinion of management, adequate accruals have
been made based on known and estimated exposures up to the deductible portion of
the Company's insurance coverages.
Employment Agreements -- In July 2002, the Company entered into employment
agreements with two employees to serve as the Company's President and Chief
Executive Officer ("CEO") and Senior Vice President and Chief Financial Officer
at the closing of the initial public offering. The agreements, which were
amended in December 2003, provide for specified compensation and benefits
including stock option awards, and in the case of the CEO, a restricted stock
award upon closing of the initial public offering and other incentives that may
be included in the Company's incentive plans to be adopted by the Company's
board of directors prior to the closing of the initial public offering.
NOTE 14 -- CAPITAL STOCK
During the one month ended January 31, 2001 the Company issued 28,126
shares of common stock for its matching contribution to the employee savings
plans.
In February 2004, the Company amended its articles of incorporation to,
among other things, create two classes of common stock, Class A and Class B,
increase its authorized capital stock and to convert any issued and outstanding
shares of the Company's common stock into Class B common stock. As amended, the
Company's authorized capital stock consists of (i) 500,000,000 shares of Class A
common stock, par value $.01 per share, and 260,000,000 shares of Class B common
stock, par value $.01 per share, and (ii) 50,000,000 shares of preferred stock,
par value $.01 per share. The Class B common stock is convertible at any time
into shares of Class A common stock on a share per share basis at the sole
option of Transocean.
In February 2004, prior to the Company's IPO, the Company completed
debt-for-equity exchanges for approximately $488.1 million principal amount of
its senior notes payable to Transocean (see Note 24).
Immediately following the debt-for-equity exchanges, the Company declared a
dividend of 11.145 shares of its Class B common stock with respect to each share
of its Class B common stock outstanding immediately following the
debt-for-equity exchanges. The stock dividend of 11.145 shares of Class B common
stock for each outstanding share of Class B common stock has been retroactively
applied to the 1,000,000 shares of common stock held by Transocean prior to the
debt-for-equity exchanges and has been reflected in the Company's historical
consolidated financial statements since January 31, 2001, the date of the
Transocean Merger. The effect of this retroactive application was to increase
the authorized common shares of the Company's Class B common stock to
260,000,000 shares and issued and outstanding to 12,144,751 shares for all
periods presented with a corresponding decrease to additional paid-in capital.
The effect of the debt-for-equity exchanges and the stock dividend on such newly
issued shares of common stock will be reflected in the first quarter of 2004.
In February 2004, the Company completed the IPO of its Class A common
shares at $12.00 per share. See Note 24.
NOTE 15 -- STOCK-BASED COMPENSATION PLANS
Stock Plans -- Prior to the Transocean Merger, the Company had 17 stock
plans (the "Incentive Plans") intended to provide an incentive that would allow
the Company to retain persons of the training, experience and ability necessary
for the development and financial success of the Company. Such plans provided
for
74
grants of stock options, stock appreciation rights, stock awards and cash
awards, which could be granted singly, in combination or in tandem. All stock
options awarded under these plans expire 10 years from the date of their grant
and were granted at the market price on the date of grant unless otherwise
noted. As a result of the Transocean Merger, Transocean assumed all outstanding
R&B Falcon stock options, which were converted into options to purchase
Transocean ordinary shares. All options and restricted stock granted prior to
announcement of the Transocean Merger were early vested in January 2001. See
Note 4.
The Company's 1998 Employee Long-Term Incentive Plan authorized 3.2 million
shares of common stock to be available for awards. In 1998, restricted stock
awards with respect to 941,500 shares were granted to certain employees of the
Company. The transfer of these awarded shares was restricted until fully vested
three years from the date of grant. The market value at the date of grant of the
restricted common stock was recorded as unearned compensation and was amortized
to expense based on a three-year vesting period.
The Company's 1999 Employee Long-Term Incentive Plan authorized 6.5 million
shares of common stock to be available for awards. In 2000, restricted stock
awards with respect to 137,350 shares were granted to certain employees of the
Company. The transfer of these awarded shares was restricted until fully vested
four years from the date of grant. The market value at the date of grant of the
restricted common stock was recorded as unearned compensation and was amortized
to expense based on a four-year vesting period.
Unearned compensation relating to the Company's restricted stock awards was
shown as a reduction of stockholders' equity. All unvested restricted stock was
vested in January 2001 as a result of the Transocean Merger. Compensation
expense recognized for the one month ended January 31, 2001 related to stock
awards totaled approximately $4.1 million.
75
Stock option transactions under the plans were as follows:
NUMBER OF WEIGHTED-
SHARES AVERAGE
UNDER EXERCISE
OPTION PRICE
---------- ---------
PRE-TRANSOCEAN MERGER -- R&B FALCON CORPORATION OPTIONS
Options outstanding at December 31, 2000.................... 16,154,272 $11.15
Granted................................................... 88,440 23.44
Exercised................................................. (48,612) 21.92
Forfeited................................................. (6,080) 15.27
----------
Options outstanding at January 31, 2001..................... 16,188,020 11.13
---------- ------
------------------------------------------------------------------------------------
POST-TRANSOCEAN MERGER -- TRANSOCEAN OPTIONS
Conversion to Transocean options............................ (8,094,010) 11.13
Granted................................................... 392,800 38.07
Exercised................................................. (1,005,035) 20.07
Forfeited................................................. (30,289) 51.92
----------
Transocean options outstanding at December 31, 2001......... 7,451,486 23.46
Granted................................................... 354,050 28.80
Exercised................................................. (92,450) 34.26
Forfeited................................................. (49,900) 46.30
----------
Transocean options outstanding at December 31, 2002......... 7,663,186 $23.62
Assumed by Transocean..................................... (6,781,561) 22.69
Transferred to TODCO...................................... 55,987 32.39
Forfeited................................................. (60,914) 37.33
---------- ------
Transocean options outstanding at December 31, 2003......... 876,698 $30.40
========== ======
POST-TRANSOCEAN MERGER -- TRANSOCEAN OPTIONS
Exercisable at December 31, 2001............................ 6,955,284 $22.19
Exercisable at December 31, 2002............................ 7,027,665 $22.68
Exercisable at December 31, 2003............................ 761,299 $30.11
During 2003, in connection with the transfer of the Transocean Assets to
Transocean, certain of the Company's employees not associated with the Company's
Shallow Water business became employees of Transocean, and Transocean assumed
any future expense relating to the vesting of the options held by these
employees. Additionally, certain former Transocean employees became employees of
the Company. The Company assumed any future expense relating to the vesting of
options held by these former Transocean employees.
The following table summarizes information about Transocean stock options
held by employees of the Company at December 31, 2003:
WEIGHTED- OPTIONS OUTSTANDING OPTIONS EXERCISABLE
AVERAGE ------------------------------ ------------------------------
RANGE OF REMAINING NUMBER WEIGHTED-AVERAGE NUMBER WEIGHTED-AVERAGE
EXERCISE PRICES CONTRACTUAL LIFE OUTSTANDING EXERCISE PRICE OUTSTANDING EXERCISE PRICE
--------------- ---------------- ----------- ---------------- ----------- ----------------
$10.00-$19.50 5.97 years... 278,051 $18.46 278,051 $18.46
$21.06-$28.80 7.91 years... 265,364 $27.19 192,864 $26.59
$37.00-$81.78 7.79 years... 333,283 $42.91 290,384 $43.59
76
The Company accounted for these plans under APB 25 under which no
compensation expense was recognized for options granted with an exercise price
at or above the market price of the Company's common stock. See Note 2.
In connection with the Company's initial public offering in February 2004
all outstanding Transocean options became fully-vested. See Note 24.
NOTE 16 -- RETIREMENT PLANS AND OTHER POST EMPLOYMENT BENEFITS
Pension and Postretirement Benefits -- The Company had three
noncontributory pension plans prior to the Transocean Merger. One or more of
these plans covered substantially all of the R&B Falcon employees paid from a
U.S. payroll. Plan benefits were primarily based on years of service and average
high 60-month compensation.
The R&B Falcon U.S. Pension Plan (the "U.S. Pension Plan") is qualified
under the Employee Retirement Income Security Act (ERISA). The R&B Falcon
Non-U.S. Pension Plan (the "Non-U.S. Pension Plan") is a nonqualified plan and
is not subject to ERISA funding requirements. The R&B Falcon Retirement Benefit
Replacement Plan (the "Replacement Plan") is a self-administered unfunded excess
benefit plan. All members of the U.S. Pension Plan are potential participants in
the Replacement Plan.
In addition to providing pension benefits, the Company provided certain
life and health care insurance benefits for its retired employees. Effective
January 1, 1999, the Company no longer provides a retiree life insurance plan to
its current employees. Only those former employees who retired prior to May 1,
1986 were eligible to retain their retiree life insurance. Retiree life
insurance benefits are provided through an insurance company whose premiums are
based on benefits paid during the year. Retiree health coverage was also
significantly restricted effective January 1, 1999. Effective August 1, 2002,
all retiree medical coverage and retiree life insurance for former R&B Falcon
employees were transferred to plans maintained by THI, the Company's parent.
Effective August 1, 2002, THI became the plan sponsor for the U.S. Pension
Plan, the Non-U.S. Pension Plan and the Replacement Plan and assumed all
liabilities related to these plans. The Company recorded a net distribution to
THI of the prepaid (accrued) cost relating to these plans and the postretirement
benefit plans. In conjunction with the change in the plan sponsor, the plans
were renamed the Transocean Holdings U.S. Pension Plan (formerly R&B Falcon U.S.
Pension Plan), the Transocean Holdings Non-U.S. Pension Plan (formerly R&B
Falcon Non-U.S. Pension) and the Transocean Holdings Replacement Plan (formerly
R&B Falcon Replacement Plan).
Savings Plans -- The Company had two savings plans that allowed employees
to contribute up to 15 percent of their base salary (subject to certain
limitations). Under these plans, the Company made matching contributions to
equal 100 percent of employee contributions on the first 6 percent of their base
salary. From July 1, 1999 through the date of the Transocean Merger, the Company
made its matching contributions in the form of issuing shares of R&B Falcon
common stock. Certain of the Company's employees were allowed to begin
participation in the Transocean U.S. Savings Plan (formerly, Transocean Sedco
Forex Savings Plan) on June 1, 2001, July 1, 2001 or August 1, 2001 based on
their assignment and geographic location. Effective August 1, 2001 and in
conjunction with eligible employee participation in the Transocean U.S. Savings
Plan, the R&B Falcon U.S. Savings Plan and the R&B Falcon Non-U.S. Savings Plan
were closed to all new participants and contributions into the plans ceased.
Participants continued to direct the investment of their accumulated
contributions into various plan investment options. Effective August 1, 2002,
THI became the plan sponsor for the R&B Falcon Non-U.S. Savings Plan, which was
renamed the Transocean Holdings Non-U.S. Savings Plan.
Effective November 1, 2002, the Transocean U.S. Savings Plan was amended
and the Company's Shallow Water employees were restricted from participation in
this Plan. Effective December 1, 2002, all savings plan assets of the employees
were liquidated and transferred from the Transocean U.S. Savings Plan into the
R&B Falcon U.S. Savings Plan. Additionally, all savings plan assets in the R&B
Falcon U.S. Savings
77
Plan of active former R&B Falcon employees who were not assigned to the Shallow
Water operations were liquidated and transferred into the Transocean U.S.
Savings Plan. The R&B Falcon U.S. Savings Plan has also been amended and
restated effective January 1, 2003.
Compensation costs under the plans amounted to $2.6 million, $1.6 million,
$0.1 million and $0.1 million for the years ended December 31, 2003 and 2002,
the eleven months ended December 31, 2001, and the one month ended January 31,
2001, respectively.
NOTE 17 -- INVESTMENTS IN AND ADVANCES TO JOINT VENTURES
Investments in and advances to unconsolidated joint ventures were as
follows (in millions):
POST-TRANSOCEAN
MERGER
---------------
DECEMBER 31
---------------
2003 2002
---- ----
Delta Towing................................................ $ -- $78.7
Other....................................................... 0.1 1.0
---- -----
$0.1 $79.7
==== =====
Equity in earnings (losses) of joint ventures consisted of the following
(in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
-------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
2003 2002 2001 2001
------------ ------------ -------------- --------------
Delta Towing................. $(6.6) $(3.2) $(0.9) $ --
Other........................ -- 0.5 -- --
----- ----- ----- ----
$(6.6) $(2.7) $(0.9) $ --
===== ===== ===== ====
Delta Towing -- The Company owns a 25 percent equity interest in Delta
Towing, a joint venture formed to own and operate the Company's U.S. marine
support vessel business, consisting primarily of shallow water tugs, crewboats
and utility barges. The Company previously contributed its support vessel
business to the joint venture in return for a 25 percent ownership interest and
certain secured notes receivable from Delta Towing with a face value of $144.0
million. The Company valued these notes at $80.0 million immediately prior to
the closing of the merger transaction with Transocean. No value was assigned to
the ownership interest in Delta Towing. The note agreement was subsequently
amended to provide for a $4.0 million, three-year revolving credit facility.
Delta Towing's property and equipment, with a net book value of $50.6 million at
December 31, 2003, are collateral for the Company's notes receivable. The
carrying value of the notes receivable, net of allowance for credit losses and
equity losses in Delta Towing was $49.0 million at December 31, 2003 and has
been eliminated in consolidation. The remaining 75 percent ownership interest is
held by Beta Marine, which also loaned Delta Towing $3.0 million.
In the first quarter of 2003, the Company recorded its share of a $2.5
million non-cash impairment charge on the carrying value of idle equipment
recorded by Delta Towing. In December 2003, the Company recorded a non-cash
impairment charge of $1.9 million as a result of Delta Towing's annual test of
impairment of long-lived assets, which is included in equity in loss of joint
ventures in our consolidated statement of operations.
Under FIN 46, Delta Towing is considered a VIE because its equity is not
sufficient to absorb the joint venture's expected future losses. The Company is
the primary beneficiary of Delta Towing for accounting purposes because it has
the largest percentage of investment at risk through the secured notes held by
the Company and would thereby absorb the majority of the expected losses of
Delta Towing. The Company consolidated Delta Towing in its December 31, 2003
consolidated financial statements. The consolidation of Delta Towing resulted in
an increase in net assets and a corresponding gain of $0.8 million which has
been
78
presented as a cumulative effect of a change in accounting principle in the
consolidated statement of operations. Prior to December 31, 2003, the Company
accounted for its investment in Delta Towing under the equity method.
The creditors of Delta Towing have no recourse to the general credit of the
Company.
NOTE 18 -- RELATED PARTY TRANSACTIONS
Delta Towing -- The secured notes issued in connection with the formation
of the joint venture consisted of (i) an $80 million principal amount note
bearing interest at eight percent per annum due January 30, 2024 (the "Tier 1
Note"), (ii) a contingent $20 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 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 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 must 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. See Note 24.
The Company valued its Tier 1, 2 and 3 Notes at $80 million immediately
prior to the closing of the Transocean Merger, the effect of which was to fully
reserve the Tier 2 and 3 Notes. At December 31, 2002, $78.7 million principal
amount was outstanding under the Company's Tier 1 Note. In December 2001, the
note agreement was amended to provide for a $4 million, three-year revolving
credit facility (the "Delta Towing Revolver") from the Company. Amounts drawn
under the Delta Towing Revolver accrue interest at eight percent per annum, with
interest payable quarterly. At December 31, 2002, $3.9 million was outstanding
under the Delta Towing Revolver. During the years ended December 31, 2003 and
2002 and the eleven months ended December 31, 2001, the Company earned $3.3
million, $6.6 million and $5.8 million of interest income on the Delta Towing
Tier 1 Note and Revolver, respectively. At December 31, 2002, the Company had
interest receivable from Delta Towing of $1.7 million.
As a result of its issuance of notes to the Company, Delta Towing is highly
leveraged. In January 2003, Delta Towing defaulted on the notes by failing to
make its scheduled quarterly interest payments and remains in default as a
result of its continued failure to make its quarterly interest payments. As a
result of the Company's continued evaluation of the collectibility of the notes,
the Company recorded a $21.3 million impairment of the notes 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 notes in the event of
default, the Company began offsetting a portion of the amount owed by the
Company to Delta Towing against the interest due under the notes. Additionally,
in 2003, the Company established a $1.6 million reserve for interest income
earned during the year on the notes receivable.
As a result of the Company's adoption of FIN 46, the Company consolidated
Delta Towing effective December 31, 2003 and intercompany accounts have been
eliminated. See Note 17.
As part of the formation of the joint venture on January 31, 2001, the
Company entered into an agreement with Delta Towing under which the Company
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
79
10 crewboats then under construction, all of which had been placed into service
as of December 31, 2002. During the years ended December 31, 2003 and 2002, the
Company incurred charges totaling $11.7 million, $10.7 million from Delta Towing
for services rendered, of which $1.6 million was rebilled to the Company's
customers and $9.1 million was reflected in operating and maintenance -- related
party expense in 2002. During the eleven months ended December 31, 2001, the
Company incurred charges totaling $15.6 million from Delta Towing for services
rendered, of which $6.5 million was rebilled to the Company's customers and $9.1
million was reflected in operating and maintenance -- related party expense.
Allocation of Administrative Costs -- Subsidiaries of Transocean provide
certain administrative support to the Company. Transocean charges the Company a
proportional share of its administrative costs based on estimates of the
percentage of work the individual Transocean departments perform for the
Company. In the opinion of management, Transocean is charging the Company for
all costs incurred on its behalf under a comprehensive and reasonable cost
allocation method. The amount of expense allocated to the Company for the years
ended December 31, 2003 and 2002 and the eleven months ended December 31, 2001
was $1.4 million, $9.7 million and $2.0 million, respectively. These allocated
expenses were classified as general and administrative -- related party expense.
Note Receivable -- Related Party -- As consideration for the sale of the
Harvey H. Ward and the Roger W. Mowell to Transocean in April 2002 (Note 23),
the Company received promissory notes due April 3, 2012 bearing interest at 5.5
percent per annum payable annually in the aggregate principal amount of $93.0
million. The notes may be repaid at any time at Transocean's option, without
penalty. For the year ended December 31, 2002, the Company accrued $3.6 million
in interest income relating to the notes. In December 2002, Transocean repaid to
the Company the $93.0 million aggregate principal amount of promissory notes
plus accrued and unpaid interest.
In August 2001, as consideration for the sale of certain drilling rigs to
Transocean, $1,190.0 million of debt owed by the Company to Transocean was
canceled. In addition, the Company received promissory notes due August 17, 2011
bearing interest at 5.72 percent per annum payable annually in the aggregate
principal amount of $425.0 million. The notes may be repaid at any time at
Transocean's option, without penalty. For the year ended December 31, 2002 and
for the eleven months ended December 31, 2001, the Company had accrued $23.4
million and $9.1 million, respectively, in interest income relating to these
promissory notes. In December 2002, Transocean repaid the $425.0 million
aggregate principal amount of promissory notes plus accrued and unpaid interest.
Transfer of Transocean Assets -- The Company sold and/or distributed the
Transocean Assets to Transocean primarily as in-kind dividends and transfers in
exchange for the cancellation of debt to Transocean, and in some instances, for
cash. See Note 23.
NOTE 19 -- SEGMENTS, GEOGRAPHICAL ANALYSIS AND MAJOR CUSTOMERS
The Company's operating assets consist of jackup and submersible drilling
rigs and inland drilling barges and a platform rig located in the U.S. Gulf of
Mexico and Trinidad, two jackup drilling rigs in Mexico, as well as land and
lake barge drilling units located in Venezuela. We provide contract oil and gas
drilling services and report the results of those operations in three business
segments which correspond to our principal geographic regions in which we
operate: U.S. Inland Barge Segment, U.S. Gulf of Mexico Segment and Other
International Segment. The accounting policies of the reportable segments are
the same as those described in Note 1.
80
Revenue, depreciation and amortization, impairment loss, operating income
(loss) and identifiable assets by reportable business segment was as follows (in
millions):
U.S. GULF OF U.S. INLAND OTHER
MEXICO BARGE INTERNATIONAL CORPORATE
SEGMENT SEGMENT SEGMENT & OTHER(A) TOTAL
------------ ----------- ------------- ---------- --------
POST-TRANSOCEAN MERGER
2003
Revenues....................... $101.2 $ 84.2 $ 42.3 $ -- $ 227.7
Depreciation and
amortization................ 55.3 23.3 13.6 -- 92.2
Impairment loss on long-lived
assets...................... 10.6 -- 0.7 -- 11.3
Operating loss................. (63.2) (34.5) (4.7) (16.3) (118.7)
Identifiable assets............ 334.6 170.4 171.3 101.9 778.2
2002
Revenues....................... $ 65.7 $ 87.5 $ 34.6 $ -- $ 187.8
Depreciation and
amortization................ 58.1 23.3 10.5 -- 91.9
Impairment loss on long-lived
assets...................... 1.1 -- 16.4 -- 17.5
Impairment loss on goodwill.... -- -- -- 381.9 381.9
Operating loss................. (80.7) (2.3) (23.3) (410.8) (517.1)
Identifiable assets............ 447.8 210.6 103.3 1,465.5 2,227.2
ELEVEN-MONTHS ENDED DECEMBER 31,
2001
Revenues....................... $218.6 $159.1 $ 63.3 $ -- $ 441.0
Depreciation and
amortization................ 63.3 220 11.2 42.9 139.4
Impairment loss on long-lived
assets...................... -- -- 1.1 -- 1.1
Operating loss................. 26.9 52.2 (2.4) (62.3) 14.4
Identifiable assets............ 508.1 240.4 155.1 7,935.2 8,838.8
-----------------------------------------------------------------------------------------------------
PRE-TRANSOCEAN MERGER
ONE-MONTH ENDED JANUARY 31, 2001
Revenues....................... $ 26.0 $ 13.8 $ 8.7 $ -- $ 48.5
Depreciation and
amortization................ 2.9 1.1 2.3 0.2 6.5
Impairment loss on long-lived
assets...................... -- -- -- 64.0 64.0
Operating income (loss)........ 15.4 4.5 (0.5) (125.0) (105.6)
---------------
(a) Includes general and administrative expenses and impairment charges which
were not allocated to a reportable segment. Identifiable assets include
assets related to discontinued operations of $0.1 million, $995.5 million
and $5,446.9 million at December 31, 2003, 2002 and 2001, respectively, as
well as assets related to the Delta Towing business of $63.5 million at
December 31, 2003. Goodwill in the amount of $425.0 million at December 31,
2001 has not been allocated to the reportable segments. Such goodwill was
fully impaired in 2002 (see Note 2).
81
The Company provides contract oil and gas drilling services with different
types of drilling equipment in several countries. Geographic information about
the Company's operations was as follows (in millions):
PRE-TRANSOCEAN
POST-TRANSOCEAN MERGER MERGER
------------------------------------------- --------------
ELEVEN MONTHS ONE MONTH
YEAR ENDED YEAR ENDED ENDED ENDED
DECEMBER 31, DECEMBER 31, DECEMBER 31, JANUARY 31,
------------ ------------ ------------- --------------
2003 2002 2001 2001
------------ ------------ ------------- --------------
OPERATING REVENUES
United States.................... $185.4 $153.9 $383.2 $42.9
Other countries.................. 42.3 33.9 57.8 5.6
------ ------ ------ -----
Total operating revenues....... $227.7 $187.8 $441.0 $48.5
====== ====== ====== =====
POST-TRANSOCEAN
MERGER
---------------
DECEMBER 31,
---------------
2003 2002
------ ------
LONG-LIVED ASSETS
United States............................................... $542.5 $727.5
Other countries............................................. 150.1 80.2
A substantial portion of the Company's assets are mobile. Asset locations
at the end of the period are not necessarily indicative of the geographic
distribution of the earnings generated by such assets during the periods.
The Company's 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.
The Company provides drilling rigs, related equipment and work crews
primarily on a dayrate basis to customers who are drilling oil and gas wells.
The Company provides these services mostly to independent oil and gas companies,
but it also services major international and government-controlled oil and gas
companies. In 2003, one customer, Applied Drilling Technologies, Inc., accounted
for 11 percent of the Company's total operating revenue for the year. No other
customer accounted for 10 percent or more of the Company's total operating
revenues in 2003. For the years ended 2002 and 2001, no single customer
accounted for 10 percent or more of the Company's total operating revenues in
the respective periods. The loss of any significant customer could have a
material adverse effect on the Company's results of operations.
NOTE 20 -- RESTRUCTURING EXPENSE
In September 2002, the Company committed to a restructuring plan to
consolidate certain functions and offices. The plan resulted in the closure of
an office and warehouse in Louisiana and relocation of most of the operations
and administrative functions previously conducted at that location. The Company
established a liability of $1.2 million for the estimated severance-related
costs associated with the involuntary termination of 57 employees pursuant to
this plan. The charge was reported as operating and maintenance expense in the
Company's consolidated statements of operations. As of December 31, 2003
substantially all of the previously established liability was paid to the 50
employees whose employment was terminated as a result of this plan.
NOTE 21 -- EARNINGS PER SHARE
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 because the effect of
including those shares is anti-dilutive for the one month ended January 31,
2001.
82
NOTE 22 -- QUARTERLY RESULTS (UNAUDITED)
Summarized quarterly financial data for the years ended December 31, 2003
and 2002 are as follows (in millions, except per share amounts):
POST-TRANSOCEAN MERGER
---------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------- ------- ------- -------
2003
Operating revenues........................... $ 53.3 $ 55.5 $ 58.5 $ 60.4
Operating loss(a)............................ (29.4) (50.0) (24.8) (14.5)
Loss from continuing operations.............. (57.0) (101.7) (35.0) (28.3)
Loss from discontinued operations............ (30.9) (34.1) -- --
Cumulative effect of a change in accounting
principle.................................. -- -- -- 0.8
Net loss(b).................................. (87.9) (135.8) (35.0) (27.5)
Net loss per common share
Basic and diluted
Net loss from continuing operations........ (4.70) (8.37) (2.88) (2.33)
Net loss from discontinued operations...... (2.54) (2.81) -- --
Cumulative effect of a change in accounting
principle............................... -- -- -- 0.07
Net loss................................... $ (7.24) $(11.18) $ (2.88) $ (2.26)
POST-TRANSOCEAN MERGER
---------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
--------- ------- ------- -------
2002
Operating revenues........................... $ 44.7 $ 37.1 $ 54.0 $ 52.0
Operating loss(c)............................ (37.6) (33.9) (39.0) (406.6)
Loss from continuing operations.............. (37.1) (32.2) (36.5) (423.3)
Income (loss) from discontinued operations... 27.3 (0.5) (570.1) 31.2
Cumulative effect of a change in accounting
principle.................................. (4,517.0) -- -- --
Net loss(d).................................. (4,526.8) (32.7) (606.6) (392.1)
Net loss per common share
Basic and diluted
Net loss from continuing operations........ (3.06) (2.65) (3.00) (34.86)
Net income (loss) from discontinued
operations.............................. 2.25 (0.04) (46.94) 2.57
Cumulative effect of a change in accounting
principle............................... (371.92) -- -- --
Net loss................................... $ (372.73) $ (2.69) $(49.94) $(32.29)
---------------
(a) First quarter of 2003 included a $30.0 million loss on retirement of debt.
Second quarter 2003 included an $11.6 million impairment loss on long-lived
assets, a $21.3 million impairment loss on a note receivable from a
then-unconsolidated joint venture and a $49.5 (a) million loss on
retirement of debt (see Notes 6 and 23).
(b) Fourth quarter 2003 included a gain of $0.8 million presented as a
cumulative effect of a change in accounting principle as a result of the
consolidation of Delta Towing (see Note 17).
(c) First quarter 2002 included loss on impairments of $1.1 million. Third
quarter 2002 included loss on impairments of $15.2 million. Fourth quarter
2002 included loss on impairments of (c) $383.1 million. (See Note 10).
83
(d) First quarter 2002 included a cumulative effect of a change in accounting
principle of $4,517.0 million (see Note 2) relating to the impairment of
goodwill. Fourth quarter 2002 included loss on impairments of $12.2 million
relating to the early retirement of debt (see Note 6).
NOTE 23 -- DISCONTINUED OPERATIONS
Operating revenues related to discontinued operations for the years ended
December 31, 2003 and 2002, eleven months ended December 31, 2001, one month
ended January 31, 2001 were $53.4 million, $658.3 million, $758.8 million, and
$80.1 million, respectively.
A summary of assets and liabilities related to the discontinued operations
as of December 31, 2003 and 2002 is as follows (in millions):
DECEMBER 31,
--------------
2003 2002
----- ------
ASSETS
Cash and cash equivalents................................... $ -- $103.6
Accounts receivable and other current assets................ 0.1 49.3
----- ------
Total current assets...................................... 0.1 152.9
----- ------
Property and equipment, net................................. -- 775.5
Notes receivable............................................ -- 2.5
Investments in and advances to joint ventures............... -- 24.4
Other assets................................................ -- 40.2
----- ------
Total non-current assets.................................. -- 842.6
----- ------
Total assets.............................................. $ 0.1 $995.5
===== ======
LIABILITIES
Accounts payable trade...................................... $ 0.2 $ 18.2
Debt due within one year.................................... -- 41.5
Interest payable -- related party........................... -- 5.7
Other current liabilities................................... 0.3 37.2
----- ------
Total current liabilities................................. 0.5 102.6
----- ------
Long-term liabilities....................................... -- 113.1
Minority interest........................................... -- 97.0
----- ------
Total non-current liabilities and other................... -- 210.1
----- ------
Total liabilities......................................... $ 0.5 $312.7
===== ======
Net (liabilities) assets related to discontinued
operations................................................ $(0.4) $682.8
===== ======
Transfer of Transocean Assets -- The Company transferred the Transocean
Assets to Transocean in various transactions in various periods. The following
is a summary of these transactions executed during 2003 and 2002:
IN-KIND DISTRIBUTIONS:
- Twelve subsidiaries of the Company, Falcon Atlantic Ltd., R&B Falcon
Drilling do Brasil, Ltda., R&B Falcon International Energy Services B.V.,
R&B Falcon B.V., R&B Falcon (M) Sdn. Bhd., RBF Rig Corporation LLC, Shore
Services LLC, R&B Falcon Inc. LLC, R&B Falcon Canada Co., Transocean
Offshore Drilling Services LLC, R&B Falcon (A) Pty. Ltd. and Cliffs
Drilling do Brasil Servicos de Petroleo S/C Ltda, with an aggregate net
book value of $44.6 million and $54.1 million, were distributed as
in-kind dividends for no consideration to Transocean in 2003 and 2002,
respectively. The
84
transactions were recorded as decreases to additional paid-in capital.
RBF Rig Corporation LLC owns the drilling rig C. E. Thornton and
Transocean Offshore Drilling Services LLC owns the drilling rig J. T.
Angel. R&B Falcon (A) Pty. Ltd. owns the drilling unit Ron Tappmeyer.
- Nine drilling rigs, the F. G. McClintock, the Peregrine III, the Charley
Graves, the W. D. Kent, Land Rig 34, the J. W. McLean, the Randolph Yost,
the D. R. Stewart and the George H. Galloway, the operating lease for the
M. G. Hulme, Jr. and certain other surplus assets with an aggregate net
book value of $278.8 million were distributed, in separate transactions,
as in-kind dividends for no consideration to Transocean during 2002. The
transactions were recorded as a decrease to additional paid-in capital.
- Certain accounts receivable balances from related parties in the amount
of $200.9 million were distributed to Transocean as an in-kind dividend
for no consideration in 2003. The transaction was recorded as a decrease
to additional paid-in capital.
- Net deferred tax assets of $45.2 million related to the distributions and
sales of rigs, subsidiaries and certain assets were distributed as
in-kind dividends for no consideration to Transocean in 2002. The
transactions were recorded as a reduction to additional paid-in capital.
- The prepaid (accrued) costs related to the Company's defined benefit
pension plans and retiree life and medical insurance plans with a net
book value of $5.3 million were distributed as an in-kind dividend for no
consideration to Transocean in 2002. The transaction was recorded as a
decrease to additional paid-in capital. See Note 16.
- A 12.5 percent undivided interest in an aircraft was assigned to
Transocean for no consideration in 2003. The net book value of $1.0
million was recorded as a decrease to additional paid-in capital.
- Miscellaneous Transocean Assets with a value of $1.4 million were
distributed to Transocean in 2003. The transaction was recorded as a
decrease to additional paid-in capital.
SALES:
- The Company sold to Transocean the stock of Arcade Drilling AS, a
subsidiary that owns and operates the Paul B. Loyd, Jr. and owns the
Henry Goodrich, for net proceeds of $264.1 million and recorded a net
pre-tax loss of $11.0 million. The sales transaction was at fair value
determined based on an independent third party appraisal, which is
included in the results of discontinued operations. In consideration for
the sale of the subsidiary, Transocean cancelled $233.3 million principal
amount of the Company's 6.95% notes due April 2008. The market value
attributable to the notes, 113.21 percent of the principal amount, was
based on an independent third party appraisal. The Company recorded a net
pre-tax loss of approximately $30.0 million in 2003 related to the
retirement of these notes. (See Note 6.)
- The Company sold Cliffs Platform Rig 1 to Transocean in consideration for
the cancellation of $13.9 million of the 6.95% Senior Notes held by
Transocean. The Company recorded the excess of the sales price over the
net book value of $1.6 million as an increase to additional paid-in
capital and a pre-tax loss on the retirement of debt of $1.5 million in
2003. (See Note 6.)
- In 2003, the Company sold to Transocean its 50 percent interest in
Deepwater Drilling L.L.C. ("DD LLC"), which leases the drilling unit
Deepwater Pathfinder, and its 60 percent interest in Deepwater Drilling
II L.L.C. ("DDII LLC"), which leases the drilling unit Deepwater
Frontier, in consideration for the cancellation of $43.7 million
principal amount of the Company's debt held by Transocean. The value of
the Company's interests in DD LLC and DDII LLC was determined by
Transocean based on a similar third party transaction. The Company
recorded the excess of the sales price over the net book value of the
membership interests of $21.6 million as an increase to additional
paid-in capital.
- In 2003, the Company sold to Transocean its membership interests in its
wholly-owned subsidiary, R&B Falcon Drilling (International & Deepwater)
Inc. LLC, which owns: (1) the drilling unit Jim Cunningham;(2) all of the
stock of R&B Falcon Deepwater (UK) Ltd., which has specified charter
85
rights with respect to the drilling unit Deepwater Nautilus; (3) all of the
stock of THE Exploration LLC, which is the issuer of the Class A1 Notes due May
2005 related to the drilling unit Deepwater Nautilus; (4) several dormant or
near dormant subsidiaries; and (5) other miscellaneous assets. As
consideration for the stock sold, Transocean cancelled $238.8 million of
the Company's outstanding debt held by Transocean. The sales transaction
was based on a valuation by Transocean which takes into account valuations
of the drilling units provided by R.S. Platou (U.S.A.) Inc. The Company
recorded the excess of the net book value over the sales price of the
membership interests of $60.9 million as a loss on sale of assets,
included in the results of discontinued operations and a pre-tax loss on
the retirement of debt of $48.0 million. (See Note 6).
- The Company sold, in separate transactions, the Harvey H. Ward and the
Roger W. Mowell to Transocean for net proceeds of $93.0 million during
2002. The sales transactions were at fair market value based on third
party appraisals. In consideration for the sales of these drilling units,
Transocean delivered promissory notes due April 3, 2012 bearing interest
at 5.5 percent per annum payable annually in the aggregate principal
amount of $93.0 million. The excess of the sales price over the net book
value of the rigs of $5.4 million was recorded as additional paid-in
capital. For the year ended December 31, 2002, the Company accrued $3.6
million in interest income relating to the notes. In December 2002,
Transocean repaid to the Company the $93.0 million aggregate principal
amount of the promissory notes plus accrued and unpaid interest.
- Five subsidiaries of the Company, R&B Falcon (Ireland) Limited, RB Anton
Limited, RB Astrid Limited, RB Mediterranean Limited and PT RBF Offshore
Drilling, were sold in separate transactions during 2002, to Transocean
for net proceeds of $2.5 million. The sales prices of R&B Falcon
(Ireland) Limited, RB Mediterranean Limited and PT RBF Offshore Drilling
were determined by the Company based on internal valuations. The sales
prices of RB Anton Limited and RB Astrid Limited were determined based on
recommendations from a third party consulting firm that manages the
assets held by these companies. The excess of the net proceeds over the
net book value of the subsidiaries of $1.2 million was recorded as
additional paid-in capital.
ASSIGNMENTS:
- The rights and obligations under a rig sharing agreement for the
Deepwater Millenium and the drilling contracts for the Deepwater Horizon
and the Deepwater Discovery were assigned for no consideration to
Transocean in 2002.
- The Company assigned to Transocean the drilling contracts for the
drilling units Deepwater Frontier in 2003 and for the Deepwater Navigator
and Peregrine 1 in 2002 for no consideration.
NOTE 24 -- SUBSEQUENT EVENTS (UNAUDITED)
Capital Stock Transactions and Retirement of Related Party Debt -- In
February 2004, prior to the Company's IPO, the Company exchanged $45,784,000 in
principal amount of its outstanding 7.375% Senior Notes held by Transocean
Holdings for 359,638 shares of the Company's Class B common stock (4,367,714
shares of Class B common stock after giving effect to the stock dividend
discussed below). Immediately following this exchange the Company exchanged
$152,463,000 and $289,793,000 principal amount of its outstanding 6.75% and 9.5%
Senior Notes, respectively, held by Transocean for 3,580,768 shares of the
Company's Class B common stock (43,487,535 shares of Class B common stock after
giving effect to the stock dividend). The determination of the number of shares
issued in the exchange transactions was based on a method that took into account
the IPO price of $12.00 per share. In connection with the exchange of related
party debt for Class B common stock, the Company expensed $1.9 million in
deferred consent fees associated with these senior notes payable.
Immediately following the debt-for-equity exchanges, the Company declared a
dividend of 11.145 shares of its Class B common stock with respect to each share
of its Class B common stock outstanding immediately following the
debt-for-equity exchanges.
86
The stock dividend of 11.145 shares of Class B common stock for each
outstanding share of Class B common stock has been retroactively applied to the
1,000,000 shares of common stock held by Transocean prior to the debt-for-equity
exchanges and has been reflected in the Company's historical consolidated
financial statements since January 31, 2001, the date of the Transocean Merger.
The effect of this retroactive application was to increase the authorized common
shares of the Company's Class B common stock to 260,000,000 shares and issued
and outstanding to 12,144,751 shares for all periods presented with a
corresponding decrease to additional paid-in capital. The effect of the
debt-for-equity exchanges and the stock dividend on such newly issued shares of
common stock will be reflected in the first quarter of 2004.
As a result of the debt-for-equity exchanges and stock dividend, Transocean
held an aggregate of 60,000,000 shares of Class B common stock prior to the
closing of the IPO. A portion of these shares of Class B common stock was sold
and converted into shares of Class A common stock in the IPO.
Initial Public Offering -- In February 2004, the Company completed the IPO
of 13,800,000 shares of its Class A common stock at $12.00 per share. The
Company did not receive any proceeds from the initial sale of Class A common
stock. Transocean currently owns 46,200,000 shares or 100 percent of the
outstanding Class B common stock giving it 94 percent of the combined voting
power of the Company's outstanding common stock due to the five votes per share
of Class B common stock as compared to the one vote per share of Class A Common
stock. Transocean does not own any of the Company's outstanding Class A common
stock and has advised the Company that its current long-term intent is to
dispose of the Company's Class B common stock owned by it.
Upon completion of the IPO, the Company entered into various agreements to
complete the separation of the Shallow Water business from Transocean, including
an employee matters agreement, a master separation agreement and a tax sharing
agreement. The master separation agreement provides for, among other things, the
assumption by the Company of liabilities relating to the Shallow Water business
and the assumption by Transocean of liabilities unrelated to the Shallow Water
business, including the indemnification of losses that may occur as a result of
certain of the Company's ongoing legal proceedings (see Note 13).
Under the tax sharing agreement, Transocean will indemnify the Company
against substantially all pre-IPO income tax liabilities. However, the Company
must pay Transocean for substantially all pre-closing income tax benefits
utilized subsequent to the closing of the IPO. As of December 31, 2003, the
Company had approximately $450 million of pre-closing tax benefits subject to
this obligation to reimburse Transocean. This amount includes approximately $173
million of the tax benefits reflected in the Company's December 31, 2003
historical financial statements and additional tax benefits that we expect to
result from the closing of the IPO, specified ownership changes, statutory
allocations of tax benefits among Transocean Holdings' consolidated group
members and other events. The tax sharing agreement also provides that if any
person other than Transocean or its subsidiaries becomes the beneficial owner of
greater than 50% of the total voting power of the Company's outstanding voting
stock, it will be deemed to have utilized all of these pre-closing tax benefits,
and the Company will be required to pay Transocean an amount for the deemed
utilization of these tax benefits adjusted by a specified discount factor. If an
acquisition of beneficial ownership had occurred on December 31, 2003, the
estimated amount that the Company would have been required to pay to Transocean
would have been approximately $360 million.
Stock Based Compensation -- In February 2004, the Company adopted a long
term incentive plan for certain employees and nonemployee directors of the
Company in order to provide additional incentives through the grant of awards
and to increase the personal stake of participants in the continued success of
the Company (the "Plan"). The Plan provides for the grant of options to purchase
shares of the Company's Class A common stock, restricted stock, deferred stock
units, share appreciation rights, cash awards, supplemental payments to cover
tax liabilities associated with the aforementioned types of awards, and
performance awards. Most awards under the Plan vest over a three-year period. A
maximum of 3,000,000 shares of the Company's Class A common stock has been
reserved for issuance under the Plan.
In conjunction with the closing of the IPO, the Company granted shares of
restricted stock and stock options to certain employees. Based upon the IPO
price of $12.00 per share, the value of these awards that the Company will
recognize as compensation expense is approximately $17.2 million, of which
approximately
87
$6.5 million will be recognized in the first quarter of 2004. The remaining
$10.7 million of compensation expense will be recognized over the vesting period
of the stock awards and options. The Company expects to recognize compensation
expense related to these awards of $4.2 million over the remainder of 2004, $4.8
million in 2005 and $1.7 million in 2006 and thereafter.
In addition, certain of the Company's employees hold options to acquire
Transocean ordinary shares, which were granted prior to the IPO under the
Transocean Incentive Plan (see Note 15). The employees holding these options
were treated as terminated for the convenience of Transocean on the IPO date. As
a result, these options became fully vested and will remain exercisable over the
original contractual life. In connection with the modification of the options,
the Company will recognize approximately $1.5 million of additional compensation
expense in the first quarter of 2004.
Delta Towing Tug Sale -- In March 2004, Delta Towing entered into an
agreement to sell the Goliath, an offshore tug, for $5.0 million, subject to
satisfactory inspections and other customary closing conditions. The Company
expects the sale to close in late March 2004 and result in a gain.
88
TODCO AND SUBSIDIARIES
SCHEDULE II -- VALUATION AND QUALIFYING ACCOUNTS
ADDITIONS
---------------------
CHARGED CHARGED
BALANCE AT TO COSTS TO OTHER BALANCE AT
BEGINNING AND ACCOUNTS DEDUCTIONS END OF
OF PERIOD EXPENSES (DESCRIBE) (DESCRIBE) PERIOD
---------- -------- ---------- ---------- ----------
(IN MILLIONS)
PRE-TRANSOCEAN MERGER
ONE MONTH ENDED JANUARY 31, 2001
Reserves and allowances deducted from
asset accounts:
Allowance for doubtful accounts
receivable........................... $6.5 $0.1 $ -- $0.3(a) $6.3
Allowance for obsolete materials and
supplies............................. 0.7 -- -- -- 0.7
--------------------------------------------------------------------------------------------------------
POST-TRANSOCEAN MERGER
ELEVEN MONTHS ENDED DECEMBER 31, 2001
Reserves and allowances deducted from
asset accounts:
Allowance for doubtful accounts
receivable........................... 6.3 4.2 -- 1.7(a) 8.8
Allowance for obsolete materials and
supplies............................. 0.7 -- -- 0.5(b) 0.2
YEAR ENDED DECEMBER 31, 2002
Reserves and allowances deducted from
asset accounts:
Allowance for doubtful accounts
receivable........................... 8.8 4.1 -- 6.2(a) 6.7
Allowance for obsolete materials and
supplies............................. 0.2 -- -- 0.2(b) --
YEAR ENDED DECEMBER 31, 2003
Reserves and allowances deducted from
asset accounts:
Allowance for doubtful accounts
receivable........................... 6.7 0.4 0.4(c) 2.5(a) 5.0
Allowance for obsolete materials and
supplies............................. $ -- $0.3 $ -- $ -- $0.3
---------------
(a) Uncollectible accounts receivable written off, net of recoveries.
(b) Amount is related to the sale of a rig and distribution of assets to a
related party.
(c) Balance attributable to consolidation of Delta Towing at December 31, 2003.
Other schedules have been omitted either because they are not required or
are not applicable, or because the required information is included in the
consolidated financial statements or notes thereto.
89
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTS ON ACCOUNTING AND FINANCIAL
DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
As of December 31, 2003, 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 the
design and operation of our disclosure controls and procedures pursuant to
Exchange Act Rule 13a-15. Based upon that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures are effective. Disclosure controls and procedures are controls and
procedures that are designed to ensure 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.
There have been no significant changes in our internal control over
financial reporting that have materially affected, or are reasonably likely to
materially affect, our internal control over financial reporting.
90
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
The following table sets forth the names, ages and positions of our
directors and executive officers as of March 1, 2004:
NAME AGE POSITION
---- --- --------
Gregory L. Cauthen........................ 46 Director
Thomas R. Hix............................. 56 Director
Arthur Lindenauer......................... 66 Director
Robert L. Long............................ 58 Director
J. Michael Talbert........................ 57 Director and Chairman of the Board
Jan Rask.................................. 48 President and Chief Executive Officer
and Director
T. Scott O'Keefe.......................... 48 Senior Vice President and Chief
Financial Officer
David J. Crowley.......................... 45 Vice President -- Marketing
Michael L. Kelley......................... 45 Vice President -- Domestic Operations
Lloyd M. Pellegrin........................ 56 Vice President -- Human Resources
Randall A. Stafford....................... 48 Vice President, General Counsel and
Corporate Secretary
Dale W. Wilhelm........................... 41 Vice President and Controller
Gregory L. Cauthen has served as director since July 2002. He is Senior
Vice President and Chief Financial Officer of Transocean. He was also Treasurer
of Transocean until July 2003. Mr. Cauthen served as Vice President, Chief
Financial Officer and Treasurer from December 2001 until he was elected Senior
Vice President in July 2002. From March 2001 until December 2001, Mr. Cauthen
served as Vice President, Finance of Transocean. Prior to joining Transocean, 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 and 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.
Thomas R. Hix was appointed as a director in February 2004. He was senior
Vice President and Chief Financial Officer of Cooper Cameron Corporation, a
petroleum and industrial equipment and services company, from January 1995 until
December 2002. Mr. Hix has been retired since January 2003. Previously, he was
Senior Vice President of Finance, Treasurer and Chief Financial Officer of The
Western Company of North America from September of 1993 to April 1995.
Arthur Lindenauer was appointed as a director in February 2004. He has been
a director of Transocean since 1999. He became Chairman of the Board of
Schlumberger Technology Corporation, the principal U.S. subsidiary of
Schlumberger Limited, a global oilfield and information services company, in
December 1998 and served in that position through February of 2004. He
previously served as Executive Vice President -- Finance and Chief Financial
Officer of Schlumberger from January 1980 to December 1998. Mr. Lindenauer was a
partner with the accounting firm of Price Waterhouse from 1972 to 1980. Mr.
Lindenauer is also a director of the New York Chapter of the Cystic Fibrosis
Foundation, a Trustee of the American University in Cairo and a member of the
Board of Overseer's of the Tuck School of Business at Dartmouth College.
Robert L. Long has served as director since our merger transaction with
Transocean in January 2001. He is President and Chief Executive Officer and a
director of Transocean. Mr. Long served as Chief Financial Officer of Transocean
from August 1996 until December 2001, at which time he assumed the position of
91
President. Mr. Long also served as Chief Operating Officer from June 2002 until
October 2002, when he assumed the additional position of Chief Executive
Officer. Mr. Long served as Senior Vice President of Transocean from May 1990
until the time of Transocean's merger transaction with Sedco Forex, at which
time he assumed the position of Executive Vice President. Mr. Long also served
as Treasurer of Transocean from September 1997 until March 2001. Mr. Long has
been employed by Transocean since 1976 and was elected Vice President in 1987.
J. Michael Talbert has served as director since July 2002. He is Chairman
of the Board of Directors of Transocean. He has served as a member of the Board
of Directors of Transocean since August 1994. Mr. Talbert served as Chief
Executive Officer of Transocean from August 1994 until October 2002, at which
time he became Chairman of the Board of Directors. Mr. Talbert also served as
Chairman of the Board of Transocean from August 1994 until the time of
Transocean's merger transaction with Sedco Forex and as President of Transocean
from the time of such merger until December 2001. Prior to assuming his duties
with Transocean, Mr. Talbert was President and Chief Executive Officer of Lone
Star Gas Company, a natural gas distribution company and a division of Ensearch
Corporation. He is also a director of El Paso Corporation, a diversified natural
gas company.
Jan Rask has been our President and Chief Executive Officer and has served
as a director since July 2002. Mr. Rask was Managing Director, Acquisitions and
Special Projects, of Pride International, Inc., a contract drilling company,
from September 2001 to July 2002, when he joined our company. From July 1996 to
September 2001, Mr. Rask was President, Chief Executive Officer and a director
of Marine Drilling Companies, Inc., a contract drilling company. Mr. Rask served
as President and Chief Executive Officer of Arethusa (Off-Shore) Limited from
May 1993 until the acquisition of Arethusa (Off-Shore) Limited by Diamond
Offshore Drilling, Inc. in May 1996. Mr. Rask joined Arethusa (Off-Shore)
Limited's principal operating subsidiary in 1990 as its President and Chief
Executive Officer. Mr. Rask has been a director of Veritas DGC Inc., an
integrated geophysical service company, since 1998.
T. Scott O'Keefe has been our Senior Vice President and Chief Financial
Officer since July 2002. From April 2002 to July 2002, Mr. O'Keefe was an
independent financial consultant. Mr. O'Keefe was Vice President of Pride
International, Inc. from September 2001 until April 2002. Mr. O'Keefe was Senior
Vice President, Chief Financial Officer and Secretary of Marine Drilling
Companies, Inc. from January 1998 until September 2001. From April 1996 to
January 1998, Mr. O'Keefe was a consultant to and Senior Vice President and
Chief Financial Officer of Grey Wolf, Inc., a contract drilling company. From
March 1995 to April 1996, Mr. O'Keefe provided financial consulting services to
various energy companies. From June 1980 to March 1995, Mr. O'Keefe held various
financial management positions with public and private oil and gas related
companies. He began his professional career with Price Waterhouse & Co. in 1978.
David J. Crowley has been our Vice President -- Marketing since April 2003.
Mr. Crowley was Director of Marketing at ENSCO International, Inc. from February
2001 to April 2003, when he joined our company. Mr. Crowley served as Manager of
Marketing for the Schlumberger -- Integrated Project Management group from
November 1999 to January 2001. From February 1997 to October 1999, Mr. Crowley
served as Manager of Marketing for Schlumberger Oilfield Services UK Ltd. Prior
to February 1997, Mr. Crowley held various management positions in operations,
engineering and marketing spanning 17 years for Sedco Inc. and Sedco Forex in
Europe, West Africa, Middle East, India and Southeast Asia.
Michael L. Kelley became our Vice President -- Domestic Operations in
February 2004. Mr. Kelley was Manager -- Operations at ENSCO Offshore Company,
the domestic offshore drilling division of ENSCO International, Inc., from April
1999 to January 2004. From June 1982 to April 1999, Mr. Kelley served in various
capacities at R&B Falcon Corporation, the latest of which was as Drilling
Superintendent from July 1991 to April 1999. Prior to June 1982, Mr. Kelley held
various positions with Tierra Drilling Company.
Lloyd M. Pellegrin has been our Vice President -- Human Resources since
November 2002. Mr. Pellegrin was Region Human Resource Manager, Shallow and
Inland Water Region of Transocean from February 2001 until November 2002. From
January 1998 until January 2001, Mr. Pellegrin served as Vice President,
Administration of R&B Falcon Drilling USA, Inc. Mr. Pellegrin also served as
Vice President, Administration with Falcon Drilling Company, Inc. from November
1992 until January 1998. Prior to
92
November 1992, Mr. Pellegrin worked for Atlantic Pacific Marine Corp. for 15
years, most recently as Vice President, Administration.
Randall A. Stafford became our Vice President, General Counsel and
Corporate Secretary in January 2003. From January 2001 until January 2003, Mr.
Stafford served as Associate General Counsel of Transocean. From January 2000
until January 2001, Mr. Stafford served as Counsel to R&B Falcon. From January
1990 until January 2000, Mr. Stafford was employed as Associate General Counsel
of Pool Energy Services Company, an international oil and gas drilling and well
servicing company that was acquired by Nabors Industries in November 1999.
Dale W. Wilhelm has been our Vice President and Controller since July 2003.
From July 2002 to July 2003, Mr. Wilhelm was an independent financial
consultant. Mr. Wilhelm was Vice President and Controller of Marine Drilling
Companies, Inc., a contract drilling company, from May 1998 to July 2002. From
August 1997 to May 1998, Mr. Wilhelm was Corporate Controller of Continental
Emsco Company, an oilfield equipment manufacturer and distributor, and from
September 1994 to August 1997, he was Corporate Controller of Serv-Tech, Inc.,
an industrial maintenance provider. Mr. Wilhelm was Assistant Corporate
Controller for CRSS Inc., an engineering and construction company, from May 1990
to September 1994. Prior to May 1990, Mr. Wilhelm was with the public accounting
firm of KPMG, LLP as Audit Manager. Mr. Wilhelm is a certified public
accountant.
BOARD AND COMMITTEE ACTIVITY AND STRUCTURE
The audit committee, which consists of Messrs. Cauthen, Hix, and Lindenauer
(Chairman), reviews and reports to the board of directors the scope and results
of audits by our outside auditor and our internal auditing function and review
with the outside auditor the adequacy of our system of internal controls, with
both Messrs. Hix and Lindenauer qualifying as "financial experts." It reviews
transactions between us and our directors and officers, our policies regarding
those transactions and compliance with our business ethics and conflict of
interest policies. The audit committee also recommends to the board of directors
a firm of certified public accountants to serve as our outside auditor for each
fiscal year, review the audit and other professional services rendered by the
outside auditor and periodically review the independence of the outside auditor.
We expect to appoint one additional director to this committee within one year
to replace Mr. Cauthen in order to satisfy the New York Stock Exchange and
Securities and Exchange Commission requirements for independence of members of
audit committees.
The executive compensation committee, which consists of Messrs. Hix and
Long (chairman), reviews and recommends to the board of directors the
compensation and benefits of our executive officers, establishes and reviews
general policies relating to our compensation and benefits and administers our
stock plans. We expect to appoint one additional outside, independent director
to this committee within one year.
We do not have a nominating committee; rather, the entire Board of
Directors participates in such decisions.
In addition to regularly scheduled board and committee meetings, our
non-management directors meet in executive sessions without the presence of
management in conjunction with regularly scheduled board meetings. These
sessions are led by the Chairman of the Board of Directors, Mr. Talbert.
Beginning at the time Transocean ceases to own at least a majority of the
voting power of our outstanding capital stock, our directors will be divided
into three classes serving staggered three-year terms. At each annual meeting of
stockholders, directors will be elected to succeed the class of directors whose
terms have expired. This classification of our board of directors could have the
effect of increasing the length of time necessary to change the composition of a
majority of the board of directors. Following this classification of the board,
in general, at least two annual meetings of stockholders will be necessary for
stockholders to effect a change in a majority of the members of the board of
directors. Prior to this classification of the board, each director will serve
for a term ending on the next annual meeting date or until his or her successor
has been duly elected and qualified or until his or her earlier death,
resignation or removal.
93
Because we are considered to be controlled by Transocean under New York
Stock Exchange Corporate Governance Rules, we are eligible for exemptions from
provisions of those rules requiring a majority of independent directors,
nominating/corporate governance and compensation committees composed entirely of
independent directors and written charters addressing specified matters. We have
elected to take advantage of these exemptions. In the event that we cease to be
a controlled company within the meaning of these rules, we will be required to
comply with these provisions after the specified transition periods.
The master separation agreement provides Transocean with continuing rights
to nominate board and committee members. See "Certain Relationships and Related
Party Transactions -- Relationship Between Us and Transocean -- Master
Separation Agreement."
COMPLIANCE WITH SECTION 16(a) OF THE EXCHANGE ACT
Section 16(a) of the Exchange Act requires our directors and executive
officers, and person who own 10% or more of our voting stock to file reports of
ownership and changes in ownership of our equity securities with the SEC and the
New York Stock Exchange. Directors, executive officers and 10% or more
stockholders are required by SEC regulations to furnish us with copies of all
Section 16(a) reports they file.
Based solely on a review of the copies of these reports furnished to us, or
written representations that no forms were required, we believe that our
directors, executive officers and 10% or more beneficial owners complied with
all Section 16(a) filing requirements during the most recent fiscal year.
WEBSITE AVAILABILITY OF CORPORATE GOVERNANCE AND OTHER DOCUMENTS
We have adopted a code of conduct and ethics applicable to our directors
and employees, including our Chief Executive Officer, Chief Financial Officer,
Controller and other executive officers. In addition to our code of ethics, the
following documents are available on the Company's website,
www.theoffshoredrillingcompany.com: (1) the Company's corporate governance
guidelines, and (2) key Board Committee charters, including charters for our
Audit and Compensation Committees.
Stockholders also may obtain print copies of these documents by submitting
a written request to Randall A. Stafford, Corporate Secretary of the Company,
2000 W. Sam Houston Parkway South, Suite 800, Houston, Texas 77042. If any
amendments are made to, or any waivers are granted with respect to, provisions
of the codes of conduct and ethics adopted by the Company that apply to their
respective Chief Executive Officers, Chief Financial Officers or Controllers,
the Company will disclose the nature of such amendment or waiver on its website.
94
ITEM 11. EXECUTIVE COMPENSATION
SUMMARY COMPENSATION TABLE
The following table shows the aggregate compensation paid to our chief
executive officer and four other most highly compensated executive officers (the
"Named Executive Officers") during the years ended December 31, 2002 and 2003.
All information set forth in this table reflects compensation earned by these
individuals for the years ended December 31, 2002 and 2003.
SUMMARY COMPENSATION TABLE
ANNUAL COMPENSATION LONG-TERM COMPENSATION AWARDS
----------------------------------------- ----------------------------------
SECURITIES ALL OTHER
OTHER ANNUAL RESTRICTED STOCK UNDERLYING COMPENSATION
NAME AND PRINCIPAL POSITION YEAR SALARY($) BONUS($)(a) COMPENSATION($) AWARD($) OPTIONS/SARS(b) ($)(c)
--------------------------- ---- --------- ----------- --------------- ---------------- --------------- ------------
Jan Rask................... 2003 530,000 -0- -- -- -- 2,347
President and Chief 2002 242,917(d) 194,103 -- -- -- 150
Executive Officer
T. Scott O'Keefe........... 2003 260,000 19,500 -- -- -- 9,360
Senior Vice President and 2002 118,333(d) 66,207 -- -- -- 1,125
Chief Financial Officer
David J. Crowley........... 2003 129,026(d) 9,677 39,808(e) -- -- 3,709
Vice
President -- Marketing 2002 -- -- -- -- -- --
Rodney W.
Meisetschlaeger........... 2003 178,861 -0- -- -- -- 8,566
Vice President -- Offshore 2002 174,580 36,941 -- -- 10,500 8,068
Operations(f)
Randall A. Stafford........ 2003 170,000 1,913 -- -- -- 360
Vice President, General 2002 145,000 23,849 -- -- 6,500 360
Counsel and Corporate
Secretary
---------------
(a) The amounts under "Bonus" for 2003 and 2002 represent amounts earned with
respect to such year but paid during the following year.
(b) Represents options to purchase Transocean ordinary shares at fair market
value on the date of the grants.
(c) The amounts shown as "All Other Compensation" represent:
SAVINGS PLAN PAYMENTS UNDER
MATCHING LIFE INSURANCE
YEAR CONTRIBUTIONS PROGRAM
---- ------------- --------------
Mr. Rask................................... 2003 $1,987 $360
2002 -- 150
Mr. O'Keefe................................ 2003 9,000 360
2002 975 150
Mr. Crowley................................ 2003 3,469 240
2002 -- --
Mr. Meisetschlaeger........................ 2003 8,100 466
2002 7,856 212
Mr. Stafford............................... 2003 -- 360
2002 -- 360
(d) Mr. Rask, Mr. O'Keefe and Mr. Crowley began their employment with us on
July 16, 2002, July 18, 2002 and April 21, 2003, respectively. Their annual
base salaries are $530,000, $260,000 and $185,000, respectively.
(e) Represents moving expense reimbursements.
(f) Mr. Meisetschlaeger left our company in January 2004.
95
GRANTS AND EXERCISES OF TRANSOCEAN STOCK OPTIONS
There were no grants of options to acquire our common stock or Transocean
ordinary shares to the executive officers named in the summary compensation
table above, or exercises of such options by such executive officers, in the
year ended December 31, 2003.
EMPLOYMENT AGREEMENTS AND CHANGE OF CONTROL ARRANGEMENTS
We entered into an employment agreement with Mr. Jan Rask effective as of
July 16, 2002, as amended on December 12, 2003, to serve as Chief Executive
Officer and President of our company in exchange for specified compensation and
benefits. The initial term of his employment agreement ends on January 16, 2007.
Afterwards, the agreement automatically renews for an additional one-year term
on each anniversary of the effective date of the agreement unless either party
gives at least a six-month advance written notice of nonrenewal. Mr. Rask's
employment agreement calls for a minimum base salary of $530,000 per year, which
will be reviewed at least annually and may be increased afterwards. The
agreement also affords Mr. Rask the opportunity to receive an annual
discretionary bonus that is tied to his achievement of specified performance
objectives established by our board of directors. Mr. Rask's annual
discretionary bonus is calculated by multiplying his percentage of attained
objectives by his annual target bonus, which is a specified percentage of his
base salary. For each year of the initial term of his employment agreement, Mr.
Rask's annual target bonus will be no less than 70% of his base salary. Under
the agreement, Mr. Rask also is eligible to receive stock option awards at the
discretion of the board and is entitled to participate in our applicable
incentive, savings, retirement and welfare plans and to receive specified
perquisites.
The employment agreement also provided that since Mr. Rask was still
employed under the agreement on the closing date of the IPO, then he would
receive a nonqualified stock option to purchase a number of shares of Class A
common stock equal to 2% of the aggregate number of outstanding shares of common
stock immediately after the closing of the IPO. The exercise price of the shares
subject to the option is $12.00 per share. The option has a ten-year term
(except in the case of Mr. Rask's termination) and one-half of the shares
subject to the option become exercisable on February 10, 2004. The remaining
shares subject to the option become exercisable on February 10, 2005 and 2006 in
equal increments. In addition to the option, since Mr. Rask was employed under
the agreement on the closing date of the IPO, he received 156,496 of restricted
shares of Class A common stock. The restricted shares vest on July 16, 2005. The
option and restricted shares are subject to the other terms and conditions,
consistent with the foregoing, of our incentive plan and applicable award
agreement.
We entered into an employment agreement with Mr. T. Scott O'Keefe effective
as of July 18, 2002, as amended on December 12, 2003, to serve as Chief
Financial Officer and Senior Vice President of our company in exchange for
specified compensation and benefits. The initial term of his employment
agreement ends on January 18, 2006. Afterwards, the agreement automatically
renews for an additional one-year term on each anniversary of the effective date
of the agreement unless either party gives at least a six-month advance written
notice of nonrenewal. Mr. O'Keefe's employment agreement calls for a minimum
base salary of $260,000 per year, which will be reviewed at least annually and
may be increased afterwards. The agreement also affords Mr. O'Keefe the
opportunity to receive an annual discretionary bonus that is tied to his
achievement of specified performance objectives established by our board of
directors. Mr. O'Keefe's annual discretionary bonus is calculated by multiplying
his percentage of attained objectives by his annual target bonus, which is a
specified percentage of his base salary. For each year of the initial term of
his employment agreement, Mr. O'Keefe's annual target bonus will be no less than
50% of his base salary. Under the agreement, Mr. O'Keefe also is eligible to
receive stock option awards at the discretion of the board and is entitled to
participate in our applicable incentive, savings, retirement and welfare plans
and to receive specified perquisites.
The employment agreement provides that since Mr. O'Keefe was still employed
under the agreement on the closing date of the IPO, then he would receive a
nonqualified stock option to purchase a number of shares of Class A common stock
equal to 0.35% of the aggregate number of outstanding shares of common stock
immediately after the closing of the IPO, but which will in no event be less
than 150,000 shares and no more
96
than 250,000 shares. The exercise price of the shares subject to the option is
equal to $12.00 per share. The option has a 10-year term (except in the case of
Mr. O'Keefe's termination) and one-half of the shares subject to the option
become exercisable on February 10, 2004. The remaining shares subject to the
option become exercisable on the February 10, 2005 and 2006 in equal increments.
The option is subject to the other terms and conditions, consistent with the
foregoing, of our incentive plan and applicable award agreement.
We entered into an employment agreement with Mr. David J. Crowley effective
as of April 21, 2003, to serve as Vice President -- Marketing of our company in
exchange for specified compensation and benefits. The initial term of his
employment ends on April 21, 2005. Afterwards, the agreement automatically
renews for an additional one-year term on each anniversary of the effective date
of the agreement unless either party gives at least a six-month advance written
notice of nonrenewal. Mr. Crowley's employment agreement calls for a minimum
base salary of $185,000 per year, which will be reviewed at least annually and
may be increased afterwards. The agreement also affords Mr. Crowley the
opportunity to receive an annual discretionary bonus that is tied to his
achievement of specified performance objectives established by our board of
directors. Mr. Crowley's annual discretionary bonus is calculated by multiplying
his percentage of attained objectives by his annual target bonus, which is a
specified percentage of his base salary. For the term of his employment
agreement, Mr. Crowley's annual bonus target will be no less than 50% of his
base salary. Mr. Crowley is also eligible to receive stock option awards at the
discretion of the board and is entitled to participate in our applicable
incentive, savings, retirement and welfare plans and to receive specified
perquisites.
The employment agreement provides that since Mr. Crowley was still employed
under the agreement on the closing date of the IPO, then he would receive a
nonqualified stock option to purchase no less than 100,000 shares of Class A
common stock. The exercise price of the shares subject to the option is equal to
$12.00 per share. The option has a 10-year term (except in the case of Mr.
Crowley's termination) and one-third of the shares subject to the option become
exercisable on each of February 10, 2005, 2006, and 2007. The option is subject
to the other terms and conditions, consistent with the foregoing, of our
incentive plan and applicable award agreement.
Under these employment agreements, if any of Mr. Rask, Mr. O'Keefe or Mr.
Crowley voluntarily terminates his employment (other than in connection with a
"change in control" as defined in the agreements) with 90 days' advance written
notice or if his employment is terminated due to death or disability, he will
receive his unpaid base salary through his termination date, any bonus payable
for the relevant year and any other benefits to which he has a vested right.
Additionally, in the event of a termination due to death or disability, the
option and restricted shares awarded to him, if any, will fully vest and the
option will remain exercisable for its full term.
Upon termination of his employment by us (except under limited
circumstances defined as for "cause" in the agreements), the officer will
receive (1) his unpaid base salary for his remaining employment term (which
includes the initial term and any renewals), (2) any bonus payable for the
relevant year, (3) full vesting of the option awarded to him, if any, and
exercisability through its full term, (4) full vesting of restricted shares
awarded to him, if any, and (5) any other benefits to which he has a vested
right.
In the event of a termination of his employment by us (except under limited
circumstances defined as for "cause" in the agreements) or by the officer for
specified reasons, such as his removal from the position of Chief Executive
Officer and President in the case of Mr. Rask, the position of Chief Financial
Officer and Senior Vice President, in the case of Mr. O'Keefe, or the position
of Vice President -- Marketing in the case of Mr. Crowley, or the assignment to
him of duties materially inconsistent with his position with us (for "good
reason"), within the 18-month period immediately following a "change in control"
as defined in the agreement (a "change in control termination"), the officer
will be entitled to receive (1) three times, in the case of Mr. Rask, two and
one-half times in the case of Mr. O'Keefe, and two times in the case of Mr.
Crowley, his annual compensation for the year of termination (which is the sum
of his base salary and his annual target bonus, or, if greater, the highest
bonus paid to him under the agreement during the most recent 36-month period),
(2) any bonus payable for the relevant year, (3) continuation of specified
welfare benefits for three years, (4) full vesting of the option awarded to him,
if any, and exercisability through its full term, and (5) full vesting of
restricted shares awarded to him, if any.
97
The employment agreements also provide for covenants limiting competition
with us, or any of our affiliates, and limiting solicitation for employment of
any of our employees, or any of our affiliates, for 18 months following a change
in control termination or for one year following any other termination of
employment and a covenant to keep specified nonpublic information relating to
us, or any of our affiliates, confidential. With respect to any payment or
distribution to Mr. Rask, Mr. O'Keefe or Mr. Crowley, the agreements provide for
a tax gross-up payment designed to keep him whole with respect to any taxes
imposed by Section 4999 of the Internal Revenue Code of 1986, as amended.
SEVERANCE POLICY AND CHANGE OF CONTROL ARRANGEMENTS
Our board of directors has adopted a Severance Policy for specified
employees who are not entitled to change of control benefits under a written
employment agreement. The benefits under this policy are not available to
Messrs. Rask, O'Keefe or Crowley because each of those officers is already
entitled to change of control benefits under an employment agreement with us, as
described above in "Employment Agreements and Change of Control Arrangements."
The benefits are available to our other officers, including Mr. Stafford. In the
event of a termination of the employment of Mr. Stafford by us or by him for
specified reasons, such as receipt of notification of salary reduction,
reduction in job title, significant reduction of responsibilities or relocation
of employment, within the one-year period immediately following a "change of
control" as defined in the policy, he will be entitled to receive an amount
equal to his annual compensation for the year of termination (the sum of his
base salary and his annual target bonus).
DIRECTOR COMPENSATION
Directors who are also full-time officers or employees of our company or
officers or employees of Transocean will receive no additional compensation for
serving as directors. All other directors will receive an annual retainer of
$25,000. The audit committee chairman will receive an additional $15,000 annual
retainer. The compensation committee chairman will receive an additional $10,000
annual retainer. Nonemployee directors will also receive a fee of $1,500 for
each board or board committee meeting attended in person or by telephone, plus
incurred expenses where appropriate.
When elected, each outside director will be granted 5,000 restricted shares
of our Class A common stock. Following this restricted stock grant, if the
outside director remains in office, the director will be granted an option to
purchase 5,000 shares of Class A common stock after each annual meeting of
stockholders at the fair market value of those shares on the date of grant.
Since the Company will not hold an annual meeting of stockholders in 2004, the
2004 option grant will be made effective as of the Company's Board of Directors'
meeting in May 2004. Because awards to outside directors are not specified in
our Long-Term Incentive Plan, the board will have authority to determine the
awards made to outside directors under the plan from time to time without the
prior approval of our stockholders.
COMPENSATION COMMITTEE INTERLOCKS AND INSIDER PARTICIPATION
None of our executive officers have served as members of a compensation
committee (or if no committee performs that function, the board of directors) of
any other entity that has an executive officer serving as a member of our board
of directors.
98
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLAN
The following table provides information with respect to compensation plans
(including individual compensation arrangements) under which our equity
securities are authorized for issuance to employees or non-employees (such as
directors, consultants, advisors, vendors, customers, suppliers or lenders), as
of March 1, 2004:
NUMBER OF SECURITIES
NUMBER OF SECURITIES REMAINING AVAILABLE FOR
TO BE ISSUED WEIGHTED-AVERAGE FUTURE ISSUANCE UNDER
UPON EXERCISE OF EXERCISE PRICE OF EQUITY COMPENSATION PLANS
OUTSTANDING OPTIONS, OUTSTANDING OPTIONS, (EXCLUDING SECURITIES
PLAN CATEGORY WARRANTS AND RIGHTS WARRANTS AND RIGHTS REFLECTED IN COLUMN(A))
------------- -------------------- -------------------- -------------------------
(A) (B) (C)
Equity compensation plans approved
by security holders............. 1,925,903 $12/share 1,074,097
Equity compensation plans not
approved by security holders.... -- -- --
--------- --------- ---------
Total............................. 1,925,903 $12/share 1,074,097
========= ========= =========
SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS OF TODCO SHARES
The following table sets forth certain information known to the Company as
of March 1, 2004 with respect to the beneficial ownership of our common stock by
(i) each stockholder known by us to own beneficially more than 5% of the
outstanding shares of any class of common stock, (ii) each director, (iii) the
Chief Executive Officer and Named Executive Officers, and (iv) all directors and
executive officers as a group.
CLASS A CLASS B
COMMON STOCK COMMON STOCK
---------------------------- ----------------------------
NUMBER OF SHARES NUMBER OF SHARES
NAME OR IDENTITY OF GROUP AND ADDRESS BENEFICIALLY OWNED PERCENT BENEFICIALLY OWNED PERCENT
------------------------------------- ------------------ ------- ------------------ -------
Directors and Named Officers:
Jan Rask(a)............................. 756,496 5.15% 0 --%
T. Scott O'Keefe(a)..................... 105,000 * 0 --
David J. Crowley........................ 0 * 0 --
Michael L. Kelley....................... 0 * 0 --
Lloyd M. Pellegrin...................... 1,831 * 0 --
Randall A. Stafford..................... 2,394 * 0 --
Dale W. Wilhelm......................... 0 * 0 --
Thomas R. Hix........................... 5,000 * 0 --
Arthur Lindenauer....................... 5,000 * 0 --
Gregory L. Cauthen...................... 0 * 0 --
Robert L. Long.......................... 0 * 0 --
J. Michael Talbert...................... 0 * 0 --
All Directors and Officers as a
Group (12 persons)(a)................... 875,721 5.92% 0
Other Principal Stockholders:
Transocean.............................. 46,200,000(b) 75.7 46,200,000 100%
4 Greenway Plaza
Houston, TX 77046
---------------
(a) Includes the following number of shares of our Class A common stock which
the named party has the right to acquire upon exercise of stock options
that are (i) currently exercisable or (ii) exercisable within 60 days of
the date hereof: Mr. Rask -- 600,000; Mr. O'Keefe -- 105,000 and all
executive officers and directors as a group -- 705,000.
(b) Includes 46,200,000 of our Class B common stock held by Transocean which
may be converted to our Class A common stock.
* Less than 1%
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SECURITY OWNERSHIP OF DIRECTORS AND EXECUTIVE OFFICERS OF TRANSOCEAN SHARES
The following table sets forth information as of March 1, 2004 with respect
to the beneficial ownership of Transocean ordinary shares by each of our
directors and Named Executive Officers, and all of our directors and executive
officers as a group. Except as otherwise indicated in the footnotes, each
individual has sole voting and investment power with respect to the shares set
forth in the following table. Each director and officer and the directors and
officers as a group beneficially own less than 1% of Transocean's ordinary
shares.
SHARES OWNED
NAME OF BENEFICIAL OWNER(A) BENEFICIALLY(B)(C)
--------------------------- ------------------
Jan Rask................................................... --
T. Scott O'Keefe........................................... --
David J. Crowley........................................... --
Michael L. Kelley.......................................... --
Lloyd M. Pellegrin(d)...................................... 28,903
Randall A. Stafford........................................ 29,640
Dale W. Wilhelm............................................ 1,250
Thomas R. Hix.............................................. --
Arthur Lindenauer.......................................... 19,121
Gregory L. Cauthen(d)...................................... 22,017
Robert L. Long(d)(e)....................................... 233,427
J. Michael Talbert(d)(f)................................... 716,846
All directors and executive officers as a group(d)......... 1,051,204
---------------
(a) The business address of each director and executive officer is c/o TODCO,
2000 W. Sam Houston Parkway South, Suite 800, Houston, Texas 77042.
(b) Beneficial ownership means the sole or shared power to vote, or to direct
the voting of, Transocean ordinary shares, or investment power with respect
to Transocean ordinary shares, or any combination of the foregoing.
(c) Includes options exercisable within 60 days held by Messrs. Pellegrin
(25,640), Stafford (29,640), Cauthen (19,167), Lindenauer (14,121), Long
(190,999) and Talbert (635,732).
(d) Includes:
ALL DIRECTORS AND
MR. MR. MR. MR. EXECUTIVE OFFICERS
PELLEGRIN CAUTHEN LONG TALBERT AS A GROUP
--------- ------- ----- ------- ------------------
Shares held by Trustee under 401(k)
plan.............................. 2,493 -- 3,646 2,295 8,434
Shares held in Employee Stock
Purchase Plan..................... 769 1,351 4,461 -- 5,820
---------------
(e) Includes 30,029 shares held in a joint account with his wife.
(f) Includes 78,536 shares held in a joint account with his wife.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
MERGER WITH TRANSOCEAN
On January 31, 2001, we completed a merger transaction with Transocean in
which an indirect subsidiary of Transocean, TSF Delaware Inc., merged with and
into our company, which was then named R&B Falcon Corporation. On December 13,
2002, R&B Falcon changed its name to TODCO.
ASSET TRANSFERS TO TRANSOCEAN
For a description of the risks related to the transactions with Transocean
described below, see "Business Risk Factors -- Risks Related to Our Principal
Stockholder Transocean." The terms of our separation from
100
Transocean, the related agreements and other transactions with Transocean were
determined in the context of a parent-subsidiary relationship and thus may be
less favorable to us than the terms we could have obtained from an unaffiliated
third party.
The following table shows our drilling units and non-drilling units as of
December 31, 2000, prior to the merger transaction with Transocean, and as of
the closing of the IPO:
DECEMBER 31, 2000 AFTER IPO
----------------- ---------
DRILLING UNITS:
Semisubmersible and Drillship rigs....................... 19 0
Tender rigs.............................................. 2 0
Jackup rigs.............................................. 39 24
Submersible rigs......................................... 3 3
Inland barge rigs........................................ 33 30
Venezuela land and barge rigs............................ 16 12
Platform rigs............................................ 3 1
--- --
115 70
=== ==
NON-DRILLING UNITS:
MOPU..................................................... 3 0
Jackup units............................................. 0 5
Support Vessels.......................................... (a) (a)
---------------
(a) Includes inland tugs, offshore tugs, crewboats, deck barges, shale barges,
spud barges, offshore barges and other service vessels. In conjunction with
the Transocean Merger in January 2001, we contributed this business to
Delta Towing in return for a 25% ownership interest in Delta Towing.
The following describes transfers of our assets to Transocean between the
date of our acquisition by Transocean and the closing of the IPO, including
transfers of the Transocean Assets to Transocean. None of the drilling rigs
transferred to Transocean are currently involved in the business activities that
fall within the TODCO business as defined in the master separation agreement.
(See "Relationship Between Us and Transocean -- Master Separation Agreement.")
In August 2001, we sold, in separate transactions, the drilling units Jack
Bates, Deepwater Millennium, Deepwater Expedition, Peregrine I, Deepwater
Horizon, C. Kirk Rhein, Falcon 100, Deepwater Navigator and Deepwater
Discoveryto Transocean for net proceeds of $1,615.0 million. The sale prices for
these units were determined by Transocean based on appraisals by R. S. Platou
(U.S.A.) Inc., a third party valuation firm. In consideration for the sales of
these drilling units, $1,190.0 million of debt we owed to Transocean was
cancelled. We incurred this debt in connection with the retirement of some of
our then-outstanding public debt. In addition, Transocean delivered to us
promissory notes due August 17, 2011 bearing interest at 5.72% payable annually
in an aggregate principal amount of $425.0 million. In December 2002, Transocean
repaid to us the $425.0 million aggregate principal amount of promissory notes
plus accrued and unpaid interest. At the time of the sales, each of the drilling
units was being utilized under a drilling contract between one of our
subsidiaries and a customer. These contracts were not transferred and we secured
the continued use of the drilling units for the purpose of performing these
contracts through charters or other arrangements. These charters or other
arrangements were terminated or transferred to Transocean prior to the closing
of the IPO.
In April 2002, we sold, in separate transactions, the drilling units Harvey
H. Ward and Roger W. Mowell to Transocean for an aggregate net price of $93.0
million. The sale prices for these units were determined by Transocean based on
appraisals by R. S. Platou (U.S.A.) Inc., a third party valuation firm. In
consideration for the sales of these drilling units, Transocean delivered to us
promissory notes due April 3, 2012 bearing interest at 5.5% payable annually in
an aggregate principal amount of $93.0 million. The notes can be prepaid at any
time at Transocean's option, without penalty. In December 2002, Transocean
repaid to us the $93.0 million aggregate principal amount of promissory notes
plus accrued and unpaid interest.
101
In July 2002, we distributed as an in-kind dividend for no consideration,
in separate transactions, the drilling units W. D. Kent, Charley Graves and J.W.
McLean to Transocean. Simultaneous with the distributions, we entered into a
demise party charter agreement with Transocean for each rig whereby Transocean
chartered the drilling units to us at a fixed daily rate aggregating $49,800.
Additionally, we entered into a master brokerage agreement with Transocean for
each drilling unit whereby we marketed that drilling unit in exchange for a fee
equal to 2% of the payment due Transocean under the demise charter. Both the
master brokerage agreements and the demise party charters were terminated on
September 30, 2002.
Also in July 2002, we sold, in separate transactions, the following
subsidiaries to Transocean, in exchange for total cash consideration of
approximately $1.1 million: (1) RB Mediterranean Ltd., which holds oil and gas
interests outside the United States, (2) RB Anton Ltd., which holds oil and gas
interests outside the United States, (3) RB Astrid Ltd., which holds oil and gas
interests outside the United States, and (4) PT RBF Offshore Drilling, which has
drilling operations in Indonesia. The sale prices for RB Mediterranean Ltd. and
PT RBF Offshore Drilling were determined by Transocean based on internal
valuations. The sale prices for RB Anton Ltd. and RB Astrid Ltd. were determined
by Transocean based on recommendations by Argonauta Exploration & Production
Services, a third party consulting firm that manages the assets held by those
entities.
Effective August 1, 2002, Transocean assumed sponsorship of specified
employee benefits plans, as more fully described in "-- Relationship Between Us
and Transocean -- Employee Matters Agreement."
In September 2002, we distributed as an in-kind dividend for no
consideration, in separate transactions, the stock of the following subsidiaries
to Transocean: (1) R&B Falcon Canada Co., which has drilling operations in
Canada, (2) Shore Services, LLC, which has shore base operations in Italy, (3)
R&B Falcon Inc., LLC, which has a branch in Saudi Arabia, (4) R&B Falcon (M)
Sdn. Bhd., which has drilling operations in Malaysia, (5) R&B Falcon
International Energy Services BV, which has drilling operations outside the
United States, (6) R&B Falcon BV, which has operations outside the United
States, (7) Transocean Offshore Drilling Services LLC, which owns the drilling
unit J. T. Angel, and (8) RBF Rig Corporation LLC, which owns the drilling unit
C. E. Thornton. Additionally, in September 2002, we distributed as an in-kind
dividend for no consideration, in separate transactions, the drilling units F.
G. McClintock, Peregrine III and Land Rig 34 as well as certain surplus
equipment to Transocean.
Also in September 2002, we sold the stock of R&B Falcon (Ireland) Limited,
which has drilling operations outside the United States, to Transocean for cash
consideration of approximately $1.4 million. The sale price was determined by
Transocean based on internal valuations.
In October 2002, we assigned our leasehold interest in the drilling unit M.
G. Hulme, Jr. to Transocean for no consideration. Additionally, we assigned the
drilling contract for the drilling unit Deepwater Horizon to Transocean for no
consideration in the same month.
In November 2002, we distributed as an in-kind dividend for no
consideration the drilling unit Randolph Yost to Transocean. Additionally, we
assigned the drilling contract for the drilling unit Deepwater Discovery to
Transocean for no consideration in the same month.
In December 2002, we distributed to Transocean as an in-kind dividend for
no consideration the stock of the following subsidiaries: (1) Falcon Atlantic
Ltd., which has operations outside the United States; and (2) R&B Falcon
Drilling do Brasil, Ltda., which has shore base operations in Brazil. Also in
December 2002, we transferred the drilling units D. R. Stewart and George H.
Galloway to Transocean for no consideration and we assigned our rights and
obligations under a rig sharing agreement for the drilling unit Deepwater
Millenium to Transocean for no consideration.
Also in December 2002, we assigned the drilling contracts for the drilling
units Deepwater Navigator and Peregrine I to Transocean for no consideration.
In January 2003, we assigned to Transocean for no consideration a 12.5%
undivided interest in an aircraft at net book value of $1.0 million. The
transaction was recorded as a decrease to additional paid-in capital.
102
Also in January 2003, we distributed to Transocean as an in-kind dividend
for no consideration some accounts receivable balances from related parties in
the amount of $200.9 million. The transaction was recorded as a decrease to
additional paid-in capital.
In February 2003, we distributed to Transocean for no consideration the
stock of our subsidiaries R&B Falcon (A) Pty. Ltd., which owns the drilling unit
Ron Tappmeyer and Cliffs Drilling do Brasil Servicos de Petroleo S/C Ltda., a
dormant Brazilian entity. The aggregate net book value of $44.6 million for
these transfers was recorded as a decrease to additional paid-in capital.
In March 2003, we sold to Transocean the stock of Arcade Drilling AS, a
subsidiary that owns and operates the Paul B. Loyd, Jr. and owns the Henry
Goodrich, for net proceeds of $264.1 million and recorded a net pre-tax loss of
$11.0 million. The sales price was determined based on an appraisal by Professor
Terje Hansen of the Norwegian School of Economics and Business Administration,
taking into account the values of the drilling units provided by R.S. Platou
(U.S.A.) Inc. In consideration for the sale of the subsidiary, Transocean
cancelled $233.3 million principal amount of our 6.95% notes due April 2008. The
market value attributed to the notes, 113.21% of the principal amount, was
determined by Transocean based on available market information.
In March 2003, we assigned the drilling contract for the Deepwater Frontier
to Transocean for no consideration. Additionally, in March 2003, we distributed
to Transocean miscellaneous deepwater assets with a value of $1.4 million for no
consideration. The transactions were recorded as a decrease to additional
paid-in capital.
In May 2003, we sold to Transocean Cliffs Platform Rig 1 in consideration
for the cancellation of $13.9 million principal amount of the 6.95% Senior Notes
held by Transocean. The sales price was determined based on an appraisal by R.S.
Platou (U.S.A.) Inc. We recorded the excess of the sales price over the net book
value of the rig of $1.6 million as an increase to additional paid-in capital
and a pre-tax loss on the retirement of debt of $1.5 million.
In May 2003, we sold to Transocean our 50% interest in Deepwater Drilling
L.L.C. ("DD LLC"), which leases the drilling unit Deepwater Pathfinder, and our
60% interest in Deepwater Drilling II L.L.C. ("DDII LLC"), which leases the
Deepwater Frontier, in consideration for the cancellation of $43.7 million
principal amount of our debt held by Transocean. The value of our interests in
DD LLC and DDII LLC was determined by Transocean based on a similar third party
transaction. We recorded the excess of the sales price over the net book value
of the membership interests of $21.6 million as an increase to additional
paid-in capital in the year ended December 31, 2003.
In June 2003, we sold to Transocean our membership interests in our wholly
owned subsidiary, R&B Falcon Drilling (International & Deepwater) Inc. LLC,
which owns the following assets: (1) the drilling unit Jim Cunningham, (2) all
of the stock of R&B Falcon Deepwater (UK) Ltd., which has specified charter
rights with respect to the drilling unit Deepwater Nautilus, (3) all of the
stock of RBF Exploration LLC, which is the issuer of the Class A1 Notes due May
2005 and the Class A2 Notes, repurchased and retired in May 2003, related to the
drilling unit Deepwater Nautilus, (4) several dormant or near dormant
subsidiaries, and (5) other miscellaneous assets. As consideration for the stock
sold, Transocean cancelled $238.8 million of our outstanding debt held by
Transocean. The sales transaction was based on a valuation by Transocean which
takes into account the valuations of the drilling units provided by R.S. Platou
(U.S.A.) Inc. We recorded the excess of the net book value over the sales price
of our membership interests of $60.9 million as a loss on sale of assets and a
pre-tax loss on the retirement of debt of $48.0 million in 2003.
At the time of the transactions, some of the drilling units discussed above
were being utilized in connection with drilling contracts between our
subsidiaries and customers. These contracts were not transferred and we secured
the use of the drilling units for the purpose of performing these contracts
through charters or other arrangements. The costs of these charters or other
arrangements are included in discontinued operations and totaled $0.8 million,
$233.8 million and $96.8 million for the years ended December 31, 2003, 2002 and
the eleven months ended December 31, 2001, respectively.
103
At the closing of the IPO, we completed the following transactions:
- We assigned to Transocean for no consideration any other agreements
relating to drilling units and other assets not owned by us or our
subsidiaries upon the closing of the IPO.
- We assigned to Transocean the rights to any receivables outstanding upon
the closing of the IPO which were not related to the "TODCO business" as
that term is used in the master separation agreement. We will remit the
proceeds from those receivables as they are collected.
- We transferred to Transocean any remaining miscellaneous equipment and
other assets that did not relate to our business following the closing of
the IPO.
To the extent the transfer of legal title to any of the above assets could
not be completed prior to the closing of the IPO, beneficial ownership of such
assets was transferred to Transocean, and we or our applicable subsidiary held
such asset as agent for the other party until such time as legal title can be
transferred. See "-- Relationship Between Us and Transocean -- Master Separation
Agreement -- Transfer of Assets and Assignment of Liabilities."
In August 2003, Transocean made a payment to us of $11.4 million in order
for us to have the amount of cash and cash equivalents agreed to between us and
Transocean, as more fully described in "-- Relationship Between Us and
Transocean -- Master Separation Agreement -- Transfer of Assets and Assignment
of Liabilities."
In December 2003, Transocean made an equity contribution to us of $84.7
million in return for intercompany payable balances we owed to Transocean.
In February 2004, prior to the IPO, the Company exchanged $45,784,000,
$152,463,000 and $289,793,000 in principal amount of its outstanding 7.375%,
6.750% and 9.500% notes, respectively, held by Transocean for 3,940,406 shares
of the Company's Class B common stock. Immediately following this exchange, the
Company declared a dividend of 11.1447508 shares of its Class B common stock
with respect to each share of its Class B common stock outstanding immediately
following the exchange. As a result, 60,000,000 shares of the Company's Class B
common stock were issued and outstanding immediately prior to the IPO.
Transocean currently hold 46,200,000 shares of the Company's Class B common
stock. The Class B common stock is convertible at any time into shares of the
Company's Class A common stock on a share per share basis at the sole option of
Transocean. The stock for debt exchange was exempt from registration pursuant to
Section 4(2) of the Securities Act of 1933.
DEBT RETIREMENT AND DEBT EXCHANGE OFFERS
In March 2002, in conjunction with Transocean, we completed exchange offers
and consent solicitations for our 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. As a result of these exchange offers and consent solicitations,
Transocean exchanged approximately $234.5 million, $342.3 million, $247.8
million, $246.5 million, $76.9 million and $289.8 million principal amount of
our outstanding 6.50%, 6.75%, 6.95%, 7.375%, 9.125% and 9.50% notes,
respectively, for newly issued 6.50%, 6.75%, 6.95%, 7.375%, 9.125% and 9.50%
notes of Transocean having the same principal amount, interest rate, redemption
terms and payment and maturity dates. Approximately $38.8 million principal
amount of notes were not exchanged in the exchange offers and $33.8 million
principal amount of the notes remains outstanding. Because the holders of a
majority in principal amount of each of these series of notes consented to
amendments to the indentures under which the notes were issued, some covenants,
restrictions and events of default were eliminated from the indentures with
respect to these series of notes. In connection with the exchange offers, we
made an aggregate of $8.3 million in consent payments to holders of our notes.
At December 31, 2003 and December 31, 2002, $488.1 million and $936.6 million
principal amount of the notes, respectively, was outstanding to Transocean.
Interest expense related to these notes was $42.7 million for the year ended
December 31, 2003 and $77.9 million for the year ended December 31, 2002.
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In December 2002, we repurchased all of the approximately $234.5 million
and $76.9 million principal amount of the 6.50% and 9.125% notes payable to
Transocean, respectively, and approximately $189.8 million of the principal
amount of the 6.75% notes payable to Transocean plus accrued and unpaid
interest. We recorded a net after-tax loss of $12.2 million in conjunction with
the repurchase of these notes. We funded the repurchase from cash received from
Transocean's repurchase of approximately $518.0 million aggregate principal
amount of the notes receivable plus accrued and unpaid interest.
In March 2003, we acquired approximately $233.3 million principal amount of
the 6.95% notes due April 2008 in exchange for the stock of Arcade. See
"-- Asset Transfers to Transocean."
In April 2003, we repaid all of the $5.0 million principal amount of the
6.50% notes, plus accrued and unpaid interest, in accordance with their
scheduled maturities. We funded the repayment from a capital contribution
received from Transocean.
In May 2003, we repurchased and retired the entire $50.0 million principal
amount of the 9.41% Nautilus Class A2 Notes due May 2005. We recorded a pre-tax
loss on retirement of debt of approximately $5.5 million. We funded the
repurchases from a capital contribution received from Transocean as well as cash
on hand.
In May 2003, we acquired $13.9 million principal amount of the 6.95% notes
in exchange for the sale of Cliffs Platform Rig 1 to Transocean. We recorded a
pre-tax loss on retirement of debt of approximately $1.5 million. See "-- Asset
Transfers to Transocean."
In May 2003, we acquired $43.7 million principal amount of the 2.76% fixed
rate promissory note issued by us to Transocean, scheduled to mature on April 6,
2005 in exchange for the sale of our 50% interest in DD LLC and our 60% interest
in DDII LLC to Transocean. See "-- Asset Transfers to Transocean."
In June 2003, we acquired $200.7 million principal amount of the 7.375%
notes, the remaining $37.5 million principal amount of the 2.76% fixed rate
promissory note and $0.6 million principal amount of the 6.95% notes in exchange
for the sale to Transocean of our wholly owned subsidiary R&B Falcon Drilling
(International & Deepwater) Inc. LLC, which owns the following assets: (1) the
drilling unit Jim Cunningham, (2) all of the stock of R&B Falcon Deepwater (UK)
Ltd., which has specified charter rights with respect to the drilling unit
Deepwater Nautilus, (3) all of the stock of RBF Exploration LLC, which is the
issuer of the Class A1 Notes due May 2005 and the Class A2 Notes repurchased and
retired in May 2003, related to the drilling unit Deepwater Nautilus, (4)
several dormant or near dormant subsidiaries, and (5) other miscellaneous
assets. We recorded a pre-tax loss on retirement of debt of approximately $48.0
million. See "-- Asset Transfers to Transocean."
As described above, Transocean has exchanged a portion of the notes it
acquired in the exchange offer as consideration for the asset transfers
described in "-- Asset Transfers to Transocean." Prior to the closing of the
IPO, Transocean exchanged the balance of the notes for newly issued shares of
our Class B common stock. The determination of the number of shares issued was
based on a method that took into account the initial public offering price.
Prior to these retirement transactions, our outstanding common stock, which is
now held by Transocean, was reclassified into shares of Class B common stock.
Following the reclassification, the retirement transactions and a stock split,
Transocean held an aggregate of 60,000,000 shares of Class B common stock prior
to the closing of the IPO. A portion of these shares of Class B common stock was
sold and converted into shares of Class A common stock in the IPO.
REVOLVING CREDIT AGREEMENT
We were a party to a $1.8 billion two-year revolving credit agreement with
Transocean, dated April 6, 2001. Amounts outstanding under the revolver bore
interest payable quarterly at LIBOR plus 0.575% to 1.300% depending on our
senior unsecured public debt rating. In April 2001 we borrowed approximately
$1.3 billion under this credit agreement to retire some of our then-outstanding
public debt. For a description of the debt retirements, see "Third Party
Debt -- Redeemed and Repurchased Debt" in Note 7 to our consolidated financial
statements for the year ended December 31, 2002 included elsewhere in this
report. This line of credit expired April 6, 2003 and, as of that date, the
approximately $81.2 million then outstanding
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under the line was converted into the 2.76% fixed rate promissory note. This
note was cancelled in connection with the sale of some of the Transocean Assets
to Transocean, as described in "-- Asset Transfers to Transocean" above.
ADMINISTRATIVE SUPPORT SERVICES
Prior to June 30, 2003, Transocean provided administrative support services
to us. Transocean charged us a proportional share of its administrative costs
based on estimates of the percentage of work the relevant Transocean departments
performed for us. This arrangement was terminated prior to June 30, 2003.
Specified administrative support services are now provided by Transocean to us
under the transition services agreement. See "-- Relationship Between Us and
Transocean -- Transition Services Agreement."
PURCHASE OF MINORITY INTERESTS IN READING & BATES DEVELOPMENT CO.
In January 2001, prior to our merger transaction with Transocean, we
purchased for $34.7 million the minority interest of approximately 13.6% in
Reading & Bates Development Co. ("Devco"), which was owned by our former
directors and employees and directors and employees of Devco (including our
former directors Paul B. Loyd, Jr., a current director of Transocean, and
Charles A. Donabedian, a former director of Transocean). In connection with the
purchase, a $300,000 bonus was paid to our former director Richard A.
Pattarozzi, a current director of Transocean. The purchase price was based on a
valuation by a third party advisor.
RELATIONSHIP BETWEEN US AND TRANSOCEAN
We have provided below a summary description of the material terms and
conditions of a master separation agreement and several other important related
agreements between Transocean and us.
MASTER SEPARATION AGREEMENT
The master separation agreement between Transocean and us provides for the
completion of the separation of our assets and businesses from those of
Transocean. In addition, it contains several agreements governing the
relationship between us and Transocean following the IPO and specifies the
ancillary agreements that we and Transocean signed.
TODCO BUSINESS
The master separation agreement defines the TODCO business to mean the
following businesses and activities:
- contract drilling, workover, production and similar services for oil and
gas wells using jackup, submersible, barge (including workover) and
platform drilling rigs in the U.S. Gulf of Mexico and U.S. inland waters,
including maintenance and mobilization activities to the extent related
to rigs providing these services,
- contract drilling, workover, production and similar services for oil and
gas wells in and offshore Mexico, Trinidad, Colombia and Venezuela
(including the turnkey drilling services formerly provided by our
subsidiaries in Venezuela), including maintenance and mobilization
activities to the extent related to rigs providing these services,
- construction activities (including construction activities involving an
upgrade to, or modification of, a rig) in connection with rigs owned by
us or our subsidiaries after the closing of the IPO,
- office or yard facilities owned or used by us and our subsidiaries to the
extent related to the services and activities described in this
definition,
- our joint venture interest in Delta Towing Holdings, LLC, the operation
of the business transferred to Delta Towing prior to that transfer and
the notes issued in connection with that transfer,
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- our investment in Energy Virtual Partners, Inc. and Energy Virtual
Partners, LP,
- activities that were related primarily to the above activities at the
time those activities ceased, and
- any business conducted by TODCO or any of its subsidiaries after the
closing of the IPO.
The following businesses and activities are excluded from the definition of
the TODCO business to the extent they were conducted prior to the closing of the
IPO:
- contract drilling, workover, production or similar services for oil and
gas wells using semisubmersibles and drillships in the U.S. Gulf of
Mexico, including maintenance and mobilization activities to the extent
related to rigs providing these services,
- contract drilling, workover, production or 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, including
maintenance and mobilization activities to the extent related to rigs
providing these services and such services using land rigs,
- construction activities (including construction activities involving an
upgrade to, or modification of, a rig) in connection with rigs or other
assets owned by (1) Transocean or its subsidiaries (excluding us) after
the closing of the IPO or (2) neither Transocean nor us after the closing
of the IPO,
- oil and gas exploration and production activities (but not including our
ownership interest in Energy Virtual Partners),
- coal production activities, and
- the turnkey drilling business that we formerly operated in the U.S. Gulf
of Mexico and offshore Mexico, except that contract drilling services
provided to that business which otherwise fall within the definition of
TODCO business are not excluded.
TRANSFER OF ASSETS AND ASSIGNMENT OF LIABILITIES
We have transferred the stock of various subsidiaries and other assets to
Transocean and Transocean has assumed liabilities associated with the
transferred assets and businesses. See "-- Asset Transfers to Transocean." The
master separation agreement provides for any additional transfers of assets and
assumptions of liabilities necessary to effect the separation of the TODCO
business from the business of Transocean. The master separation agreement
provides that assets or liabilities that could not legally be transferred or
assumed prior to the closing of the IPO would be transferred or assumed as soon
as practicable following receipt of all necessary consents of third parties and
regulatory approvals. In any such case, the master separation agreement provides
that the party retaining the assets or liabilities will hold the assets in trust
for the use and benefit of, or retain the liabilities for the account of, the
party entitled to the assets or liabilities (at the expense of that party),
until the transfer or assumption can be completed. The party retaining these
assets or liabilities will also take any action reasonably requested by the
other party in order to place the other party in the same position as would have
existed if the transfer or assumption had been completed. We refer to all of
these transfers of assets and assumptions of liabilities together as the
"separation."
Except as set forth in the master separation agreement, no party is making
any representation or warranty as to the assets or liabilities transferred or
assumed as a part of the separation and all assets were and will be transferred
on an "as is, where is" basis. As a result, we and Transocean each have agreed
to bear the economic and legal risks that any conveyances of assets are
insufficient to vest good and marketable title to such assets in the party who
should have title under the master separation agreement.
The parties also agreed that for a period of one year following the IPO, if
Transocean determines in its good faith judgment that:
- any assets owned by us or our subsidiaries were used primarily during the
prior 12 months in Transocean's business, we will transfer those assets
to Transocean without additional consideration, or
107
- any assets owned by Transocean were used primarily during the prior 12
months in our business, Transocean will transfer those assets to us
without additional consideration.
All of the rigs listed in "Business -- Drilling Rig Fleet" are deemed to
have been used primarily in our business during the 12 months prior to the
closing of the IPO.
WORKING CAPITAL
The master separation agreement contains an acknowledgement that our cash
and cash equivalents as of June 30, 2003 were $25.0 million after giving effect
to a subsequent payment by Transocean to us of $11.4 million. The amount paid to
us by Transocean equals the difference between $25.0 million and the amount of
our cash and cash equivalents as of June 30, 2003 prior to giving effect to the
payment by Transocean. The master separation agreement provides that we will
retain all cash and cash equivalents generated by our business following June
30, 2003. Transocean will not be required to make any additional payments to us
for our working capital needs under the master separation agreement.
LETTERS OF CREDIT AND GUARANTEES
The master separation agreement requires that we and Transocean use our
reasonable best efforts to terminate (or have us or one of our subsidiaries
substituted for Transocean, or Transocean or one of its subsidiaries substituted
for us, as applicable) all existing guarantees by one party of obligations
relating to the business of the other party, including financial, performance
and other guarantee obligations. We have also agreed with Transocean that each
party will use its reasonable best efforts to have the other party substituted
under letters of credit or other surety instruments issued by third parties for
the account of either party or any of its subsidiaries issued on behalf of the
other party's business.
INDEMNIFICATION AND RELEASE
The master separation agreement provides for cross-indemnities that will
generally place financial responsibility on us and our subsidiaries for all
liabilities associated with the businesses and operations falling within the
definition of TODCO business, and that will generally place financial
responsibility for liabilities associated with all of Transocean's businesses
and operations with Transocean and its subsidiaries, regardless of the time
those liabilities arise. The master separation agreement also contains
indemnification provisions under which we and Transocean each indemnify the
other with respect to breaches of the master separation agreement or any
ancillary agreements. We have also agreed to indemnify Transocean against
liabilities arising from misstatements or omissions in this prospectus or the
registration statement of which it is a part, except for misstatements or
omissions relating to information regarding Transocean provided by Transocean in
writing for inclusion in this prospectus or the registration statement.
In connection with our separation from Transocean, the allocation of
liabilities related to taxes and employment matters will be governed separately
in a tax sharing agreement and an employee matters agreement. See "-- Tax
Sharing Agreement" and "-- Employee Matters Agreement."
Under the master separation agreement, we generally released Transocean and
its affiliates, agents, successors and assigns, and Transocean generally
released us and our affiliates, agents, successors and assigns, from any
liabilities between us or our subsidiaries on the one hand, and Transocean or
its subsidiaries on the other hand, arising from acts or events occurring on or
before the closing of the IPO, including acts or events occurring in connection
with the separation or the IPO. The general release does not apply to
obligations under the master separation agreement or any ancillary agreement or
to specified debt and other ongoing contractual arrangements.
Under the master separation agreement, we will be strictly liable to
Transocean for any misstatements or omissions in information supplied to
Transocean in connection with SEC filings and other public disclosures.
108
NONCOMPETITION AND OTHER COVENANTS
The master separation agreement includes provisions that restrict us from
competing with Transocean in specified business activities. These provisions do
not restrict us from engaging in any contract drilling, workover, production or
similar services for oil and gas wells using jackup, barge, platform or land
rigs in the following geographic locations: U.S. onshore, U.S. inland water,
U.S. Gulf of Mexico and offshore or onshore Mexico, Trinidad, Venezuela or
Colombia. However, except for the activities described in the foregoing
sentence, we are restricted from engaging in any contract drilling, workover,
production or similar services for oil and gas wells using any type of drilling
unit in the following geographic locations: offshore North America, offshore
South America, offshore Europe, offshore Africa, offshore Middle East, offshore
India, offshore Southeast Asia, offshore Asia, offshore Australia, the Gulf of
Mexico, the North Sea, the Mediterranean Sea, the Red Sea, the Persian Gulf and
the Caspian Sea. These provisions remain in effect so long as Transocean
beneficially owns at least a majority of the voting power of our outstanding
voting stock.
The master separation agreement required us to use reasonable commercial
efforts to satisfy the conditions precedent for the closing of the IPO. The
master separation agreement also includes provisions relating to a tax-free
distribution by Transocean of the remainder of our common stock it owns, but
does not obligate Transocean to effect such a distribution. If Transocean
chooses to conduct a tax-free distribution, we have agreed to take all action
reasonably requested by Transocean to facilitate that transaction at our own
expense.
The master separation agreement also contains provisions relating to the
exchange of information, provision of information for financial reporting
purposes, the preservation of legal privileges, dispute resolution, and
provision of corporate records.
Some of the rights granted to Transocean in the master separation agreement
would apply to and be binding upon any entity that acquires control of us.
INSURANCE
The master separation agreement provides that we will continue to be
covered under substantially all current insurance policies of Transocean (other
than employee welfare or benefit plan policies, which are addressed in the
employee matters agreement) and future insurance policies determined jointly by
us and Transocean. We have agreed to reimburse Transocean for premium expenses
related to those insurance policies. Transocean has agreed not to terminate our
coverage under the insurance policies unless it provides us prior notice.
However, we will cease to have coverage under Transocean's insurance policies
when Transocean ceases to own at least a majority of the voting power of our
outstanding voting stock, and no prior notice will be required in that case. In
no event will Transocean be liable to us in the event of the termination of any
insurance policy (unless in the case of termination by Transocean, Transocean
failed to provide us the notice required by the master separation agreement),
the failure of insurance policies to cover our liabilities or the nonrenewal of
insurance policies beyond their expiration dates as of the date of the master
separation agreement.
CORPORATE GOVERNANCE
The master separation agreement also contains several provisions regarding
our corporate governance that apply as long as Transocean owns specified
percentages of our common stock. As long as Transocean owns shares representing
a majority of the voting power of our outstanding voting stock, Transocean will
have the right to:
- nominate for designation by our board of directors, or a nominating
committee of the board, a majority of the members of the board, as well
as the chairman of the board, and
- designate at least a majority of the members of any committee of our
board of directors.
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If Transocean's beneficial ownership of our common stock is reduced to a
level of at least 10% but less than a majority of the voting power of our
outstanding voting stock, Transocean will have the right to:
- designate for nomination a number of directors proportionate to its
voting power, and
- designate one member of any committee of our board of directors.
In the master separation agreement, we have also agreed to use our best
efforts to cause Transocean's nominees to be elected.
The master separation agreement specified the form of our amended and
restated certificate of incorporation and bylaws to be in effect at the time of
the IPO. It also provides that for so long as Transocean beneficially owns
shares representing at least 15% of the voting power of our outstanding voting
stock, we will not, without the prior consent of Transocean, adopt any
amendments to our amended and restated certificate of incorporation or bylaws or
take any action to recommend to our stockholders certain actions which would,
among other things, limit the legal rights of Transocean, or deny any benefit to
Transocean or any of its subsidiaries as our stockholders in a manner not
applicable to our stockholders generally.
We have also agreed that for so long as Transocean and its subsidiaries own
50% or more of the voting power of our outstanding voting stock, we will
maintain the same accounting principles and practices as Transocean, and we will
not select a different accounting firm than Transocean's, which is currently
Ernst & Young LLP, to serve as our independent certified public accountants.
We have also agreed that for so long as Transocean owns at least a majority
of the voting power of all the outstanding shares of voting stock, we will not
take any action or enter into any commitment or agreement that could result in a
contravention or default by us or any of our affiliates, of or under any
provisions of applicable law, any provision of Transocean's memorandum of
association or articles of association or any credit agreement or other material
agreement by which Transocean is bound. Also, for so long as Transocean owns at
least a majority of the voting power of our outstanding voting stock, we will
not enter into any commitment or agreement that contains provisions triggering a
default or material payment when Transocean exercises its right to convert its
shares of our Class B common stock into shares of our Class A common stock or
otherwise disposes of its shares of our Class B common stock.
We have agreed to grant to Transocean a continuing right to purchase from
us, at the times set forth in the master separation agreement,
- such number of shares of our voting stock as is necessary to allow
Transocean to maintain its then-current percentage following the IPO, and
- 80% of the shares of each other class of capital stock that we issue.
These rights terminate if at any time Transocean owns less than 80% of the
voting power of our outstanding voting stock.
EXPENSES
Transocean has agreed to pay all out-of-pocket costs and expenses incurred
in connection with the separation, the IPO, the master separation agreement and
the ancillary agreements, except as otherwise provided in the master separation
agreement, the ancillary agreements or any other agreement between us and
Transocean relating to the separation and the IPO.
TAX SHARING AGREEMENT
Until the closing of our IPO, we were included in Transocean Holdings'
consolidated group for U.S. federal income tax purposes. As of the closing of
the IPO, we are not included in Transocean Holdings' U.S. federal consolidated
group because no U.S. subsidiary of Transocean owns at least 80% of the
aggregate voting power and value of our outstanding stock.
110
We have entered into a tax sharing agreement with Transocean Holdings which
governs Transocean Holdings' and our respective rights, responsibilities and
obligations with respect to taxes and tax benefits. References in this summary
description of the tax sharing agreement to the terms "tax" or "taxes" mean
taxes and any interest, penalties, additions to tax or additional amounts in
respect of such taxes. The general principles of the tax sharing agreement
include the following:
- Except for special tax items discussed in the bullet below, all 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 IPO generally will
be for the account of Transocean Holdings. Accordingly, we generally will
not be liable for any income taxes accruing on or before the closing of
the IPO, but we generally must pay Transocean Holdings for the amount of
any income tax benefits, calculated as described below, created on or
before the closing of the IPO ("pre-closing tax benefits") that we use or
absorb on a return with respect to a period after the closing of the IPO.
We will have no obligation to pay Transocean Holdings for any pre-closing
tax benefits arising out of or relating to the alternative minimum tax
provisions of Sections 55 through 59 of the U.S. Internal Revenue Code,
but we will be required to pay Transocean Holdings for any pre-closing
tax benefits we use that are alternative minimum tax credits described in
Section 53 of the Internal Revenue Code. Our obligation to pay Transocean
Holdings for the use of pre-closing tax benefits and our potential
obligation to pay alternative minimum tax to the Internal Revenue Service
may result in our paying more, in the aggregate, to the Internal Revenue
Service and to Transocean Holdings than we would otherwise have paid if
we had utilized no pre-closing tax benefits. For purposes of the tax
sharing agreement, deferred tax liabilities reflected in our financial
statements, which represent the anticipated future tax effects of
temporary differences between the financial statement basis and the tax
basis of our assets and liabilities, are not considered to constitute
income tax liabilities accrued on or before the closing of the IPO. As of
December 31, 2003, we had approximately $450 million of income tax
benefits subject to our obligation to reimburse Transocean Holdings. See
Note 12 to our consolidated financial statements included in Item 8 of
this report. The amount of these tax benefits will be calculated as
follows:
(1) in the case of a deduction used or absorbed, by multiplying the
deduction by the highest applicable statutory tax rate in effect,
and
(2) in the case of a credit used or absorbed, by allowing 100% of the
credit.
However, if the use or absorption of a pre-closing tax benefit defers or
precludes our use or absorption of any income tax benefit created after
the closing of the IPO ("post-closing tax benefit"), our payment
obligation with respect to the pre-closing tax benefit generally will be
deferred until we actually use or absorb such post-closing tax benefit.
This payment deferral will not apply with respect to, and we will have to
pay currently for the use or absorption of pre-closing tax benefits to the
extent of:
(1) up to 20% of any deferred or precluded post-closing tax benefit
arising out of our payment of foreign income taxes, and
(2) 100% of any deferred or precluded post-closing tax benefit arising
out of a carryback from a subsequent year.
If any person other than Transocean or its subsidiaries becomes the
beneficial owner of greater than 50% of the aggregate voting power of our
outstanding voting stock, we will be deemed to have used or absorbed all
pre-closing tax benefits, and we generally will be required to pay
Transocean Holdings an amount for the deemed use or absorption of these
pre-closing tax benefits. The amount paid for the deemed use of these tax
benefits will be calculated by:
(1) in the case of a deduction (including, for these purposes, all
pre-closing income taxes, whether claimed as a deduction or
credit), multiplying the deduction by the highest applicable
statutory tax rate in effect,
111
(2) in the case of a credit other than a pre-closing foreign tax
credit, allowing 100% of such credit, and
(3) multiplying the amounts by a specified discount factor.
The specified discount factor will vary depending on the year in which
another person becomes the beneficial owner of greater than 50% of the
voting power of our stock: if in 2003, 2004, 2007 or 2008, then the factor
is 0.80; if in 2005 or 2006, then the factor is 0.70; if in 2009, then the
factor is 0.85; if in 2010, then the factor is 0.90; if in 2011 or 2012,
then the factor is 0.95; and if in 2013 or a later year, then the factor
is 1.00). Moreover, if any of our subsidiaries that join with us in the
filing of consolidated returns ceases to join in the filing of such
returns, we will be deemed to have used that portion of the pre-closing
tax benefits attributable to that subsidiary following the cessation, and
we generally will be required to pay Transocean Holdings the amount of
this deemed tax benefit, calculated as described above with regard to an
acquisition of beneficial ownership, at the time such subsidiary ceases to
join in the filing of such returns. In the case of any of our payments to
Transocean resulting from another person becoming the owner of greater
than 50% of our voting stock or a subsidiary ceasing to join in the filing
of a consolidated return with us, the payment will in no case be deferred,
regardless of whether the existence of the related pre-closing tax benefit
would or could defer or preclude our use or absorption of any post-closing
tax benefit. Moreover, the payment will not be subsequently adjusted for
any difference between the tax benefits that we are deemed to use or
absorb in such case and the tax benefits that we actually use or absorb,
and the difference between those amounts could be substantial. Among other
considerations, applicable tax laws may, as a result of another person
becoming the owner of greater than 50% of our voting power, significantly
limit our use of such tax benefits, and these limitations are not taken
into account in determining the amount of the payment to Transocean. A
substantial portion of the pre-closing tax benefits are net operating
losses, most or all of which should be eligible to be carried forward at
least fourteen more years.
- We are responsible for all special tax items accruing on or after the
date on which we issued shares of our common stock to Transocean in
repayment of our notes, as described in "-- Debt Retirement and Debt
Exchange Offers." For this purpose, special tax items means taxes with
respect to items specified in U.S. Treasury regulation section
1.1502-76(b)(2)(ii)(C) (generally referring to transactions outside the
ordinary course of our business). However, special tax items do not
include taxes with respect to transactions to effect the separation of
the TODCO business from the business of Transocean. See "-- Master
Separation Agreement." Moreover, there were no special tax items that
accrued during the period beginning on the date of issuance of such
shares to Transocean and ending on the date of the closing of the IPO.
- If we and Transocean Holdings (or any affiliate of Transocean Holdings
other than us) are members of a U.S. federal consolidated group or state,
local or foreign combined group for any period after the closing of the
IPO, we will be responsible for all income taxes attributable to us for
that period, determined as if we had filed separate U.S. federal, state,
local or foreign income tax returns. We will be entitled to reimbursement
by Transocean Holdings for any income tax benefits realized by Transocean
Holdings or any of its affiliates as a result of our being a member of
any such consolidated or combined group. As indicated, however, we do not
expect that Transocean Holdings and we will be members of a U.S. federal
consolidated group or any state, local or combined group after the
closing of the IPO.
- We must pay Transocean Holdings for any tax benefits attributable to us
resulting from (1) the payment by Transocean Holdings, after the closing
of the IPO, of any additional taxes of the TODCO business that are not
U.S. federal income taxes or (2) the delivery by Transocean or its
subsidiaries, after the closing of the IPO, of stock of Transocean to an
employee of ours in connection with the exercise of an employee stock
option. We will generally be required to pay the deemed value of these
tax benefits within 30 days of the payment of such additional taxes or
the delivery of Transocean stock, whether or not we ever actually use or
absorb such tax benefits. Payments may be deferred with respect to any
item in excess of $1.0 million.
112
- Apart from (1) income taxes and income tax benefits that accrued on or
before the closing of the IPO and (2) tax benefits resulting from
Transocean's payment of our taxes that are not U.S. federal income taxes
or delivery of stock to our employees, described above, Transocean
Holdings will be responsible for all income taxes, and will be entitled
to all income tax benefits, attributable to Transocean Holdings or its
affiliates (other than us), and we will be responsible for all income
taxes, and will be entitled to all income tax benefits, attributable to
us.
- Our ability to obtain a refund from a carryback to a year in which we and
Transocean Holdings joined in a consolidated or combined return will be
at the discretion of Transocean Holdings. Moreover, any refund that we
may obtain will be net of any increase in taxes resulting from the
carryback that are otherwise for the account of Transocean Holdings.
- We will have the right to be notified of tax matters for which we are
responsible under the terms of the tax sharing agreement, although
Transocean Holdings will have sole authority to respond to and conduct
all tax proceedings, including tax audits, relating to any Transocean
Holdings consolidated, or Transocean combined, income tax returns in
which we are included.
- Transocean Holdings will have substantial control over our filing of tax
returns with respect to (1) any period in which Transocean or Transocean
Holdings possess greater than 50% of the voting power of all of our
outstanding stock or (2) any period after the closing of the IPO so long
as there remains a present or potential obligation for us to pay
Transocean Holdings for pre-closing tax benefits.
- We will also be responsible for all taxes, other than income taxes,
attributable to the TODCO business, whether accruing before, on or after
the closing of the IPO.
- We generally will be required to pay Transocean Holdings for the amount
of pre-closing tax benefits that we use in determining the amount of any
installment of estimated taxes we pay to Transocean Holdings or any tax
authority within thirty days after the installment of estimated taxes is
or would have been paid. If, after any installment payment of estimated
taxes or after the relevant return is due (with or without any
extensions), the estimated amount of pre-closing tax benefits for which
we have previously paid differs from the most recent estimate or actual
amount of pre-closing tax benefits that we use or absorb on that return,
we and Transocean Holdings must make appropriate true-up payments between
us. However, under some circumstances, payments by us for the use of
pre-closing tax benefits, whether estimated or actual, may be deferred
(subject to an interest charge) under a subordination agreement between
us and Transocean in favor of our third-party lenders.
The tax sharing agreement further provides for cooperation between
Transocean Holdings and us with respect to tax matters, the exchange of
information and the retention of records that may affect the income tax
liability of the parties to the agreement. However, if we fail to cooperate with
Transocean Holdings in any tax contest with respect to taxes that are otherwise
for the account of Transocean Holdings, any additional taxes resulting from such
tax contest will be for our account, notwithstanding any other provision in the
tax sharing agreement.
Notwithstanding the tax sharing agreement, under U.S. treasury regulations,
each member of a consolidated group is severally liable for the U.S. federal
income tax liability of each other member of the consolidated group.
Accordingly, with respect to periods in which we have been included in
Transocean Holdings' consolidated group, we could be liable to the U.S.
government for any U.S. federal income tax liability incurred, but not
discharged, by any other member of Transocean Holdings' consolidated group.
However, if any such liability were imposed, we would generally be entitled to
be indemnified by Transocean Holdings for tax liabilities allocated to
Transocean Holdings under the tax sharing agreement.
REGISTRATION RIGHTS AGREEMENT
Because our shares of common stock held by Transocean are deemed
"restricted securities" as defined in Rule 144, Transocean may only sell a
limited number of shares of our common stock into the public markets without
registration under the Securities Act. We entered into a registration rights
agreement with Transocean under which, at the request of Transocean, we would
use our best efforts to register shares of our common
113
stock that were held by Transocean after the closing of the IPO, or were
subsequently acquired, for public sale under the Securities Act. As long as
Transocean owns a majority of the voting power of our outstanding common stock,
there is no limit to the number of registrations that it may request. Once
Transocean owns less than a majority of the voting power of our outstanding
common stock, it can request a total of three additional registrations. If
Transocean sells more than 10% of our outstanding shares of common stock to a
transferee, Transocean may transfer all or a portion of its rights under the
agreement, except that a transferee that acquires a majority of our outstanding
common stock can only request two additional registrations after it owns less
than a majority of our outstanding common stock, and a transferee of less than a
majority of our outstanding common stock can only request either one or two
registrations, depending on the percentage of our outstanding common stock it
acquires. The transfer of rights under the agreement to a transferee does not
limit the number of registrations Transocean may request. We also provide
Transocean and its permitted transferees with "piggy-back" rights to include its
shares in future registrations of our common stock under the Securities Act.
There is no limit on the number of these "piggy-back" registrations in which
Transocean may request its shares be included. These rights will terminate once
Transocean or a permitted transferee is able to dispose of all of its shares of
our common stock within a three-month period pursuant to the exemption from
registration provided under Rule 144 of the Securities Act. We have agreed to
cooperate in these registrations and related offerings. We and Transocean have
agreed to restrictions on the ability of each party to sell securities following
registrations requested by either party.
TRANSITION SERVICES AGREEMENT
We entered into a transition services agreement with Transocean under which
Transocean provides specified administrative support during the transitional
period following the closing of the IPO. Transocean may provide specified
information technology and systems, financial reporting, accounting, human
resources, treasury and claims administration services to us in exchange for
agreed fees based on Transocean's actual costs. We are required to use specified
services so long as Transocean owns at least 50% of the voting power of our
outstanding shares of voting stock. Only in limited circumstances will
Transocean be liable to us with respect to the provision of services under the
transition services agreement.
EMPLOYEE MATTERS AGREEMENT
We entered into an agreement with Transocean and Transocean Holdings to
allocate specified assets, liabilities, and responsibilities relating to our
current and former employees and their participation in Transocean's benefit
plans.
Benefits under our U.S. pension plan ceased to accrue as of July 1, 1999.
As of August 1, 2001, our employees' existing accrued benefits under that plan
were fully vested. Sponsorship of that plan has been assumed by Transocean
Holdings effective August 1, 2002. Effective as of the date that we no longer
are a part of a controlled group of companies with Transocean for U.S. federal
income tax purposes, affected employees will be entitled to take a distribution
from that plan, subject to the provisions of the plan and to taxation and
possible early withdrawal penalties. We do not expect to establish a new pension
plan for our employees.
Our employees became eligible to participate in our U.S. savings plan
effective November 1, 2002. Our employees may make pre-tax contributions to that
plan. Employees who are not considered highly compensated for tax purposes may
also make post-tax contributions. We provide matching contributions of up to
3.0% of the compensation contributed to the plan by each employee as well as
additional discretionary matching of another 1.5% to a total 4.5% in matching
contributions. Additionally, the plan allows for a discretionary annual
contribution allocable to all eligible employees, subject to a two-year vesting
requirement. We have agreed that we will make discretionary matching
contributions of at least 0.5% of compensation for participating employees, and
an additional annual contribution of 1.5% of compensation for all eligible
employees (as defined in the plan) for so long as we are part of a controlled
group of companies with Transocean for U.S. federal income tax purposes. Prior
to November 1, 2002, our employees participated in the Transocean U.S. Savings
Plan, and we agreed to contribute 1.5% of compensation to that plan for our
eligible employees for the period beginning January 1, 2002 and ending October
31, 2002. On or about January 1, 2003, liabilities for our employees' accounts
under the Transocean U.S. Savings Plan, and assets associated with those
114
liabilities, were transferred to our U.S. savings plan. Our employees who have
invested in Transocean ordinary shares under the Transocean U.S. Savings Plan
may retain that investment, if they choose to do so, until December 31, 2005,
but will not be eligible to acquire additional Transocean ordinary shares under
our U.S. savings plan.
All of our eligible employees were entitled to continue to participate in
welfare benefit plans after the closing of the IPO which are substantially
comparable to those in which they presently participate. Transocean agreed to
use its best efforts to retain in place coverage under existing group life,
accidental death and long-term disability insurance policies for our employees
after the closing of the IPO until the earlier of the expiration of the policy
rate guarantees or the date that Transocean is no longer a majority owner of our
outstanding common stock. We will reimburse Transocean for the cost of that
coverage. Our employees are not eligible for retiree medical coverage.
Under the terms of the Transocean stock option awards granted prior to the
closing of the IPO, our employees will continue to retain outstanding options to
acquire Transocean ordinary shares for the duration of their original term.
With some exceptions, we have agreed to indemnify Transocean for employment
liabilities arising from any acts of our employees or from claims by our
employees against Transocean and for liabilities relating to benefits for our
employees. Transocean has agreed to similarly indemnify us.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
FEES PAID TO INDEPENDENT PUBLIC ACCOUNTANTS
Prior to the IPO in February 2004, the Company was an indirect wholly owned
subsidiary of Transocean and, as such, did not have an Audit Committee. The
audit and non-audit fees of the Company were reviewed and approved by the Audit
Committee of Transocean for purposes of considering whether such fees are
compatible with maintaining the auditor's independence. Additionally, in 2002,
the Company's audit and audit-related fees, including fees billed by Ernst &
Young LLP in connection with the Company's IPO were paid by Transocean.
The following are estimated fees billed for professional services rendered
by Ernst & Young LLP paid by the Company for 2003.
Audit Fees. Fees for services rendered by Ernst & Young LLP for the audit
of the financial statements of the Company were approximately $270,000 for 2003.
Specific services for the Company include fees related to the audit of the 2003
consolidated financial statements and assistance and review of documents filed
with the SEC billed directly to the Company.
Audit-Related Fees. Aggregate fees billed for all audit-related services
rendered by Ernst & Young LLP to the Company consisted of $30,874 of fees in
2003. Specific services for the Company include consultations regarding
accounting and reporting standards.
Tax Fees. Aggregate fees billed for permissible tax services rendered by
Ernst & Young LLP to the Company were $5,076 during 2003. Specific services
include state and local tax planning and compliance for the Company and
expatriate employees.
All Other Fees. There were no fees billed nor other services rendered by
Ernst & Young LLP to the Company in 2003.
Certain fees for professional services rendered in 2003 in connection with
the Company's registration statement on Form S-1 were billed directly to and
paid by Transocean. These fees include required historical audits of the annual
financial statements, a portion of the 2003 annual audit of the financial
statements, reviews of quarterly financial statements for inclusion in the Form
S-1, work done by tax professionals in connection with the audits and quarterly
reviews, consents, assistance with and review of other documents filed with the
SEC, and accounting and reporting consultations.
115
No fees for professional services were billed to the Company in 2002 except
for tax fees of $6,072. Specific tax services include state and local tax
planning and compliance for the Company and expatriate employees. All other
professional services for 2002 were billed directly to and paid by Transocean in
connection with the initial filing of the registration statement in 2002.
Subsequent to the IPO, our audit committee must pre-approve all audit and
non-audit services provided to the Company by its independent accountants. This
pre-approval authority has been delegated to the audit committee chairman and is
then reviewed by the entire audit committee at the committee's next meeting.
The Audit Committee has pre-approved the provision of the following
Non-Audit Services to the Company by its independent accountants for 2004:
Audit-Related Services. Financial statement audits of employee benefit
plans; agreed-upon or expanded audit procedures related to accounting and/or
billing records required to respond to or comply with financial, accounting or
regulatory reporting matters; internal control reviews and assistance with
internal control reporting requirements; consultations by the company's
management as to the accounting or disclosure treatment of transactions or
events and/or the actual or potential impact of final or proposed rules,
standards or interpretations by the SEC, FASB, or other regulatory or
standard-setting bodies not considered Audit services as applicable to the
financial statements Ernst & Young has been engaged to audit; subsidiary or
equity investee audits not required by statute or regulation that are
incremental to the audit of the consolidated financial statements; assistance
with implementation of the requirements of SEC rules or listing standards
promulgated pursuant to the Sarbanes-Oxley Act.
Tax Services. U.S. federal, state and local tax planning and advice; U.S.
federal, state and local tax compliance; international tax planning and advice;
international tax compliance; review of federal, state, local and international
income, franchise, and other tax returns; domestic and foreign tax planning,
compliance and advice; assistance with tax audits and appeals before the IRS and
similar state, local and foreign agencies; tax only valuation services,
including transfer pricing and cost segregation studies; tax advice and
assistance regarding statutory, regulatory or administrative developments;
expatriate tax planning, advice and compliance (including executive officers).
PART IV
ITEM 15. EXHIBITS, FINANCIAL STATEMENTS, SCHEDULES, & REPORTS ON FORM 8-K
FINANCIAL STATEMENTS
See Index to Consolidated Financial Statements on Page 46.
FINANCIAL STATEMENT SCHEDULES
See Index to Consolidated Financial Statements on Page 46.
EXHIBIT INDEX
EXHIBIT FILED HEREWITH OR INCORPORATED
NO. DESCRIPTION BY REFERENCE FROM:
------- ----------- ------------------------------
3.1 Third Amended and Restated Certificate of Filed herewith
Incorporation.
3.2 Amended and Restated By-Laws Filed herewith
3.4 Form of Certificate of Designation of Series A Included as Exhibit A to Exhibit 3.3
Junior Participating Preferred Stock (included as to Amendment 1 of Form S-1,
Exhibit A to Exhibit 3.3) Registration No. 333-101921, filed
February 12, 2003
116
EXHIBIT FILED HEREWITH OR INCORPORATED
NO. DESCRIPTION BY REFERENCE FROM:
------- ----------- ------------------------------
4.1 Rights Agreement by and between TODCO and The Bank Filed herewith
of New York, dated as of February 4, 2004
4.2 Specimen Stock Certificate. Exhibit 4.1 to Amendment 3 of
Form S-1, Registration No. 333-
The Company is a party to several debt instruments 101921, filed September 12, 2003
under
which the total amount of securities authorized does
not exceed 10% of the total assets of the Company
and its subsidiaries on a consolidated basis.
Pursuant to Paragraph 4(iii)(A) of Item 601(b) of
Regulation S-K, the Company agrees to furnish a copy
of such instruments to the Commission upon request
4.3 Omnibus Credit and Guaranty Agreement dated as of Exhibit 4.2 to Amendment 7 of Form
December 30, 2003 among TODCO, the guarantors, S-1, Registration No. 333-101921,
lenders and issuing bank parties thereto, Citibank filed January 21, 2004
N.A., as administrative agent and collateral agent,
and Citigroup Global Markets, Inc., as lead arranger
and sole book runner
10.1 Master Separation Agreement dated February 4, 2004 Exhibit 99.2 to Current Report of
by and among Transocean, Inc., Transocean Holdings Transocean Inc. on Form 8-K dated as
Inc., and TODCO February 10, 2004
10.2 Tax Sharing Agreement dated February 4, 2004 by and Exhibit 99.3 to Current Report of
between Transocean Holdings Inc. and TODCO Transocean Inc. on Form 8-K dated as
February 10, 2004
10.3 Transition Services Agreement dated February 4, 2004 Exhibit 99.4 to Current Report of
between Transocean Holdings Inc. and TODCO Transocean Inc. on Form 8-K dated as
of February 10, 2004
10.4 Employee Matters Agreement dated February 4, 2004 by Exhibit 99.5 to Current Report of
and among Transocean, Inc., Transocean Holdings Transocean Inc. on Form 8-K dated as
Inc., and TODCO. February 10, 2004
10.5 Registration Rights Agreement dated February 4, 2004 Exhibit 99.6 to Current Report of
between Transocean Inc. and TODCO Transocean Inc. on Form 8-K dated as
February 10, 2004
10.6 TODCO Long-Term Incentive Plan Exhibit 10.6 to Amendment 6 of Form
S-1, Registration No. 333-101921,
filed December 15, 2003
10.7 Employment Agreement dated July 15, 2002, between Exhibit 10.7 to Form S-1,
Jan Rask, R&B Falcon Management Services, Inc. and Registration No. 333-101921, filed
R&B Falcon Corporation December 18, 2002
10.8 Amendment No. 1 dated December 12, 2003 to the Exhibit 10.8 to Amendment 6 of Form
Employment Agreement dated July 15, 2002 between Jan S-1, Registration No. 333-101921,
Rask, R&B Falcon Management Services, Inc. and R&B filed December 15, 2003
Falcon Corporation
10.9 Employment Agreement dated July 18, 2002 between T. Exhibit 10.8 to Form S-1,
Scott O'Keefe, R&B Falcon Management Services, Inc. Registration No. 333-101921, filed
and R&B Falcon Corporation December 18, 2002
117
EXHIBIT FILED HEREWITH OR INCORPORATED
NO. DESCRIPTION BY REFERENCE FROM:
------- ----------- ------------------------------
10.10 Amendment No. 1 dated December 12, 2003 to the Exhibit 10.10 to Amendment 6 of Form
Employment Agreement dated July 18, 2002 between T. S-1, Registration No. 333-101921,
Scott O'Keefe, R&B Falcon Management Services, Inc. filed December 15, 2003
and R&B Falcon Corporation
10.11 Employment Agreement dated April 28, 2003 between Exhibit 10.9 to Amendment 3 of Form
David J. Crowley, TODCO Management Services, LLC and S-1, Registration No. 333-101921,
TODCO filed September 12, 2003
10.12 Form of Indemnification Agreement for Officers and Exhibit 10.10 to Amendment 3 of Form
Directors S-1, Registration No. 333-101921,
filed September 12, 2003
10.13 Revolving Credit and Note Purchase Agreement, dated Exhibit 10.9 to Form S-1,
as of December 20, 2001, among Delta Towing, LLC, as Registration No. 333-101921, filed
Borrower, R&B Falcon Drilling USA, Inc., as RBF December 18, 2002
Noteholder, and Beta Marine Services, L.L.C., as
Beta Noteholder
10.14 TODCO Severance Policy Exhibit 10.14 to Amendment 8 of Form
S-1, Registration No. 333-101921,
filed February 3, 2004
14.1 TODCO Code of Business Conduct and Ethics Filed herewith
21.1 Subsidiaries of Registrant Exhibit 21.1 to Amendment 1 of Form
S-1, Registration No. 333-101921,
filed February 12, 2003
23.1 Consent of Ernst & Young LLP Filed herewith
24.1 Power of Attorney Filed herewith
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Filed herewith
Executive Officer
31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Filed herewith
Financial Officer
32.1 Section 1350 Certification of Chief Executive Filed herewith
Officer and Chief Financial Officer
---------------
REPORTS ON FORM 8-K
No Form 8-K was filed in the last quarter of the fiscal year covered by
this report.
118
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 in Houston, Texas, on
this 17th day of March, 2004.
TODCO
/s/ JAN RASK
--------------------------------------
Jan Rask
President and Chief Executive Officer
Pursuant to the requirements of the Securities Act of 1934, this report has
been signed by the following persons in the capacities indicated on March 17,
2004.
SIGNATURE TITLE
--------- -----
/s/ JAN RASK President and Chief Executive Officer and Director
------------------------------------------------ (Principal Executive Officer)
Jan Rask
/s/ T. SCOTT O'KEEFE Senior Vice President and Chief Financial Officer
------------------------------------------------ (Principal Financial Officer)
T. Scott O'Keefe
/s/ DALE W. WILHELM Vice President and Controller (Principal
------------------------------------------------ Accounting Officer)
Dale W. Wilhelm
* Director
------------------------------------------------
Gregory L. Cauthen
* Director
------------------------------------------------
Thomas R. Hix
* Director
------------------------------------------------
Arthur Lindenauer
* Director
------------------------------------------------
Robert L. Long
* Director and Chairman of the Board
------------------------------------------------
J. Michael Talbert
*Signed through power of attorney
119
EXHIBIT INDEX
EXHIBIT FILED HEREWITH OR INCORPORATED
NO. DESCRIPTION BY REFERENCE FROM:
------- ----------- ------------------------------
3.1 Third Amended and Restated Certificate of Filed herewith
Incorporation.
3.2 Amended and Restated By-Laws Filed herewith
3.4 Form of Certificate of Designation of Series A Included as Exhibit A to Exhibit 3.3
Junior Participating Preferred Stock (included as to Amendment 1 of Form S-1,
Exhibit A to Exhibit 3.3). Registration No. 333-101921, filed
February 12, 2003
4.1 Rights Agreement by and between TODCO and The Bank Filed herewith
of New York, dated as of February 4, 2004.
4.2 Specimen Stock Certificate.
The Company is a party to several debt instruments Exhibit 4.1 to Amendment 3 of Form
under which the total amount of securities S-1, Registration No. 333-101921,
authorized does not exceed 10% of the total assets filed September 12, 2003
of the Company and its subsidiaries on a
consolidated basis. Pursuant to Paragraph 4(iii)(A)
of Item 601(b) of Regulation S-K, the Company agrees
to furnish a copy of such instruments to the
Commission upon request
4.3 Omnibus Credit and Guaranty Agreement dated as of Exhibit 4.2 to Amendment 7 of Form
December 30, 2003 among TODCO, the guarantors, S-1, Registration No. 333-101921,
lenders and issuing bank parties thereto, Citibank filed January 21, 2004
N.A., as administrative agent and collateral agent,
and Citigroup Global Markets, Inc., as lead arranger
and sole book runner.
10.1 Master Separation Agreement dated February 4, 2004 Exhibit 99.2 to Current Report of
by and among Transocean, Inc., Transocean Holdings Transocean Inc. on Form 8-K dated as
Inc., and TODCO. February 10, 2004
10.2 Tax Sharing Agreement dated February 4, 2004 by and Exhibit 99.3 to Current Report of
between Transocean Holdings Inc. and TODCO. Transocean Inc. on Form 8-K dated as
February 10, 2004
10.3 Transition Services Agreement dated February 4, 2004 Exhibit 99.4 to Current Report of
between Transocean Holdings Inc. and TODCO. Transocean Inc. on Form 8-K dated as
of February 10, 2004
10.4 Employee Matters Agreement dated February 4, 2004 by Exhibit 99.5 to Current Report of
and among Transocean, Inc., Transocean Holdings Transocean Inc. on Form 8-K dated as
Inc., and TODCO. February 10, 2004
10.5 Registration Rights Agreement dated February 4, 2004 Exhibit 99.6 to Current Report of
between Transocean Inc. and TODCO. Transocean Inc. on Form 8-K dated as
February 10, 2004
10.6 TODCO Long-Term Incentive Plan Exhibit 10.6 to Amendment 6 of Form
S-1, Registration No. 333-101921,
filed December 15, 2003
10.7 Employment Agreement dated July 15, 2002, between Exhibit 10.7 to Form S-1,
Jan Rask, R&B Falcon Management Services, Inc. and Registration No. 333-101921, filed
R&B Falcon Corporation. December 18, 2002
10.8 Amendment No. 1 dated December 12, 2003 to the Exhibit 10.8 to Amendment 6 of Form
Employment Agreement dated July 15, 2002 between Jan S-1, Registration No. 333-101921,
Rask, R&B Falcon Management Services, Inc. and R&B filed December 15, 2003
Falcon Corporation.
120
EXHIBIT FILED HEREWITH OR INCORPORATED
NO. DESCRIPTION BY REFERENCE FROM:
------- ----------- ------------------------------
10.9 Employment Agreement dated July 18, 2002 between T. Exhibit 10.8 to Form S-1,
Scott O'Keefe, R&B Falcon Management Services, Inc. Registration No. 333-101921, filed
and R&B Falcon Corporation. December 18, 2002
10.10 Amendment No. 1 dated December 12, 2003 to the Exhibit 10.10 to Amendment 6 of Form
Employment Agreement dated July 18, 2002 between T. S-1, Registration No. 333-101921,
Scott O'Keefe, R&B Falcon Management Services, Inc. filed December 15, 2003
and R&B Falcon Corporation.
10.11 Employment Agreement dated April 28, 2003 between Exhibit 10.9 to Amendment 3 of Form
David J. Crowley, TODCO Management Services, LLC and S-1, Registration No. 333-101921,
TODCO. filed September 12, 2003
10.12 Form of Indemnification Agreement for Officers and Exhibit 10.10 to Amendment 3 of Form
Directors. S-1, Registration No. 333-101921,
filed September 12, 2003
10.13 Revolving Credit and Note Purchase Agreement, dated Exhibit 10.9 to Form S-1,
as of December 20, 2001, among Delta Towing, LLC, as Registration No. 333-101921, filed
Borrower, R&B Falcon Drilling USA, Inc., as RBF December 18, 2002
Noteholder, and Beta Marine Services, L.L.C., as
Beta Noteholder.
10.14 TODCO Severance Policy. Exhibit 10.14 to Amendment 8 of Form
S-1, Registration No. 333-101921,
filed February 3, 2004
14.1 TODCO Code of Business Conduct and Ethics. Filed herewith
21.1 Subsidiaries of Registrant. Exhibit 21.1 to Amendment 1 of Form
S-1, Registration No. 333-101921,
filed February 12, 2003
23.1 Consent of Ernst & Young LLP Filed herewith
24.1 Power of Attorney Filed herewith
31.1 Rule 13a-14(a)/15d-14(a) Certification of Chief Filed herewith
Executive Officer
31.2 Rule 13a-14(a)/15d-14(a) Certification of Chief Filed herewith
Financial Officer
32.1 Section 1350 Certification of Chief Executive Filed herewith
Officer and Chief Financial Officer
121