-----BEGIN PRIVACY-ENHANCED MESSAGE-----
Proc-Type: 2001,MIC-CLEAR
Originator-Name: webmaster@www.sec.gov
Originator-Key-Asymmetric:
MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen
TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB
MIC-Info: RSA-MD5,RSA,
JgzlB8nnSrwTXj7ttezGPZwHr2e2hbhNAzTMzaAjo9dIt3HoqeWS5KweB5PUe7Xl
dch0x7ZIsfXmkLc8UaKugQ==
<SEC-DOCUMENT>0000950134-04-003628.txt : 20040317
<SEC-HEADER>0000950134-04-003628.hdr.sgml : 20040317
<ACCEPTANCE-DATETIME>20040316203357
ACCESSION NUMBER: 0000950134-04-003628
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 10
CONFORMED PERIOD OF REPORT: 20031231
FILED AS OF DATE: 20040317
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: TODCO
CENTRAL INDEX KEY: 0001210697
STANDARD INDUSTRIAL CLASSIFICATION: DRILLING OIL & GAS WELLS [1381]
IRS NUMBER: 760544217
STATE OF INCORPORATION: DE
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 001-31983
FILM NUMBER: 04674034
BUSINESS ADDRESS:
STREET 1: 2000 W. SAM HOUSTON PKWY S., SUITE 800
CITY: HOUSTON
STATE: TX
ZIP: 77042-3615
BUSINESS PHONE: 713-278-6000
</SEC-HEADER>
<DOCUMENT>
<TYPE>10-K
<SEQUENCE>1
<FILENAME>h13407e10vk.txt
<DESCRIPTION>TODCO - FISCAL YEAR ENDED DECEMBER 31, 2003
<TEXT>
<PAGE>
.
.
.
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
---------------------
FORM 10-K
<Table>
<C> <S>
(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
</Table>
COMMISSION FILE NUMBER 1-31983
---------------------
TODCO
(Exact name of registrant as specified in its charter)
<Table>
<S> <C>
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)
</Table>
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
<Table>
<Caption>
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
------------------- -----------------------------------------
<S> <C>
Class A common stock, par value $.01 per share New York Stock Exchange
Preferred stock purchase rights New York Stock Exchange
</Table>
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
<PAGE>
TABLE OF CONTENTS
<Table>
<Caption>
PAGE
NUMBER
------
<S> <C> <C>
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
</Table>
1
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
The following table contains information regarding our jackup rig fleet as
of March 1, 2004:
<Table>
<Caption>
ORIGINAL WATER DEPTH RATED DRILLING
YEAR ENTERED CAPACITY DEPTH
RIG TYPE(A) SERVICE (IN FEET) (IN FEET) LOCATION STATUS
- --- ------- ------------ ----------- -------------- --------- --------------
<S> <C> <C> <C> <C> <C> <C>
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
</Table>
- ---------------
(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
<PAGE>
The following table contains information regarding our barge drilling rig
fleet as of March 1, 2004:
<Table>
<Caption>
ORIGINAL RATED
YEAR ENTERED HORSEPOWER DRILLING DEPTH
RIG TYPE(A) SERVICE RATING (IN FEET) LOCATION STATUS
- --- ------- ------------ ---------- -------------- -------- --------------
<S> <C> <C> <C> <C> <C> <C>
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
</Table>
- ---------------
(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
<PAGE>
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:
<Table>
<Caption>
ORIGINAL RATED
YEAR ENTERED HORSEPOWER DRILLING DEPTH
RIG TYPE(A) SERVICE/UPGRADED RATING (IN FEET) LOCATION STATUS
- --- ------- ---------------- ---------- -------------- --------- --------------
<S> <C> <C> <C> <C> <C> <C>
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
</Table>
- ---------------
(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
<PAGE>
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
<PAGE>
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.
9
<PAGE>
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
<PAGE>
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
11
<PAGE>
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.
12
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<Table>
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)
<S> <C> <C> <C> <C> <C> <C>
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
</Table>
<Table>
PRE-TRANSOCEAN
MERGER POST-TRANSOCEAN MERGER
------------------- -----------------------------
AS OF DECEMBER 31, AS OF DECEMBER 31,
------------------- -----------------------------
1999 2000 2001 2002 2003
-------- -------- -------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C>
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
</Table>
- ---------------
(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
<PAGE>
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
<PAGE>
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
<PAGE>
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.
<Table>
<Caption>
THREE MONTHS ENDED
-----------------------------------------------------------------------------------------
DECEMBER 31, MARCH 31, JUNE 30, SEPTEMBER 30, DECEMBER 31, MARCH 31, JUNE 30,
2001 2002 2002 2002 2002 2003 2003
------------ --------- -------- ------------- ------------ --------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
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%
<Caption>
THREE MONTHS ENDED
----------------------------
SEPTEMBER 30, DECEMBER 31,
2003 2003
------------- ------------
<S> <C> <C>
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%
</Table>
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
<PAGE>
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 thereaft