================================================================================
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
______________________
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM ______ TO ______.
COMMISSION FILE NUMBER 333-75899
______________________
TRANSOCEAN INC.
(Exact name of registrant as specified in its charter)
______________________
CAYMAN ISLANDS 66-0582307
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
4 GREENWAY PLAZA
HOUSTON, TEXAS 77046
(Address of principal executive offices) (Zip Code)
Registrants' telephone number, including area code: (713) 232-7500
______________________
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
------- -------
Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes X No
------- -------
As of April 30, 2003, 319,773,020 ordinary shares, par value $0.01 per
share, were outstanding.
================================================================================
TRANSOCEAN INC.
INDEX TO FORM 10-Q
QUARTER ENDED MARCH 31, 2003
Page
----
PART I - FINANCIAL INFORMATION
- ----------------------------------
ITEM 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Operations
Three Months Ended March 31, 2003 and 2002 . . . . . . . 2
Condensed Consolidated Statements of Comprehensive Income (Loss)
Three Months Ended March 31, 2003 and 2002 . . . . . . . 3
Condensed Consolidated Balance Sheets
March 31, 2003 and December 31, 2002. . . . . . . . . . . 4
Condensed Consolidated Statements of Cash Flows
Three Months Ended March 31, 2003 and 2002 . . . . . . . 5
Notes to Condensed Consolidated Financial Statements. . . . . 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. . . . . . . . . . . . . .18
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk. .35
ITEM 4. Controls and Procedures . . . . . . . . . . . . . . . . . .36
PART II - OTHER INFORMATION
- -------------------------------
ITEM 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . .37
ITEM 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . .38
PART I - FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
The condensed consolidated financial statements of Transocean Inc. and its
consolidated subsidiaries (the "Company") included herein have been prepared,
without audit, pursuant to the rules and regulations of the Securities and
Exchange Commission. Certain information and notes normally included in
financial statements prepared in accordance with accounting principles generally
accepted in the United States have been condensed or omitted pursuant to such
rules and regulations. These financial statements should be read in conjunction
with the audited consolidated financial statements and the notes thereto
included in the Company's Annual Report on Form 10-K for the year ended December
31, 2002.
1
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(In millions, except per share data)
(Unaudited)
Three Months Ended March 31,
------------------------------
2003 2002
-------------- --------------
Operating Revenues
Contract drilling revenues $ 589.6 $ 667.9
Client reimbursable revenues 26.4 -
- ------------------------------------------------------------------------ -------------- --------------
616.0 667.9
- ------------------------------------------------------------------------ -------------- --------------
Costs and Expenses
Operating and maintenance 374.1 381.0
Depreciation 126.8 125.6
General and administrative 13.9 19.8
Impairment loss on long-lived assets 1.0 1.1
Gain from sale of assets, net (1.4) (1.9)
- ------------------------------------------------------------------------ -------------- --------------
514.4 525.6
- ------------------------------------------------------------------------ -------------- --------------
Operating Income 101.6 142.3
Other Income (Expense), net
Equity in earnings of joint ventures 3.6 1.9
Interest income 6.9 4.2
Interest expense (52.6) (55.9)
Other, net (0.6) (0.7)
- ------------------------------------------------------------------------ -------------- --------------
(42.7) (50.5)
- ------------------------------------------------------------------------ -------------- --------------
Income Before Income Taxes, Minority Interest and
Cumulative Effect of a Change in Accounting Principle 58.9 91.8
Income Tax Expense 11.8 13.8
Minority Interest (0.1) 0.7
- ------------------------------------------------------------------------ -------------- --------------
Net Income Before Cumulative Effect of a Change in Accounting Principle 47.2 77.3
Cumulative Effect of a Change in Accounting Principle - (1,363.7)
- ------------------------------------------------------------------------ -------------- --------------
Net Income (Loss) $ 47.2 $ (1,286.4)
======================================================================== ============== ==============
Basic Earnings (Loss) Per Share
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.15 $ 0.24
Loss on Cumulative Effect of a Change in Accounting Principle - (4.27)
- ------------------------------------------------------------------------ -------------- --------------
Net Income (Loss) $ 0.15 $ (4.03)
======================================================================== ============== ==============
Diluted Earnings (Loss) Per Share
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.15 $ 0.24
Loss on Cumulative Effect of a Change in Accounting Principle - (4.22)
- ------------------------------------------------------------------------ -------------- --------------
Net Income (Loss) $ 0.15 $ (3.98)
======================================================================== ============== ==============
Weighted Average Shares Outstanding
Basic 319.7 319.1
- ------------------------------------------------------------------------ -------------- --------------
Diluted 321.6 323.1
- ------------------------------------------------------------------------ -------------- --------------
Dividends Paid per Share $ - $ 0.03
- ------------------------------------------------------------------------ -------------- --------------
See accompanying notes.
2
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)
(Unaudited)
Three Months Ended March 31,
----------------------------
2003 2002
-------------- ------------
Net income (loss) $ 47.2 $ (1,286.4)
- -----------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Amortization of gain on terminated interest rate swaps - (0.1)
Change in unrealized loss on securities available for sale - 0.1
Change in share of unrealized loss in unconsolidated joint venture's
interest rate swaps (0.3) 3.1
Minimum pension liability adjustments 0.7 -
- -----------------------------------------------------------------------------------------------------
Other comprehensive income 0.4 3.1
- -----------------------------------------------------------------------------------------------------
Total comprehensive income (loss) $ 47.6 $ (1,283.3)
=====================================================================================================
See accompanying notes.
3
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
March 31, December 31,
2003 2002
----------- --------------
(Unaudited)
ASSETS
Cash and Cash Equivalents $ 1,520.4 $ 1,214.2
Accounts Receivable, net of allowance for doubtful accounts of $17.3
and $20.8 at March 31, 2003 and December 31, 2002, respectively 481.7 499.3
Materials and Supplies, net of allowance for obsolescence of $18.6
at March 31, 2003 and December 31, 2002 157.1 155.8
Deferred Income Taxes 17.1 21.9
Other Current Assets 53.7 20.5
- --------------------------------------------------------------------------------------------------
Total Current Assets 2,230.0 1,911.7
- --------------------------------------------------------------------------------------------------
Property and Equipment 10,201.6 10,198.0
Less Accumulated Depreciation 2,290.2 2,168.2
- --------------------------------------------------------------------------------------------------
Property and Equipment, net 7,911.4 8,029.8
- --------------------------------------------------------------------------------------------------
Goodwill, net 2,190.6 2,218.2
Investments in and Advances to Joint Ventures 110.7 108.5
Deferred Income Taxes 26.2 26.2
Other Assets 193.5 370.7
- --------------------------------------------------------------------------------------------------
Total Assets $ 12,662.4 $ 12,665.1
==================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts Payable $ 132.6 $ 134.1
Accrued Income Taxes 18.8 59.5
Debt Due Within One Year 1,051.7 1,048.1
Other Current Liabilities 295.2 262.2
- --------------------------------------------------------------------------------------------------
Total Current Liabilities 1,498.3 1,503.9
- --------------------------------------------------------------------------------------------------
Long-Term Debt 3,568.1 3,629.9
Deferred Income Taxes 102.4 107.2
Other Long-Term Liabilities 291.9 282.7
- --------------------------------------------------------------------------------------------------
Total Long-Term Liabilities 3,962.4 4,019.8
- --------------------------------------------------------------------------------------------------
Commitments and Contingencies
Preference Shares, $0.10 par value; 50,000,000 shares authorized,
none issued and outstanding - -
Ordinary Shares, $0.01 par value; 800,000,000 shares authorized,
319,768,212 and 319,219,072 shares issued and outstanding at
March 31, 2003 and December 31, 2002, respectively 3.2 3.2
Additional Paid-in Capital 10,635.8 10,623.1
Accumulated Other Comprehensive Loss (31.1) (31.5)
Retained Deficit (3,406.2) (3,453.4)
- --------------------------------------------------------------------------------------------------
Total Shareholders' Equity 7,201.7 7,141.4
- --------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 12,662.4 $ 12,665.1
==================================================================================================
See accompanying notes.
4
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
Three Months Ended March 31,
----------------------------
2003 2002
------------- -------------
Cash Flows from Operating Activities
Net income (loss) $ 47.2 $ (1286.4)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation 126.8 125.6
Impairment loss on goodwill - 1363.7
Stock-based compensation expense 1.5 0.2
Deferred income taxes 27.6 (23.3)
Equity in earnings of joint ventures (3.6) (1.9)
Net gain from disposal of assets (0.7) -
Impairment loss on long-lived assets 1.0 1.1
Amortization of debt-related discounts/premiums, fair value
adjustments and issue costs, net (1.8) 1.3
Deferred income, net 7.0 (5.4)
Deferred expenses, net (4.8) 7.4
Other, net 5.8 5.0
Changes in operating assets and liabilities
Accounts receivable 17.6 (8.9)
Accounts payable and other current liabilities 42.4 (4.6)
Income taxes receivable/payable, net (40.7) 15.8
Other current assets (34.5) (27.6)
- ------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 190.8 162.0
- ------------------------------------------------------------------------------------------------
Cash Flows from Investing Activities
Capital expenditures (24.4) (47.7)
Proceeds from disposal of assets, net 2.2 43.4
Joint ventures and other investments, net 1.4 (3.6)
- ------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (20.8) (7.9)
- ------------------------------------------------------------------------------------------------
Cash Flows from Financing Activities
Repayments under commercial paper program - (326.4)
Repayments on other debt instruments (47.8) (85.0)
Cash from termination of interest rate swaps 173.5 -
Net proceeds from issuance of ordinary shares under
stock-based compensation plans 10.9 9.1
Dividends paid - (9.6)
Financing costs - (8.2)
Other, net (0.4) 0.7
- ------------------------------------------------------------------------------------------------
Net Cash Provided by (Used in) Financing Activities 136.2 (419.4)
- ------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 306.2 (265.3)
- ------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Period 1,214.2 853.4
- ------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 1,520.4 $ 588.1
================================================================================================
See accompanying notes.
5
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 - PRINCIPLES OF CONSOLIDATION
Transocean Inc. (together with its subsidiaries and predecessors, unless
the context requires otherwise, the "Company") is a leading international
provider of offshore and inland marine contract drilling services for oil and
gas wells. As of March 31, 2003, the Company owned, had partial ownership
interests in or operated more than 170 mobile offshore and barge drilling units.
The Company contracts its drilling rigs, related equipment and work crews
primarily on a dayrate basis to drill oil and gas wells.
Intercompany transactions and accounts have been eliminated. The equity
method of accounting is used for investments in joint ventures where the
Company's ownership is between 20 and 50 percent and for investments in joint
ventures owned more than 50 percent where the Company does not have control of
the joint venture. The cost method of accounting is used for investments in
joint ventures where the Company's ownership is less than 20 percent and the
Company does not have control of the joint venture.
NOTE 2 - GENERAL
BASIS OF CONSOLIDATION - The accompanying condensed consolidated financial
statements of the Company have been prepared without audit in accordance with
accounting principles generally accepted in the United States ("U.S.") for
interim financial information and with the instructions to Form 10-Q and Article
10 of Regulation S-X of the Securities and Exchange Commission. Accordingly,
pursuant to such rules and regulations, these financial statements do not
include all disclosures required by accounting principles generally accepted in
the U.S. for complete financial statements. Operating results for the three
month period ended March 31, 2003 are not necessarily indicative of the results
that may be expected for the year ending December 31, 2003 or for any future
period. The accompanying condensed consolidated financial statements and notes
thereto should be read in conjunction with the audited consolidated financial
statements and notes thereto included in the Company's Annual Report on Form
10-K for the year ended December 31, 2002.
ACCOUNTING ESTIMATES - The preparation of financial statements in
conformity with accounting principles generally accepted in the U.S. requires
management to make estimates and assumptions that affect the reported amounts of
assets, liabilities, revenues, expenses and disclosure of contingent assets and
liabilities. On an ongoing basis, the Company evaluates its estimates, including
those related to bad debts, materials and supplies obsolescence, investments,
intangible assets and goodwill, property and equipment and other long-lived
assets, income taxes, financing operations, workers' insurance, pensions and
other post-retirement and employment benefits and contingent liabilities. The
Company bases its estimates on historical experience and on various other
assumptions that are believed to be reasonable under the circumstances, the
results of which form the basis for making judgments about the carrying values
of assets and liabilities that are not readily apparent from other sources.
Actual results could differ from such estimates.
SUPPLEMENTARY CASH FLOW INFORMATION - Cash payments for interest and income
taxes, net, were $14.8 million and $24.3 million, respectively, for the three
months ended March 31, 2003 and $8.8 million and $21.3 million, respectively,
for the three months ended March 31, 2002.
GOODWILL - In accordance with the Financial Accounting Standards Board's
("FASB") Statement of Financial Accounting Standards ("SFAS") 142, Goodwill and
Other Intangible Assets, goodwill is tested for impairment at the reporting unit
level, which is defined as an operating segment or a component of an operating
segment that constitutes a business for which financial information is available
and is regularly reviewed by management. Management has determined that the
Company's reporting units are the same as its operating segments for the purpose
of allocating goodwill and the subsequent testing of goodwill for impairment.
Goodwill resulting from the merger transaction with Sedco Forex Holdings Limited
was allocated 100 percent to the Company's International and U.S. Floater
Contract Drilling Services segment. Goodwill resulting from the merger
transaction (the "R&B Falcon merger") with R&B Falcon Corporation ("R&B Falcon",
now known as "TODCO") was allocated to the Company's two reporting units,
International and U.S. Floater Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water, at a ratio of
6
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
68 percent and 32 percent, respectively. The allocation was determined based on
the percentage of each reporting unit's assets at fair value to the total fair
value of assets acquired in the R&B Falcon merger. The fair value was determined
from a third party valuation.
During the first quarter of 2002, the Company implemented SFAS 142 and
performed the initial test of impairment of goodwill on its two reporting units.
The test was applied utilizing the estimated fair value of the reporting units
as of January 1, 2002 determined based on a combination of each reporting unit's
discounted cash flows and publicly traded company multiples and acquisition
multiples of comparable businesses. There was no goodwill impairment for the
International and U.S. Floater Contract Drilling Services reporting unit.
However, because of deterioration in market conditions that affected the Gulf of
Mexico Shallow and Inland Water business segment since the completion of the R&B
Falcon merger, a $1,363.7 million ($4.22 per diluted share) impairment of
goodwill was recognized as a cumulative effect of a change in accounting
principle in the first quarter of 2002.
During the fourth quarter of 2002, the Company performed its annual test of
goodwill impairment as of October 1. Due to a general decline in market
conditions, the Company recorded a non-cash impairment charge of $2,876.0
million ($9.01 per diluted share) of which $2,494.1 million and $381.9 million
related to the International and U.S. Floater Contract Drilling Services and
Gulf of Mexico Shallow and Inland Water reporting units, respectively.
The Company's goodwill balance, after giving effect to the goodwill
write-downs, was $2.2 billion as of March 31, 2003. The changes in the carrying
amount of goodwill as of March 31, 2003 are as follows (in millions):
Balance at Balance at
January 1, March 31,
2003 Other (a) 2003
----------- ------------ ---------
International and U.S. Floater Contract Drilling Services $ 2,218.2 $ (27.6) $2,190.6
_________________
(a) Represents favorable adjustments during 2003 of non-U.S. tax-related pre-acquisition
contingencies related to the R&B Falcon merger.
IMPAIRMENT OF OTHER LONG-LIVED ASSETS - The carrying value of long-lived
assets, principally property and equipment, is reviewed for potential impairment
when events or changes in circumstances indicate that the carrying amount of
such assets may not be recoverable. For property and equipment held for use, the
determination of recoverability is made based upon the estimated undiscounted
future net cash flows of the related asset or group of assets being evaluated.
Property and equipment held for sale are recorded at the lower of net book value
or net realizable value. See Note 6.
CAPITALIZED INTEREST - Interest costs for the construction and upgrade of
qualifying assets are capitalized. No interest was capitalized for the three
months ended March 31, 2003 and 2002.
INCOME TAXES - Income taxes have been provided based upon the tax laws and
rates in the countries in which operations are conducted and income is earned.
The income tax rates imposed by these taxing authorities vary substantially.
Taxable income may differ from pre-tax income for financial accounting purposes.
There is no expected relationship between the provision for income taxes and
income before income taxes because the countries have different taxation
regimes, which vary not only with respect to nominal rate but also in terms of
the availability of deductions, credits and other benefits. Variations also
arise because income earned and taxed in any particular country or countries may
fluctuate from period to period. These factors, combined with lower expected
financial results for the year, are expected to lead to a higher effective tax
rate.
7
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
COMPREHENSIVE INCOME - The components of accumulated other comprehensive
income (loss) as of March 31, 2003 and December 31, 2002 are as follows (in
millions):
Unrealized Other
Gain on Loss on Comprehensive
Terminated Available- Loss Related to Minimum Total Other
Interest Rate for-Sale Unconsolidated Pension Comprehensive
Swap Securities Joint Venture Liability Income (Loss)
--------------- ------------ ----------------- ----------- ---------------
Balance at December 31, 2002 $ 3.6 $ (0.6) $ (2.0) $ (32.5) $ (31.5)
Other comprehensive income (loss) - - (0.3) 0.7 0.4
--------------- ------------ ----------------- ----------- ---------------
Balance at March 31, 2003 $ 3.6 $ (0.6) $ (2.3) $ (31.8) $ (31.1)
=============== ============ ================= =========== ===============
SEGMENTS - The Company's operations are aggregated into two reportable
segments: (i) International and U.S. Floater Contract Drilling Services and (ii)
Gulf of Mexico Shallow and Inland Water. The Company provides services with
different types of drilling equipment in several geographic regions. The
location of the Company's operating assets and the allocation of resources to
build or upgrade drilling units is determined by the activities and needs of
clients. See Note 5.
INTERIM FINANCIAL INFORMATION - The condensed consolidated financial
statements reflect all adjustments, which are, in the opinion of management,
necessary for a fair statement of results of operations for the interim periods.
Such adjustments are considered to be of a normal recurring nature unless
otherwise identified.
STOCK-BASED COMPENSATION - Through December 31, 2002 and in accordance with
the provisions of SFAS 123, Accounting for Stock-Based Compensation, the Company
had elected to follow the Accounting Principles Board Opinion ("APB") 25,
Accounting for Stock Issued to Employees, and related interpretations in
accounting for its employee stock-based compensation plans. Effective January 1,
2003, the Company adopted the fair value method of accounting for stock-based
compensation using the prospective method of transition under SFAS 123.
8
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
If compensation expense for grants to employees under the incentive plan
and the stock purchase plan for the periods prior to December 31, 2002 were
recognized using the fair value method of accounting under SFAS 123 rather than
the intrinsic value method under APB 25, net income (loss) and earnings (loss)
per share would have been reduced to the pro forma amounts indicated below (in
millions, except per share data):
Three Months Ended
March 31,
------------------
2003 2002
------ ----------
Net Income (Loss) as Reported $47.2 $(1,286.4)
Add back: Stock-based compensation expense included in reported
net income (loss), net of related tax effects 1.2 0.2
Deduct: Total stock-based compensation expense determined under
fair value based method for all awards, net of related tax effects
Incentive Plan (4.6) (4.4)
Employee Stock Purchase Plan (0.9) (0.6)
------ ----------
Pro Forma net income (loss) $42.9 $(1,291.2)
====== ==========
Basic Earnings (Loss) Per Share
As Reported $0.15 $ (4.03)
Pro Forma 0.13 (4.05)
Diluted Earnings (Loss) Per Share
As Reported $0.15 $ (3.98)
Pro Forma 0.13 (4.00)
NEW ACCOUNTING PRONOUNCEMENTS - In January 2003, the FASB issued
Interpretation ("FIN") 46, Consolidation of Variable Interest Entities. FIN 46
requires companies with a variable interest in a variable interest entity to
apply this guidance to that entity as of the beginning of the first interim
period beginning after June 15, 2003 for existing interests and immediately for
new interests. The application of the guidance could result in the consolidation
of a variable interest entity. The Company is evaluating the impact of this
interpretation on its consolidated financial position and results of operations.
Effective January 2003, the Company implemented Emerging Issues Task Force
("EITF") Issue No. 99-19, Reporting Revenues Gross as a Principal versus Net as
an Agent. As a result of the implementation of the EITF, the costs incurred and
charged to the Company's clients on a reimbursable basis are recognized as
operating and maintenance expense. In addition, the amounts billed to the
Company's clients associated with these reimbursable costs are being recognized
as client reimbursable revenue. Management expects client reimbursable revenues
and operating and maintenance expense to be between $80 million and $100 million
as a result of the implementation of EITF 99-19. The change in accounting
principle will have no effect on the Company's results of operations or
consolidated financial position. Prior periods have not been reclassified, as
these amounts were not material.
RECLASSIFICATIONS - Certain reclassifications have been made to prior
period amounts to conform with the current period's presentation.
9
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 3 - DEBT
Debt, net of unamortized discounts, premiums and fair value adjustments, is
comprised of the following (in millions):
March 31, December 31,
2003 2002
---------- -------------
6.5% Senior Notes, due April 2003(a) $ 239.5 $ 239.7
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable
May 2003, May 2008 and May 2013) (a)(c) 531.0 527.2
9.125% Senior Notes, due December 2003 88.8 89.5
Amortizing Term Loan Agreement - Final Maturity December 2004 262.5 300.0
6.75% Senior Notes, due April 2005 (b) 367.5 371.8
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005 94.8 104.7
9.41% Nautilus Class A2 Notes, due May 2005(a) 51.5 51.7
6.95% Senior Notes, due April 2008 (b) 272.6 277.2
9.5% Senior Notes, due December 2008 (b) 365.5 371.8
6.625% Notes, due April 2011 (b) 805.5 803.7
7.375% Senior Notes, due April 2018 250.5 250.5
1.5% Convertible Debentures, due May 2021 (put options exercisable May 2006,
May 2011 and May 2016) 400.0 400.0
8% Debentures, due April 2027 198.0 198.0
7.45% Notes, due April 2027 (put options exercisable April 2007) 94.7 94.6
7.5% Notes, due April 2031 597.4 597.4
Other - 0.2
---------- -------------
Total Debt 4,619.8 4,678.0
Less Debt Due Within One Year (c) 1,051.7 1,048.1
---------- -------------
Total Long-Term Debt $ 3,568.1 $ 3,629.9
========== =============
_______________
(a) See Note 11.
(b) At December 31, 2002, the Company was a party to interest rate swap
agreements with respect to these debt instruments. See Note 4.
(c) The Zero Coupon Convertible Debentures are classified as debt due within
one year since the put options can be exercised in May 2003.
10
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
The scheduled maturity of the face value of the Company's debt assumes the
bondholders exercise their options to require the Company to repurchase the Zero
Coupon Convertible Debentures, 1.5% Convertible Debentures and 7.45% Notes in
May 2003, May 2006 and April 2007, respectively, and is as follows (in
millions):
Twelve
Months
Ending
March 31,
-------------
2004 $ 1,062.6
2005 158.0
2006 407.9
2007 400.0
2008 100.0
Thereafter 2,300.0
-------------
Total $ 4,428.5
=============
Commercial Paper Program - The Company has two revolving credit agreements,
described below, which provide liquidity for commercial paper borrowings. At
March 31, 2003, no amounts were outstanding under the Commercial Paper Program.
Revolving Credit Agreements - The Company is a party to two revolving
credit agreements, a $550.0 million five-year revolving credit agreement dated
December 29, 2000 and a $250.0 million 364-day revolving credit agreement dated
December 26, 2002. In addition to providing for commercial paper borrowings,
these credit lines may also be drawn on directly. At March 31, 2003, no amounts
were outstanding under either of these revolving credit agreements.
Term Loan Agreement - The Company is a party to an amortizing unsecured
five-year term loan agreement dated December 16, 1999. Amounts outstanding under
the Term Loan Agreement bear interest, at the Company's option, at a base rate
or London Interbank Offered Rate ("LIBOR") plus a margin that varies depending
on the Company's senior unsecured public debt rating. At March 31, 2003, the
margin was 0.70 percent per annum. The debt began to amortize in March 2002, at
a rate of $25.0 million per quarter in 2002. In 2003 and 2004, the debt
amortizes at a rate of $37.5 million per quarter. As of March 31, 2003, $262.5
million was outstanding under this agreement.
Exchange Offer - In March 2002, the Company completed exchange offers and
consent solicitations for TODCO's 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Senior Notes ("the Exchange Offer"). As a result of the Exchange Offer,
approximately $234.5 million, $342.3 million, $247.8 million, $246.5 million,
$76.9 million and $289.8 million principal amount of TODCO's outstanding 6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, were exchanged
for the Company's newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Senior Notes having the same principal amount, interest rate, redemption terms
and payment and maturity dates. Because the holders of a majority in principal
amount of each of these series of notes consented to the proposed amendments to
the applicable indenture pursuant to which the notes were issued, some
covenants, restrictions and events of default were eliminated from the
indentures with respect to these series of notes. After the Exchange Offer,
approximately $5.0 million, $7.7 million, $2.2 million, $3.5 million, $10.2
million and $10.2 million principal amount of the outstanding 6.5%, 6.75%,
6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, not exchanged remain
the obligation of TODCO. These notes are combined with the notes of the
corresponding series issued by the Company in the above table. In connection
with the Exchange Offer, TODCO paid $8.3 million in consent payments to holders
of TODCO's notes whose notes were exchanged. The consent payments are being
amortized as an increase to interest expense over the remaining term of the
respective notes and such amortization is expected to be approximately $1.1
million in 2003.
11
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 4 - INTEREST RATE SWAPS
In June 2001, the Company entered into interest rate swap agreements in the
aggregate notional amount of $700.0 million with a group of banks relating to
the Company's $700.0 million aggregate principal amount of 6.625% Notes due
April 2011. In February 2002, the Company entered into interest rate swap
agreements with a group of banks in the aggregate notional amount of $900.0
million relating to the Company's $350.0 million aggregate principal amount of
6.75% Senior Notes due April 2005, $250.0 million aggregate principal amount of
6.95% Senior Notes due April 2008 and $300.0 million aggregate principal amount
of 9.5% Senior Notes due December 2008. The objective of each transaction was to
protect the debt against changes in fair value due to changes in the benchmark
interest rate. Under each interest rate swap, the Company received the fixed
rate equal to the coupon of the hedged item and paid the floating rate (LIBOR)
plus a margin of 50 basis points, 246 basis points, 171 basis points and 413
basis points, respectively, which were designated as the respective benchmark
interest rates, on each of the interest payment dates until maturity of the
respective notes. The hedges were considered perfectly effective against changes
in the fair value of the debt due to changes in the benchmark interest rates
over their term. As a result, the shortcut method applied and there was no need
to periodically reassess the effectiveness of the hedges during the term of the
swaps.
In January 2003, the Company terminated the swaps with respect to its
6.75%, 6.95% and 9.5% Senior Notes. In March 2003, the Company terminated the
swaps with respect to its 6.625% Notes. As a result of these terminations, the
Company received cash proceeds, net of accrued interest, of approximately $173.5
million that was recognized as a fair value adjustment to long-term debt in the
Company's consolidated balance sheet and is being amortized as a reduction to
interest expense over the life of the underlying debt. Such amortization is
expected to be approximately $23.1 million ($0.07 per diluted share) in 2003.
Deepwater Drilling LLC, an unconsolidated subsidiary in which the Company
has a 50 percent ownership interest, has entered into interest rate swaps with
aggregate market values netting to a liability of $5.0 million at March 31,
2003. The Company's interest in these swaps was included in accumulated other
comprehensive income, net of tax, with corresponding reductions to deferred
income taxes and investments in and advances to joint ventures.
NOTE 5 - SEGMENTS
The Company's operations are aggregated into two reportable segments: (i)
International and U.S. Floater Contract Drilling Services and (ii) Gulf of
Mexico Shallow and Inland Water. The International and U.S. Floater Contract
Drilling Services segment consists of fifth-generation semisubmersibles and
drillships, other deepwater semisubmersibles and drillships, mid-water
semisubmersibles and drillships, non-U.S. jackup drilling rigs, other mobile
offshore drilling units and other assets used in support of offshore drilling
activities and offshore support services. The Gulf of Mexico Shallow and Inland
Water segment consists of jackup and submersible drilling rigs and inland
drilling barges located in the U.S. Gulf of Mexico and Trinidad, as well as land
and lake barge drilling units located in Venezuela. The Company provides
services with different types of drilling equipment in several geographic
regions. The location of the Company's rigs and the allocation of resources to
build or upgrade rigs is determined by the activities and needs of clients.
Accounting policies of the segments are the same as those described in Note 2.
The Company accounts for intersegment revenue and expenses as if the revenue or
expenses were to third parties at current market prices.
12
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Operating revenues and income before income taxes, minority interest and
cumulative effect of a change in accounting principle by segment are as follows
(in millions):
Three Months Ended
March 31,
----------------
2003 2002
------- -------
Operating Revenues
International and U.S. Floater Contract Drilling Services $562.7 $623.2
Gulf of Mexico Shallow and Inland Water 53.3 44.7
------- -------
Total Operating Revenues $616.0 $667.9
------- -------
Operating income before general and administrative expense
International and U.S. Floater Contract Drilling Services $144.0 $194.9
Gulf of Mexico Shallow and Inland Water (28.5) (32.8)
------- -------
115.5 162.1
Unallocated general and administrative expense (13.9) (19.8)
Unallocated other income (expense), net (42.7) (50.5)
------- -------
Income before Income Taxes, Minority Interest and
Cumulative Effect of a Change in Accounting Principle $ 58.9 $ 91.8
======= =======
Total assets by segment were as follows (in millions):
March 31, December 31,
2003 2002
---------- -------------
International and U.S. Floater Contract Drilling Services $ 11,820.5 $ 11,804.1
Gulf of Mexico Shallow and Inland Water 841.9 861.0
---------- -------------
Total Assets $ 12,662.4 $ 12,665.1
========== =============
NOTE 6 - ASSET DISPOSITIONS AND IMPAIRMENT LOSS
In January 2003, in the International and U.S. Floater Contract Drilling
Services segment, the Company completed the sale of a jackup rig, the RBF 160,
for net proceeds of $13.0 million and recognized a net after-tax gain of $0.2
million. The proceeds were received in December 2002.
During the three months ended March 31, 2003, the Company settled an
insurance claim and sold certain other assets for net proceeds of approximately
$2.2 million and recorded net after-tax gains of $1.2 million in the Company's
International and U.S. Floater Contract Drilling Services segment.
In March 2002, in the International and U.S. Floater Contract Drilling
Services segment, the Company sold two semisubmersible rigs, the Transocean 96
and Transocean 97, for net proceeds of $30.7 million and recognized net
after-tax gains of $1.3 million.
During the three months ended March 31, 2002, the Company settled an
insurance claim and sold certain other assets for net proceeds of approximately
$12.7 million and recorded net after-tax gains of $0.5 million in the Company's
International and U.S. Floater Contract Drilling Services segment and net
after-tax losses of $0.6 million in the Company's Gulf of Mexico Shallow and
Inland Water segment.
During the three months ended March 31, 2003, the Company recorded a
pre-tax non-cash impairment charge in the International and U.S. Floater
Contract Drilling Services segment of $1.0 million, which resulted from the
13
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Company's decision to discontinue its leases on its oil and gas properties. The
impairment was determined and measured based on the remaining book value of the
asset at the time the decision was made to discontinue the leases.
During the three months ended March 31, 2002, the Company recorded a
pre-tax non-cash impairment charge related to an asset held for sale in the Gulf
of Mexico Shallow and Inland Water segment of $1.1 million, which resulted from
deterioration in market conditions. The impairment was determined and measured
based on an estimate of fair value derived from an offer from a potential buyer.
NOTE 7 - EARNINGS PER SHARE
The reconciliation of the numerator and denominator used for the
computation of basic and diluted earnings per share is as follows (in millions,
except per share data):
Three Months Ended
March 31,
----------------------
2003 2002
---------- ----------
NUMERATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting Principle $ 47.2 $ 77.3
Cumulative Effect of a Change in Accounting Principle - (1,363.7)
---------- ----------
Net Income (Loss) $ 47.2 $(1,286.4)
========== ==========
DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share 319.7 319.1
Effect of dilutive securities:
Employee stock options and unvested stock grants 1.3 2.3
Warrants to purchase ordinary shares 0.6 1.7
---------- ----------
Adjusted weighted-average shares and assumed conversions for
diluted earnings per share 321.6 323.1
========== ==========
BASIC EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.15 $ 0.24
Cumulative Effect of a Change in Accounting Principle - (4.27)
---------- ----------
Net Income (Loss) $ 0.15 $ (4.03)
========== ==========
DILUTED EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.15 $ 0.24
Cumulative Effect of a Change in Accounting Principle - (4.22)
---------- ----------
Net Income (Loss) $ 0.15 $ (3.98)
========== ==========
Ordinary shares subject to issuance pursuant to the conversion features of
the convertible debentures are not included in the calculation of adjusted
weighted-average shares and assumed conversions for diluted earnings per share
because the effect of including those shares is anti-dilutive.
NOTE 8 - CONTINGENCIES
Legal Proceedings - In 1990 and 1991, two of the Company's subsidiaries
were served with various assessments collectively valued at approximately $7
million from the municipality of Rio de Janeiro, Brazil to collect a municipal
tax on services. The Company believes that neither subsidiary is liable for the
taxes and has contested the assessments in the Brazilian administrative and
court systems. The Brazil Supreme Court rejected the Company's appeal of an
adverse lower court's ruling with respect to a June 1991 assessment, which was
valued at approximately
14
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
$6 million. The Company plans to challenge the assessment in a separate
proceeding. The Company recently received a favorable ruling from the Brazil
Superior Court of Justice in connection with a disputed August 1990 assessment.
The Company is awaiting a ruling from the Taxpayer's Council in connection with
an October 1990 assessment. If the Company's defenses are ultimately
unsuccessful, the Company believes that the Brazilian government-controlled oil
company, Petrobras, has a contractual obligation to reimburse the Company for
municipal tax payments required to be paid by them. The Company does not expect
the liability, if any, resulting from these assessments to have a material
adverse effect on its business or consolidated financial position.
In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration and affiliates and Samuel Geary
and Associates Inc. against the Company, certain underwriters at Lloyd's (the
"Underwriters") and an insurance broker in the 16th Judicial District Court of
St. Mary Parish, Louisiana. The plaintiffs alleged damages amounting to in
excess of $50 million in connection with the drilling of a turnkey well in 1995
and 1996. The case was tried before a jury in January and February 2000, and the
jury returned a verdict of approximately $30 million in favor of the plaintiffs
for excess drilling costs, loss of insurance proceeds, loss of hydrocarbons,
expenses and interest. The Company and the Underwriters appealed such judgment,
and the Louisiana Court of Appeals reduced the amount for which the Company may
be responsible to less than $10 million. The plaintiffs requested that the
Supreme Court of Louisiana consider the matter and reinstate the original
verdict. The Company and the Underwriters also appealed to the Supreme Court of
Louisiana requesting that the Court reduce the verdict or, in the case of the
Underwriters, eliminate any liability for the verdict. Prior to the Supreme
Court of Louisiana ruling on all such petitions, the Company settled with the
St. Mary group of plaintiffs and the State of Louisiana. Thereafter, the Supreme
Court of Louisiana denied the applications for consideration by the remaining
plaintiffs but has not yet ruled on the Company's application or the application
of the Underwriters. The plaintiffs may seek rehearing of the decision. The
Company believes that any amounts, apart from a small deductible, paid in
settlement or which may ultimately be paid to the remaining plaintiffs are
covered by relevant primary and excess liability insurance policies. However,
the insurers and Underwriters have denied all coverage. The Company has
instituted litigation against those insurers and Underwriters to enforce its
rights under the relevant policies. While the Company cannot predict the outcome
of such litigation, it does not expect that the ultimate outcome of this case
will have a material adverse effect on its business or consolidated financial
position.
The Company has certain other actions or claims pending that have been
previously discussed and reported in the Company's Annual Report on Form 10-K
for the year ended December 31, 2002 and the Company's other reports filed with
the Securities and Exchange Commission. There have been no material developments
in these previously reported matters. The Company and its subsidiaries are
involved in a number of other lawsuits, all of which have arisen in the ordinary
course of the Company's business. The Company does not believe that ultimate
liability, if any, resulting from any such other pending litigation will have a
material adverse effect on its business or consolidated financial position.
Letters of Credit and Surety Bonds - The Company had letters of credit
outstanding at March 31, 2003 totaling $61.2 million. These letters of credit
guarantee various contract bidding and insurance activities under various lines
provided by several banks.
As is customary in the contract drilling business, the Company also has
various surety bonds totaling $138.8 million in place that secure customs
obligations relating to the importation of its rigs and certain performance and
other obligations.
NOTE 9 - RELATED PARTY TRANSACTIONS
Delta Towing - In January 2003, Delta Towing LLC ("Delta Towing") failed to
make its scheduled quarterly interest payment of $1.7 million on the notes
receivable. The Company signed a 90-day waiver of the terms requiring payment of
interest. As of March 31, 2003, payment had not been received. At March 31,
2003, the Company had interest receivable from Delta Towing of $2.9 million. See
Note 11.
15
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 10 - RESTRUCTURING CHARGES
In September 2002, the Company committed to a restructuring plan to close
its engineering office in Montrouge, France. The Company established a liability
of $2.8 million for the estimated severance-related costs associated with the
involuntary termination of 16 employees pursuant to this plan. The charge was
reported as operating and maintenance expense in the International and U.S.
Floater Contract Drilling Services segment in the Company's consolidated
statements of operations. Through March 31, 2003, $2.2 million had been paid to
15 employees whose positions were eliminated as a result of this plan. The
Company anticipates that substantially all amounts will be paid by the end of
the second quarter of 2003.
In September 2002, the Company committed to a restructuring plan for a
staff reduction in Norway as a result of a decline in activity in that region.
The Company established a liability of $1.2 million for the estimated
severance-related costs associated with the involuntary termination of six
employees pursuant to this plan. The charge was reported as operating and
maintenance expense in the International and U.S. Floater Contract Drilling
Services segment in the Company's consolidated statements of operations. Through
March 31, 2003, $0.7 million had been paid representing full or partial payments
to five employees whose positions are being eliminated as a result of this plan.
The Company anticipates that substantially all amounts will be paid by the end
of the first quarter of 2005.
In September 2002, the Company committed to a restructuring plan to
consolidate certain functions and offices utilized in its Gulf of Mexico Shallow
and Inland Water segment. The plan resulted in the closure of an administrative
office and warehouse in Louisiana and relocation of most of the operations and
administrative functions previously conducted at that location. The Company
established a liability of $1.2 million for the estimated severance-related
costs associated with the involuntary termination of 57 employees pursuant to
this plan. The charge was reported as operating and maintenance expense in the
Company's consolidated statements of operations. Through March 31, 2003, $1.1
million had been paid to 44 employees whose employment has been terminated as a
result of this plan. The Company anticipates that substantially all amounts will
be paid by the end of the second quarter of 2003.
NOTE 11 - SUBSEQUENT EVENTS
Debt Repayments - In April 2003, the Company repaid all of the $239.5
million principal amount outstanding 6.5% Senior Notes, plus accrued and unpaid
interest, in accordance with their scheduled maturities. The Company funded the
repayment from existing cash balances.
In May 2003, the Company intends to repurchase and retire the entire $50.0
million principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005.
The Company expects to record a pre-tax loss on retirement of debt of
approximately $6.0 million. The Company expects to fund the repurchases from
existing cash balances. No assurance can be given that the Company will be able
to complete this repurchase on the expected terms or otherwise.
Zero Coupon Convertible Debentures - On April 25, 2003, the Company
announced that holders of its Zero Coupon Convertible Debentures due May 24,
2020 have the option to require the Company to repurchase their debentures as of
May 24, 2003. Each holder of the debentures has the right to require the Company
to repurchase on May 24, 2003 all or any part of such holder's debentures at a
repurchase price of $628.57 per $1,000 principal amount. Under the terms of the
debentures, the Company has the option to pay for the debentures with cash, the
Company's ordinary shares, or a combination of cash and shares, and has elected
to pay for the debentures solely with cash. If all outstanding debentures are
surrendered for repurchase, the aggregate cash repurchase price will be
approximately $543.7 million. The Company expects that virtually all of the
holders of the Zero Coupon Convertible Debentures will exercise their put option
in May 2003 and, at that time, the Company would recognize additional expense of
approximately $11 million as a pre-tax loss on retirement of debt to fully
amortize the remaining debt issue costs related to these debentures. The Company
intends to pay the repurchase price from existing cash balances. The
16
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
debentures are convertible, at the option of the holder, into 8.1566 of the
Company's ordinary shares per $1,000 principal amount, subject to adjustment
under certain circumstances.
Delta Towing - In April 2003, Delta Towing failed to make its scheduled
quarterly interest payment. In April 2003, Delta Towing also failed to make a
quarterly interest payment originally due in January 2003 that was deferred to
April as a result of the 90-day waiver signed in January 2003. The Company
considers Delta Towing to be in default but believes that future cash flows will
result in payment of the recorded principal and interest ultimately being
received.
Nigeria Strike - In April 2003, members of the local branch of a Nigerian
union initiated a strike on four of the Company's rigs working there. The labor
strike began on April 16 on the semisubmersible M.G. Hulme, Jr. and on April 19
on the semisubmersible rig Sedco 709 and the jackup rigs Trident VI and Trident
VIII. The striking workers have now departed the rigs, and the Company is in the
process of returning all four of the rigs to service. The M.G. Hulme, Jr. has
resumed operations. The three remaining rigs are expected to resume operations
within the next week, although no assurance can be given that the Company will
be able to return the three rigs to service in that time frame. At full
dayrates, the four rigs were contracted at rates that would result in combined
revenue of approximately $342,000 per day. The rigs do not earn dayrates until
they return to service.
17
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
The following information should be read in conjunction with the audited
consolidated financial statements and the notes thereto included in the
Company's Annual Report on Form 10-K for the year ended December 31, 2002.
OVERVIEW
Transocean Inc. (together with its subsidiaries and predecessors, unless
the context requires otherwise, the "Company," "Transocean," "we, " "us" or
"our") is a leading international provider of offshore and inland marine
contract drilling services for oil and gas wells. As of April 30, 2003, we
owned, had partial ownership interests in or operated more than 170 mobile
offshore and barge drilling units. As of this date, our fleet included 13
fifth-generation semisubmersibles and drillships ("floaters"), 15 other
deepwater floaters, 32 mid-water floaters and 55 jackup drilling rigs. Our fleet
also included 35 drilling barges, five tenders, three submersible drilling rigs,
two platform drilling rigs, a mobile offshore production unit, and a land
drilling rig, as well as nine land rigs and three lake barges in Venezuela. We
contract our drilling rigs, related equipment and work crews primarily on a
dayrate basis to drill oil and gas wells. We also provide additional services,
including management of third-party well service activities.
We have reclassified our floaters into a deepwater category, consisting of
our fifth-generation floaters and other deepwater floaters, and a mid-water
category. We have also reviewed the use of the term "deepwater" in connection
with our fleet. The term as used in the drilling industry to denote a particular
segment of the market varies and continues to evolve with technological
improvements. We generally view the deepwater market sector as that which begins
in water depths of approximately 4,500 feet. Within our "deepwater" category, we
consider our "fifth-generation" rigs to be the semisubmersibles Deepwater
Horizon, Cajun Express, Deepwater Nautilus, Sedco Energy and Sedco Express and
the drillships Deepwater Discovery, Deepwater Expedition, Deepwater Frontier,
Deepwater Millennium, Deepwater Pathfinder, Discoverer Deep Seas, Discoverer
Enterprise and Discoverer Spirit. The floaters comprising the "other deepwater"
sub-category are those semisubmersible rigs and drillships which have a water
depth capacity of at least 4,500 feet. The mid-water category is comprised of
those floaters with a water depth capacity of less than 4,500 feet. We have
reclassified these rigs to better reflect how we view, and how we believe our
investors and the industry view, our fleet.
Our operations are aggregated into two reportable segments: (i)
International and U.S. Floater Contract Drilling Services and (ii) Gulf of
Mexico Shallow and Inland Water. The International and U.S. Floater Contract
Drilling Services segment consists of semisubmersibles and drillships, non-U.S.
jackups, other mobile offshore drilling units and other assets used in support
of offshore drilling activities and offshore support services. The Gulf of
Mexico Shallow and Inland Water segment consists of jackup and submersible
drilling rigs located in the U. S. Gulf of Mexico and Trinidad and U.S. inland
drilling barges, as well as land and lake barge drilling units located in
Venezuela. We provide services with different types of drilling equipment in
several geographic regions. The location of our rigs and the allocation of
resources to build or upgrade rigs is determined by the activities and needs of
our clients.
As a result of the implementation of Emerging Issues Task Force ("EITF")
Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent,
costs we incur that are charged to our clients on a reimbursable basis are being
recognized as operating and maintenance expense beginning in 2003. In addition,
the amounts billed to our clients associated with these reimbursable costs are
being recognized as operating revenue. We expect the increase in operating
revenues and operating and maintenance expense resulting from this
implementation to be between $80 million and $100 million for the year 2003.
This change in the accounting treatment for client reimbursables will have no
effect on our results of operations or consolidated financial position. We
previously recorded these charges and related reimbursements on a net basis in
operating and maintenance expense. Prior period amounts have not been
reclassified, as the amounts were not material.
In July 2002, we announced plans to pursue a divestiture of our Gulf of
Mexico Shallow and Inland Water business. In December 2002, our subsidiary,
TODCO, formerly known as R&B Falcon Corporation, filed a registration statement
with the Securities and Exchange Commission ("SEC") relating to our previously
announced initial public offering of our Gulf of Mexico Shallow and Inland Water
business. We expect to separate this business from Transocean and establish
TODCO as a publicly traded company. We are proceeding to reorganize TODCO as the
18
entity that owns that business in preparation of the offering. We continue with
our plan to transfer assets not used in this business from TODCO to our other
subsidiaries, and these internal transfers will not affect the consolidated
financial statements of Transocean. We expect to complete the initial public
offering when market conditions warrant, subject to various factors. Given the
current general uncertainty in the equity and U.S. natural gas drilling markets,
we are unsure when the transaction could be completed on terms acceptable to us.
We do not expect to sell all of our interest in TODCO in the initial public
offering. Until we complete the initial public offering transaction, we will
continue to operate and account for TODCO primarily as our Gulf of Mexico
Shallow and Inland Water segment.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of
operations are based upon our condensed consolidated financial statements. The
preparation of these financial statements requires us to make estimates and
judgments that affect the reported amounts of assets, liabilities, revenues,
expenses and related disclosure of contingent assets and liabilities. On an
on-going basis, we evaluate our estimates, including those related to bad debts,
materials and supplies obsolescence, investments, property and equipment,
intangible assets and goodwill, income taxes, financing operations, workers'
insurance, pensions and other post-retirement and employment benefits and
contingent liabilities. We base our estimates on historical experience and on
various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments about
the carrying values of assets and liabilities that are not readily apparent from
other sources. Actual results may differ from these estimates under different
assumptions or conditions.
We believe the following are our most critical accounting policies. These
policies require significant judgments and estimates used in the preparation of
our consolidated financial statements.
Allowance for doubtful accounts-We establish reserves for doubtful accounts
on a case-by-case basis when we believe the required payment of specific amounts
owed to us is unlikely to occur. We derive a majority of our revenue from
services to international oil companies and government-owned or
government-controlled oil companies. Our receivables are concentrated in certain
oil-producing countries. We generally do not require collateral or other
security to support client receivables. If the financial condition of our
clients was to deteriorate or their access to freely convertible currency was
restricted, resulting in impairment of their ability to make the required
payments, additional allowances may be required.
Valuation allowance for deferred tax assets-We record a valuation allowance
to reduce our deferred tax assets to the amount that is more likely than not to
be realized. While we have considered future taxable income and ongoing prudent
and feasible tax planning strategies in assessing the need for the valuation
allowance, should we determine that we would more likely than not be able to
realize our deferred tax assets in the future in excess of our net recorded
amount, an adjustment to the valuation allowance would increase income in the
period such determination was made. Likewise, should we determine that we would
more likely than not be able to realize all or part of our net deferred tax
asset in the future, an adjustment to the valuation allowance would reduce
income in the period such determination was made.
Goodwill impairment-We perform a test for impairment of our goodwill
annually as of October 1 as prescribed by Statement of Financial Accounting
Standards ("SFAS") 142, Goodwill and Other Intangibles. Because our business is
cyclical in nature, goodwill could be significantly impaired depending on when
the assessment is performed in the business cycle. The fair value of our
reporting units is based on a blend of estimated discounted cash flows, publicly
traded company multiples and acquisition multiples. Estimated discounted cash
flows are based on projected utilization and dayrates. Publicly traded company
multiples and acquisition multiples are derived from information on traded
shares and analysis of recent acquisitions in the marketplace, respectively, for
companies with operations similar to ours. Changes in the assumptions used in
the fair value calculation could result in an estimated reporting unit fair
value that is below the carrying value, which may give rise to an impairment of
goodwill. In addition to the annual review, we also test for impairment should
an event occur or circumstances change that may indicate a reduction in the fair
value of a reporting unit below its carrying value.
19
Property and equipment-Our property and equipment represents more than 60
percent of our total assets. We determine the carrying value of these assets
based on our property and equipment accounting policies, which incorporate our
estimates, assumptions and judgments relative to capitalized costs, useful lives
and salvage values of our rigs. We review our property and equipment for
impairment when events or changes in circumstances indicate that the carrying
value of such assets may be impaired or when reclassifications are made between
property and equipment and assets held for sale as prescribed by SFAS 144,
Accounting for Impairment or Disposal of Long-Lived Assets. Asset impairment
evaluations are based on estimated undiscounted cash flows for the assets being
evaluated. Our estimates, assumptions and judgments used in the application of
our property and equipment accounting policies reflect both historical
experience and expectations regarding future industry conditions and operations.
Using different estimates, assumptions and judgments, especially those involving
the useful lives of our rigs and expectations regarding future industry
conditions and operations, could result in different carrying values of assets
and results of operations.
Pension and Other Postretirement Benefits-Our defined benefit pension and
other postretirement benefit (retiree life insurance and medical benefits)
obligations and the related benefit costs are accounted for in accordance with
SFAS 87, Employers' Accounting for Pensions, and SFAS 106, Employers' Accounting
for Postretirement Benefits Other than Pensions. Pension and postretirement
costs and obligations are actuarially determined and are affected by assumptions
including expected return on plan assets, discount rates, compensation
increases, employee turnover rates and health care cost trend rates. We evaluate
our assumptions periodically and make adjustments to these assumptions and the
recorded liabilities as necessary.
Two of the most critical assumptions are the expected long-term rate of
return on plan assets and the assumed discount rate. We evaluate our assumptions
regarding the estimated long-term rate of return on plan assets based on
historical experience and future expectations on investment returns, which are
calculated by our third party investment advisor utilizing the asset allocation
classes held by the plan's portfolios. We utilize the Moody's Aa long-term
corporate bond yield as a basis for determining the discount rate for a majority
of our plans. Changes in these and other assumptions used in the actuarial
computations could impact our projected benefit obligations, pension
liabilities, pension expense and other comprehensive income. We base our
determination of pension expense on a market-related valuation of assets that
reduces year-to-year volatility. This market-related valuation recognizes
investment gains or losses over a five-year period from the year in which they
occur. Investment gains or losses for this purpose are the difference between
the expected return calculated using the market-related value of assets and the
actual return based on the market-related value of assets.
Contingent liabilities-We establish reserves for estimated loss
contingencies when we believe a loss is probable and the amount of the loss can
be reasonably estimated. Revisions to contingent liabilities are reflected in
income in the period in which different facts or information become known or
circumstances change that affect our previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
our assumptions and estimates regarding the probable outcome of the matter.
Should the outcome differ from our assumptions and estimates, revisions to the
estimated reserves for contingent liabilities would be required.
OPERATING RESULTS
THREE MONTHS ENDED MARCH 31, 2003 COMPARED TO THREE MONTHS ENDED MARCH 31,
2002
Our revenues and operating and maintenance expense decreased by $51.9
million and $6.9 million, respectively. In addition, our overall average
dayrate and utilization decreased from $72,500 and 61%, respectively, for the
quarter ended March 31, 2002 to $69,100 and 55%, respectively, for the quarter
ended March 31, 2003. These decreases were mainly attributable to a decline in
overall market conditions and resulted from a general uncertainty over world
economic and political events. Following is a detailed analysis of our
International and U.S. Floater Contract Drilling Services segment and Gulf of
Mexico Shallow and Inland Water segment operating results, as well as an
analysis of income and expense categories that we have not allocated to our two
segments.
20
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT
Three Months Ended
March 31,
--------------------
2003 2002 Change % Change
--------- --------- ---------- ---------
(In millions, except day amounts and % change)
Operating days (a) 5,882.3 6,883.9 (1,001.6) (14.5)%
Utilization (a) (b) (d) 68.8% 82.0% N/A (16.1)%
Average dayrate (a) (c) (d) $ 91,600 $ 90,100 $ 1,500 1.7%
Contract drilling revenues $ 541.1 $ 623.2 $ (82.1) (13.2)%
Client reimbursable revenues 21.6 - 21.6 N/M
--------- --------- ---------- ---------
562.7 623.2 (60.5) (9.7)%
Operating and maintenance 315.5 328.7 (13.2) (4.0)%
Depreciation 103.6 102.3 1.3 1.3%
Impairment loss on long-lived assets 1.0 - 1.0 N/M
Gain from sale of assets, net (1.4) (2.7) 1.3 (48.1)%
--------- --------- ---------- ---------
Operating income before general and administrative
expense $ 144.0 $ 194.9 $ (50.9) (26.1)%
========= ========= ========== =========
_______________
"N/A" means not applicable
"N/M" means not meaningful
(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days as a
percentage of the total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization has
changed to include all rigs based on contract drilling revenues. Prior periods have been
restated to reflect the change.
This segment's average dayrates and utilization (excluding rigs sold,
returned to owner or transferred between this segment and the Gulf of Mexico
Shallow and Inland Water segment) decreased from $92,600 and 82% to $92,300 and
68%, for the three months ended March 31, 2002 compared to the same period for
2003, respectively, which resulted in a decrease in operating revenues of $75.8
million. Additional decreases resulted from the sale of rigs ($6.5 million), a
leased rig returned to its owner ($1.4 million) and the transfer of a jackup rig
from this segment to the Gulf of Mexico Shallow and Inland Water segment during
and subsequent to the first quarter of 2002 ($2.1 million). These decreases
were partially offset by an increase in revenue from a rig transferred into this
segment from the Gulf of Mexico Shallow and Inland Water segment subsequent to
the first quarter of 2002 ($4.6 million).
Operating revenues for the three months ended March 31, 2003 included $21.6
million related to costs incurred and billed to clients on a reimbursable basis.
See "-Overview."
A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.
The decrease in this segment's operating and maintenance expenses was
primarily due to rigs stacked as a result of lower utilization ($18.1 million),
sold ($5.8 million), removed from our active fleet ($2.4 million) or returned to
owner ($1.4 million) during and subsequent to the first quarter of 2002. In
addition, we received $2.6 million in proceeds from an insurance claim recovery
in the first quarter of 2003. Partially offsetting the decreases were
additional costs incurred relating to client reimbursable expenses recognized as
operating and maintenance expense as
21
a result of implementing EITF 99-19 (see "-Overview"). We also incurred
additional expense resulting from the transfer of a jackup rig into this segment
from the Gulf of Mexico Shallow and Inland Water subsequent to the first quarter
of 2002 ($2.5 million).
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT
Three Months Ended
March 31,
--------------------
2003 2002 Change % Change
--------- --------- -------- ---------
(In millions, except day amounts and % change)
Operating days (a) 2,622.0 2,281.3 340.7 14.9%
Utilization (a) (b) (d) 38.3% 34.7% N/A 10.4%
Average dayrate (a) (c) (d) $ 18,500 $ 19,600 $(1,100) (5.6)%
Contract drilling revenues $ 48.5 $ 44.7 $ 3.8 8.5%
Client reimbursable revenues 4.8 - 4.8 N/M
--------- --------- -------- ---------
53.3 44.7 8.6 19.2%
Operating and maintenance 58.6 52.3 6.3 12.0%
Depreciation 23.2 23.3 (0.1) (0.4)%
Impairment loss on long-lived assets - 1.1 (1.1) N/M
Loss from sale of assets, net - 0.8 (0.8) N/M
--------- --------- -------- ---------
Operating loss before general and administrative
expense $ (28.5) $ (32.8) $ 4.3 13.1%
========= ========= ======== =========
_________________
"N/A" means not applicable
"N/M" means not meaningful
(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days as a
percentage of the total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue earning
day.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization was
changed to include all rigs based on contract drilling revenues. Prior periods have been
restated to reflect the change.
The increase in this segment's operating revenues was primarily due to
increased utilization from 34% for the three months ended March 31, 2002 to 38%
for the same period in 2003, excluding rigs transferred to the International and
U.S. Floater Contract Drilling Services segment or sold during and subsequent to
the first quarter of 2002, which resulted in an increase in revenue of $9.2
million. The increase was partially offset by decreased average dayrates from
$20,300 (excluding the effect of the transfer of a jackup rig from this segment
into the International and U.S. Floater Contract Drilling Services segment and
the sale of two mobile offshore production units) for the three months ended
March 31, 2002 to $18,500 for the same period in 2003, which resulted in a
decrease in revenue of $4.7 million.
Operating revenues for the three months ended March 31, 2003 included $4.8
million related to costs incurred and billed to clients on a reimbursable basis.
See "-Overview."
A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.
The increase in this segment's operating and maintenance expenses was
primarily due to an increase in activity resulting in increased personnel
expenses ($4.9 million). In addition, operating and maintenance expenses
increased
22
due to costs incurred relating to client reimbursable expenses recognized as
operating and maintenance expense as a result of implementing EITF 99-19 during
the three months ended March 31, 2003 (see "-Overview"). The increase in
miscellaneous and administrative expenses of $1.1 million related to an
insurance claim provision ($2.5 million) partially offset by a decrease in
provision for doubtful accounts ($1.3 million) upon collection of amounts
previously reserved. These increases were partially offset by lower expenses
resulting from a reduction in maintenance expenses ($2.5 million) and the
transfer of a jackup rig from this segment into the International and U.S.
Floater Contract Drilling Services segment ($0.8 million).
TOTAL COMPANY RESULTS OF OPERATIONS
Three Months Ended
March 31,
---------------------
2003 2002 Change % Change
---------- --------- -------- ---------
(In millions, except % change)
General and Administrative Expense $ 13.9 $ 19.8 $ (5.9) (29.8)%
Other (Income) Expense, net
Equity in earnings of joint ventures (3.6) (1.9) (1.7) 89.5%
Interest income (6.9) (4.2) (2.7) 64.3%
Interest expense 52.6 55.9 (3.3) (5.9)%
Other, net 0.6 0.7 (0.1) (14.3)%
Income Tax Expense 11.8 13.8 (2.0) (14.5)%
Cumulative Effect of a Change in Accounting Principle - (1,363.7) 1,363.7 N/M
_______________
"N/M" means not meaningful
The decrease in general and administrative expense was primarily
attributable to $3.9 million of costs related to the exchange of our notes for
TODCO's notes in March 2002 as more fully described in Note 3 to our condensed
consolidated financial statements. In addition, personnel expenses decreased
$1.0 million primarily due to lower pension expense in 2003 and a one-time
curtailment gain related to retiree life insurance.
The increase in equity in earnings of joint ventures was primarily related
to our 60 percent share of the earnings of Deepwater Drilling II L.L.C. ("DDII
LLC"), which owns the Deepwater Frontier, and our 50 percent share of Deepwater
Drilling L.L.C. ("DD LLC"), which owns the Deepwater Pathfinder. These rigs
experienced increased utilization and average dayrates in the first quarter of
2003 compared to the same period in 2002. Offsetting the increase in equity in
earnings of joint ventures was our 25 percent share of losses from Delta Towing
Holdings, L.L.C. The increase in interest income was primarily due to interest
earned on higher average cash balances for the three months ended March 31, 2003
compared to the same period in 2002. The decrease in interest expense was
attributable to reductions in interest expense of $1.4 million associated with
debt refinanced and retired during and subsequent to March 31, 2002. We also
received a refund of interest from a taxing authority that resulted in a
reduction in interest expense of $1.8 million. Additionally, in the first
quarter of 2003, we terminated our fixed to floating interest rate swaps, which
resulted in an increase in interest expense of $3.6 million as we paid fixed
interest rate on the underlying debt subsequent to the termination of the swaps.
Partially offsetting these increases was a decrease in interest expense of $3.5
million related to the amortization of the gain from the termination of the
interest rate swaps.
We operate internationally and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected relationship between the provision for income taxes and income before
income taxes.
During the three months ended March 31, 2002, we recognized a $1,363.7
million cumulative effect of a change in accounting principle in our Gulf of
Mexico Shallow and Inland Water segment related to the implementation of SFAS
142 as more fully described in Note 2 to our condensed consolidated financial
statements.
23
FINANCIAL CONDITION
March 31, December 31, %
2003 2002 Change Change
-------------------------------------------
(In millions)
TOTAL ASSETS
International and U.S. Floater Contract Drilling Services $ 11,820.5 $ 11,804.1 $ 16.4 0.1%
Gulf of Mexico Shallow and Inland Water 841.9 861.0 (19.1) (2.2)%
---------- ------------ -------- -------
$ 12,662.4 $ 12,665.1 $ (2.7) N/M
========== ============ ======== =======
_________________
"N/M" means not meaningful
The increase in International and U.S. Floater Contract Drilling Services
assets was due to an increase in temporary cash investments ($301.6 million).
This increase was partially offset by the sale of a jackup rig ($18.0 million
net book value), normal depreciation during 2003 ($103.6 million), a decrease in
accounts receivable due to lower activity and adjustments to goodwill during
2003 primarily resulting from the release of a pre-acquisition tax-related
contingency related to the merger with R&B Falcon Corporation. The decrease in
Gulf of Mexico Shallow and Inland Water assets was primarily due to normal
depreciation during 2003 ($23.2 million).
RESTRUCTURING CHARGES
In September 2002, we committed to a restructuring plan to eliminate our
engineering department located in Montrouge, France. We established a liability
of $2.8 million for the estimated severance-related costs associated with the
involuntary termination of 16 employees pursuant to this plan. The charge was
reported as operating and maintenance expense in the International and U.S.
Floater Contract Drilling Services segment in our consolidated statements of
operations. As of March 31, 2003, $2.2 million had been paid to 15 employees
whose positions were eliminated as a result of this plan. We anticipate that
substantially all amounts will be paid by the end of the second quarter of 2003.
In September 2002, we committed to a restructuring plan for a staff
reduction in Norway as a result of a decline in activity in that region. We
established a liability of $1.2 million for the estimated severance-related
costs associated with the involuntary termination of six employees pursuant to
this plan. The charge was reported as operating and maintenance expense in the
International and U.S. Floater Contract Drilling Services segment in our
consolidated statements of operations. As of March 31, 2003, $0.7 million had
been paid representing full or partial payments to five employees whose
positions have been eliminated as a result of this plan. We anticipate that
substantially all amounts will be paid by the end of the first quarter of 2005.
In September 2002, we committed to a restructuring plan to consolidate
certain functions and offices utilized in our Gulf of Mexico Shallow and Inland
Water segment. The plan resulted in the closure of an administrative office and
warehouse in Louisiana and relocation of most of the operations and
administrative functions previously conducted at that location. We established a
liability of $1.2 million for the estimated severance-related costs associated
with the involuntary termination of 57 employees pursuant to this plan. The
charge was reported as operating and maintenance expense in our consolidated
statements of operations. As of March 31, 2003, $1.1 million had been paid to 44
employees whose employment has been terminated as a result of this plan. We
anticipate that substantially all amounts will be paid by the end of the second
quarter of 2003.
OUTLOOK
Fleet utilization and average dayrates decreased within our International
and U.S. Floater Contract Drilling Services business segment during the first
quarter of 2003 compared with the fourth quarter of 2002. Fleet utilization
increased slightly and average dayrates decreased within our Gulf of Mexico
Shallow and Inland Water business segment during the first quarter of 2003
compared with the fourth quarter of 2002.
24
Comparative average dayrates and utilization figures are set forth in the
table below.
Three Months Ended
----------------------------------------
March 31, December 31, March 31,
2003 2002 2002
----------- -------------- -----------
AVERAGE DAYRATES (a)(b)(d)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation $ 183,800 $ 188,700 $ 185,800
Other Deepwater $ 113,600 $ 120,400 $ 120,800
Total Deepwater $ 147,500 $ 149,300 $ 148,100
Mid-Water $ 77,200 $ 84,400 $ 81,500
Jackups - Non-U.S. $ 56,900 $ 57,700 $ 58,700
Other Rigs $ 43,200 $ 36,200 $ 42,500
----------- -------------- -----------
Segment Total $ 91,600 $ 96,100 $ 90,100
----------- -------------- -----------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles $ 20,100 $ 21,900 $ 22,200
Inland Barges $ 17,600 $ 19,600 $ 19,200
Other Rigs $ 18,100 $ 18,700 $ 17,500
----------- -------------- -----------
Segment Total $ 18,500 $ 20,300 $ 19,600
----------- -------------- -----------
Total Mobile Offshore Drilling Fleet $ 69,100 $ 74,300 $ 72,500
=========== ============== ===========
UTILIZATION (a)(c)(d)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation 97% 96% 81%
Other Deepwater 76% 96% 82%
Total Deepwater 85% 96% 82%
Mid-Water 53% 57% 81%
Jackups - Non-U.S. 87% 83% 90%
Other Rigs 36% 48% 61%
----------- -------------- -----------
Segment Total 69% 74% 82%
----------- -------------- -----------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles 32% 33% 22%
Inland Barges 47% 44% 40%
Other Rigs 32% 29% 55%
----------- -------------- -----------
Segment Total 38% 37% 35%
----------- -------------- -----------
Total Mobile Offshore Drilling Fleet 55% 58% 61%
=========== ============== ===========
_________________
(a) Applicable to all rigs.
(b) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
(c) Utilization is defined as the total actual number of revenue earning days as a percentage of the
total number of calendar days in the period.
(d) Effective January 1, 2003, the calculation of average dayrates and utilization was changed to include
all rigs based on contract drilling revenues. Prior periods have been restated to reflect the change.
25
Commodity prices have continued at relatively strong levels so far during
2003. Crude oil prices have been driven in large part by the war with Iraq and
the political turmoil in Venezuela, although prices have softened somewhat in
recent weeks. The cold winter weather and lower inventory levels have similarly
continued to support strong U.S. natural gas prices.
However, demand for our drilling rigs is driven in part by our clients'
perception of future commodity prices, coupled with a number of associated
factors including the availability of drilling prospects, relative production
costs, the stage of reservoir development and political environments. It is
unclear why the current strong commodity prices have not translated into
increased drilling activity, and we do not see any significant indication that
activity will increase materially in the near-term other than some positive
signs in the U.S. Gulf of Mexico shallow and inland water market sectors.
We see mixed signals in the short-term outlook for our deepwater fleet.
There are opportunities in the short-term for deepwater rigs in India and the
Far East, although we are concerned about the existing oversupply in the U.S.
Gulf of Mexico. However, we remain optimistic about the longer-term deepwater
outlook. The number of large discoveries in West Africa combined with continuing
exploratory interest in that region and growing demand for deepwater rigs in
India and the Far East are positive developments supporting long-term deepwater
activity.
The non-U.S. jackup market sector remains strong, and we look for this
activity level to continue through 2003. Opportunities in Mexico and India are
contributing to an already relatively strong market sector.
The mid-water floater business remains extremely weak as this segment
continues to be significantly oversupplied globally. While there should be an
increase in activity for mid-water rigs in the North Sea due to seasonal summer
work, the outlook there and elsewhere appears poor beyond that point. We expect
the global mid-water sector to continue to be oversupplied throughout 2003.
The recovery in the U.S. Gulf of Mexico shallow and inland market segment
has been limited to date, although we believe there have been recent signs of
improvement. We believe dayrates for shallow water jackups could be in a
position to strengthen, and the demand for jackups in Mexico and India should
also continue to indirectly help this sector as rigs leave the U.S. Gulf of
Mexico for these countries. We have also seen indications that U.S. natural gas
prices will remain strong over the near-term.
The contract drilling market historically has been highly competitive and
cyclical, and we are unable to predict the extent to which current market
conditions will continue. A decline in oil or gas prices could further reduce
demand for our contract drilling services and adversely affect both utilization
and dayrates.
In April 2003, members of the local branch of a Nigerian union initiated a
strike on four of our rigs working there. The labor strike began on April 16 on
the semisubmersible M.G. Hulme, Jr. and on April 19 on the semisubmersible rig
Sedco 709 and the jackup rigs Trident VI and Trident VIII. The striking workers
have now departed the rigs, and we are in the process of returning all four of
the rigs to service. The M.G. Hulme, Jr. has resumed operations. The three
remaining rigs are expected to resume operations within the next week, although
no assurance can be given that we will be able to return the three rigs to
service in that time frame. At full dayrates, the four rigs were contracted at
rates that would result in combined revenue of approximately $342,000 per day.
The rigs do not earn dayrates until they return to service.
We have a 60 percent ownership interest in an unconsolidated joint venture,
DDII LLC, which owns the Deepwater Frontier. A subsidiary of ConocoPhillips
("ConocoPhillips") owns the remaining 40 percent interest in DDII LLC. We share
management of the joint venture equally with ConocoPhillips, and DDII LLC is a
lessee in a synthetic lease financing facility entered into in connection with
the construction of the Deepwater Frontier. Pursuant to the lease financing, the
rig is owned by a special purpose entity and leased to the joint venture. We do
not own, manage or control the special purpose entity.
26
We are in discussions with ConocoPhillips to purchase their interest in
DDII LLC. If we were to purchase the remaining 40 percent interest we do not
already own, we would consolidate DDII LLC as a subsidiary in our financial
statements. In this event, the value of the rig and the debt and equity
financing associated with the lease would be reflected on our balance sheet as a
result of the application of the Financial Accounting Standards Board's ("FASB")
Interpretation ("FIN") 46, Consolidation of Variable Interest Entities. We
expect the amount of the debt and equity financing to be reflected on our
balance sheet to be approximately $165 million. No assurance can be given that
we will be able to complete the purchase of ConocoPhillips' interest in DDII
LLC.
In May 2003, we intend to repurchase and retire the entire $50.0 million
principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005. We
expect to fund the repurchases from existing cash balances and to record a
pre-tax loss on retirement of debt of approximately $6.0 million. No assurance
can be given that we will be able to complete this repurchase on the expected
terms or otherwise.
Each holder of our Zero Coupon Convertible Debentures due May 24, 2020 has
the option to require us to repurchase all or any part of such holder's
debentures on May 24, 2003 at a price of $628.57 per $1,000 principal amount.
Under the terms of the debentures, we have the option to pay for the debentures
with cash, our ordinary shares, or a combination of cash and shares, and have
elected to pay for the repurchase of the debentures solely with cash. If all
outstanding debentures are surrendered for repurchase, the aggregate cash
repurchase price will be approximately $544.0 million. We expect that virtually
all of the holders of the Zero Coupon Convertible Debentures will exercise their
put option in May 2003. If all outstanding debentures are surrendered for
repurchase, we would recognize additional expense of approximately $11 million
as a pre-tax loss on retirement of debt to fully amortize the remaining debt
issue costs related to these debentures. We intend to pay the repurchase price
from existing cash balances. The debentures are convertible into 8.1566 shares
of our ordinary shares per $1,000 principal amount, subject to adjustment under
certain circumstances.
During the quarter ended March 31, 2003, we deferred costs primarily
related to mobilizations and contract preparation of $22.8 million and
recognized amortization expense of previously deferred mobilization and contract
preparation costs of $17.8 million. We expect to defer approximately $19.0
million in mobilization and contract preparation costs and to amortize to
expense approximately $27.0 million in the second quarter of 2003. Our
expectations are based upon certain of our rigs being awarded contracts for
which bids have been submitted and for those contracts that have been awarded to
begin at the contractual start date. We cannot provide any assurance that the
contracts under bid will be awarded to us or that awarded contracts will begin
when anticipated. As such, actual cost deferrals and amortizations could vary
from these estimates.
Our income tax returns are subject to review and examination in the various
jurisdictions in which we operate. The U.S. Internal Revenue Service is
currently auditing the years 1999, the year we became a Cayman Islands company,
and 2000. In addition, other tax authorities have examined the amounts of income
and expense subject to tax in their jurisdiction for prior periods. We are
currently contesting additional assessments, which have been asserted, and may
contest any future assessments. While the outcome of these assessments is not
presently known, we do not believe that the ultimate resolution of these
asserted income tax liabilities will have a material adverse effect on our
business or consolidated financial position.
As of April 29, 2003, approximately 58 percent and 27 percent of our
International and U.S. Floater Contract Drilling Services segment fleet days
were committed for the remainder of 2003 and for the year 2004, respectively.
For our Gulf of Mexico Shallow and Inland Water segment, which has traditionally
operated under short-term contracts, committed fleet days were approximately 5
percent for the remainder of 2003 and none are currently committed for the year
2004.
27
LIQUIDITY AND CAPITAL RESOURCES
SOURCES AND USES OF CASH
Three Months Ended
March 31,
-------------------
2003 2002 Change
------- ---------- ----------
(In millions)
NET CASH PROVIDED BY OPERATING ACTIVITIES
Net income (loss) $ 47.2 $(1,286.4) $ 1,333.6
Depreciation 126.8 125.6 1.2
Other non-cash items 32.0 1,348.1 (1,316.1)
Changes in working capital items (15.2) (25.3) 10.1
------- ---------- ----------
$190.8 $ 162.0 $ 28.8
======= ========== ==========
Cash generated from net income items adjusted for non-cash activity
increased $18.7 million. Cash provided by working capital items increased $10.1
million due to lower activity resulting in a reduction in accounts receivable
coupled with an increase in interest payable due to the termination of our
interest rate swaps in 2003 (see "-Derivative Instruments") partially offset by
a decrease in income tax payable and an increase in other current assets
resulting from prepayment of annual insurance premiums.
Three Months Ended
March 31,
----------------
2003 2002 Change
------- ------- --------
(In millions)
NET CASH USED IN INVESTING ACTIVITIES
Capital expenditures $(24.4) $(47.7) $ 23.3
Proceeds from disposal of assets 2.2 43.4 (41.2)
Other, net 1.4 (3.6) 5.0
------- ------- --------
$(20.8) $ (7.9) $ (12.9)
======= ======= ========
Net cash used in investing activities increased for the three months ended
March 31, 2003 as compared to the same period in the previous year as a result
of the reduction in proceeds from asset sales, which was partially offset by the
reduction in current quarter capital expenditures (see "-Capital Expenditures").
Three Months Ended
March 31,
------------------
2003 2002 Change
-------- -------- -------
(In millions)
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES
Repayments under commercial paper program $ - $(326.4) $326.4
Cash received from termination of interest rate swaps 173.5 - 173.5
Repayments of debt obligations (47.8) (85.0) 37.2
Other, net 10.5 (8.0) 18.5
-------- -------- -------
$ 136.2 $(419.4) $ 555.6
======== ======== =======
We repaid $326.4 million under our commercial paper program during the
quarter ended March 31, 2002 while no such payment was made for the same period
in 2003. For the first quarter of 2003, we received interest rate swap
termination proceeds of $173.5 million (see "-Derivative Instruments"). The
decrease in repayments of debt obligations of $37.2 million was due to early
repayment of secured rig financing on the Trident IX and Trident 16 of $50.6
million in 2002 partially offset by an increase in scheduled debt payments of
$13.4 million during the first quarter of 2003. The increase in cash provided in
other, net is due to $8.2 million in consent payments in March 2002 related to
the exchange of our notes for R&B Falcon notes as well as an increase of $2.2
million in proceeds from the
28
issuance of shares to the Employee Share Purchase Program. Additionally,
dividends of $9.6 million were paid in the first quarter of 2002. Payment of
dividends was discontinued after the second quarter of 2002.
CAPITAL EXPENDITURES
Capital expenditures totaled $24.4 million during the three months ended
March 31, 2003. During 2003, we expect to spend between $130.0 million and
$150.0 million on our existing fleet, corporate infrastructure and major
upgrades. A substantial majority of our expected capital expenditures in 2003
relates to the International and U.S. Floater Contract Drilling Services
segment.
We intend to fund the cash requirements relating to our capital
expenditures through available cash balances, cash generated from operations and
asset sales. We also have available borrowings under our revolving credit
agreements and commercial paper program (see "-Sources of Liquidity") and may
engage in other commercial bank or capital market financings.
ACQUISITIONS AND DISPOSITIONS
From time to time, we review possible acquisitions or dispositions of
businesses and drilling units and may in the future make significant capital
commitments for such purposes. Any such acquisition could involve the payment by
us of a substantial amount of cash or the issuance of a substantial number of
additional ordinary shares or other securities. We would likely fund the cash
portion of any such acquisition through cash balances on hand, the incurrence of
additional debt, sales of assets, ordinary shares or other securities or a
combination thereof. In addition, from time to time, we review possible
dispositions of drilling units.
In January 2003, in our International and U.S. Floater Contract Drilling
Services segment, we completed the sale of a jackup rig, the RBF 160, for net
proceeds of $13.0 million and recognized a net after-tax gain of $0.2 million.
The proceeds were received in December 2002.
During the three months ended March 31, 2003, we settled an insurance claim
and sold certain other assets for net proceeds of approximately $2.2 million and
recorded net after-tax gains of $1.2 million in our International and U.S.
Floater Contract Drilling Services segment.
We continue to proceed with our previously announced plans to pursue an
initial public offering of our Gulf of Mexico Shallow and Inland Water business.
Our plan is to separate this business from Transocean and establish it as a
publicly traded company. We are proceeding with our plans to reorganize TODCO as
the entity that owns this business in preparation of the offering. We expect to
complete the initial public offering when market conditions warrant, subject to
various factors. Given the current general uncertainty in the equity and U.S.
natural gas drilling markets, we are unsure when the transaction could be
completed on terms acceptable to us. See "-Overview."
SOURCES OF LIQUIDITY
Our primary sources of liquidity in the first quarter of 2003 were our cash
flows from operations and proceeds from the termination of our interest rate
swaps. Primary uses of cash were debt repayment and capital expenditures. At
March 31, 2003, we had $1,520.4 million in cash and cash equivalents.
We anticipate that we will rely primarily upon existing cash balances and
internally generated cash flows to maintain liquidity in 2003, as cash flows
from operations are expected to be positive and, together with existing cash
balances, adequate to fulfill anticipated obligations, including the potential
obligation to repurchase the Zero Coupon Convertible Debentures at the option of
the holders. See Notes 3 and 11 to our condensed consolidated financial
statements. From time to time, we may also use bank lines of credit and
commercial paper to maintain liquidity for short-term cash needs.
29
We intend to use the proceeds from the initial public offering of our Gulf
of Mexico Shallow and Inland Water business as well as any proceeds from asset
sales (see "-Acquisitions and Dispositions") to further reduce our debt
balances.
We intend to use cash from operations primarily to pay debt as it comes due
and to fund capital expenditures. If we seek to reduce our debt other than
through scheduled maturities, we could do so through repayment of bank
borrowings or through repurchases or redemptions of, or tender offers for, debt
securities. At March 31, 2003 and December 31, 2002, our total debt was
$4,619.8 million and $4,678.0 million, respectively. We have significantly
reduced capital expenditures compared to prior years due to the completion of
our newbuild program in 2001. During the first quarter of 2003, we reduced net
debt, defined as total debt less swap receivables and cash and cash equivalents,
by $183.1 million. The components of net debt at carrying value were as follows
(in millions):
March 31, December 31,
2003 2002
----------- --------------
Total Debt $ 4,619.8 $ 4,678.0
Less: Cash and cash equivalents (1,520.4) (1,214.2)
Swap receivables - (181.3)
We believe net debt provides useful information regarding the level of our
indebtedness by reflecting cash and investments that could be used to repay
debt. Net debt has been consistently reduced since 2001 due to the fact that
cash flows, primarily from operations and asset sales, have been greater than
that needed for capital expenditures.
Our internally generated cash flow is directly related to our business and
the market segments in which we operate. Should the drilling market deteriorate
further, or should we experience poor results in our operations, cash flow from
operations may be reduced. However, we have continued to generate positive cash
flow from operating activities over recent years.
We have access to $800 million in bank lines of credit under two revolving
credit agreements, a 364-day revolving credit agreement providing for $250
million in borrowings and expiring in December 2003 and a five-year revolving
credit agreement providing for $550 million in borrowings and expiring in
December 2005. These credit lines are used primarily to back our $800 million
commercial paper program and may also be drawn on directly. As of March 31,
2003, none of the credit line capacity was utilized.
The bank credit lines require compliance with various covenants and
provisions customary for agreements of this nature, including an interest
coverage ratio and leverage ratio, both as defined by the credit agreements, of
not less than three to one and not greater than 40 percent, respectively. In
calculating the leverage ratio, the credit agreements specifically exclude the
impact on total capital of all non-cash goodwill impairment charges recorded in
compliance with SFAS 142 (see Note 2 to our condensed consolidated financial
statements). Other provisions of the credit agreements include limitations on
creating liens, incurring debt, transactions with affiliates, sale/leaseback
transactions and mergers and sale of substantially all assets. Should we fail to
comply with these covenants, we would be in default and may lose access to these
facilities. A loss of the bank facilities would also cause us to lose access to
the commercial paper markets. We are also subject to various covenants under the
indentures pursuant to which our public debt was issued, including restrictions
on creating liens, engaging in sale/leaseback transactions and engaging in
merger, consolidation or reorganization transactions. A default under our public
debt could trigger a default under our credit lines and cause us to lose access
to these facilities. See Note 8 to our consolidated financial statements in our
Annual Report on Form 10-K for the year ended December 31, 2002 for a
description of our credit agreements and debt securities.
In April 2001, the Securities and Exchange Commission ("SEC") declared
effective our shelf registration statement on Form S-3 for the proposed offering
from time to time of up to $2.0 billion in gross proceeds of senior or
subordinated debt securities, preference shares, ordinary shares and warrants to
purchase debt securities, preference shares, ordinary shares or other
securities. At March 31, 2003, $1.6 billion in gross proceeds of securities
remained unissued under the shelf registration statement.
30
Our access to commercial paper, debt and equity markets may be reduced or
closed to us due to a variety of events, including, among others, downgrades of
ratings of our debt and commercial paper, industry conditions, general economic
conditions, market conditions and market perceptions of us and our industry.
Our contractual obligations in the table below include our debt obligations
at face value.
For the twelve months ending March 31,
---------------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
-------- ---------- ---------- ----------- ----------
(In millions)
CONTRACTUAL OBLIGATIONS
Debt $4,428.5 $ 1,062.6 $ 565.9 $ 500.0 $ 2,300.0
======== ========== ========== =========== ==========
The bondholders may, at their option, require us to repurchase the Zero
Coupon Convertible Debentures due 2020, the 1.5% Convertible Debentures due 2021
and the 7.45% Notes due 2027 in May 2003, May 2006 and April 2007, respectively.
With regard to both series of the Convertible Debentures, we have the option to
pay the repurchase price in cash, ordinary shares, or any combination of cash
and ordinary shares. We have elected to pay for the Zero Coupon Convertible
Debentures we repurchase in May 2003 with existing cash. The chart above assumes
that the holders of these Convertible Debentures and notes exercise the options
at the first available date. We expect virtually all of the holders of the Zero
Coupon Convertible Debentures will exercise their put option in May 2003 and, at
that time, we would recognize additional expense of approximately $11 million as
a loss on retirement of debt to fully amortize the remaining debt issue costs
related to these debentures. We are also required to repurchase the convertible
debentures at the option of the holders at other later dates as more fully
described in Note 8 to our consolidated financial statements in our Annual
Report on Form 10-K for the year ended December 31, 2002.
In April 2003, we repaid all of the $239.5 million principal amount
outstanding 6.5% Senior Notes in accordance with their scheduled maturities,
plus interest accrued and unpaid to the repayment date. We funded the repayment
from existing cash balances.
In May 2003, we intend to repurchase and retire all of the $50.0 million
principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005. We
expect to fund the repurchases from existing cash balances. No assurance can be
given that we will be able to complete this repurchase on the expected terms or
otherwise.
We have certain operating leases that have been previously discussed and
reported in our Annual Report on Form 10-K for the year ended December 31, 2002.
There have been no material changes in these previously reported leases.
31
At March 31, 2003, we had other commitments that we are contractually
obligated to fulfill with cash should the obligations be called. These
obligations consisted primarily of standby letters of credit and surety bonds,
that guarantee our performance as it relates to our drilling contracts,
insurance, tax and other obligations in various jurisdictions. Letters of credit
are issued under a number of facilities provided by several banks. The
obligations that are the subject of these surety bonds are geographically
concentrated in the United States, Brazil and Nigeria. These letters of credit
and surety bond obligations are not normally called as we typically comply with
the underlying performance requirement. The table below provides a list of these
obligations in U.S. dollar equivalents and their time to expiration. It should
be noted that these obligations could be called at any time prior to the
expiration dates.
For the twelve months ending March 31,
-------------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
------ ---------- ---------- ----------- ----------
(In millions)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit $ 61.2 $ 44.5 $ 12.3 $ 4.4 $ -
Surety Bonds 138.8 75.8 63.0 - -
Purchase Option Guarantees Joint Ventures (a) 208.9 208.9 - - -
Other Commitments 0.1 - 0.1 - -
------ ---------- ---------- ----------- ----------
Total $409.0 $ 329.2 $ 75.4 $ 4.4 $ -
====== ========== ========== =========== ==========
___________________________
(a) See "-Special Purpose Entities".
DERIVATIVE INSTRUMENTS
We have established policies and procedures for derivative instruments that
have been approved by our Board of Directors. These policies and procedures
provide for the prior approval of derivative instruments by our Chief Financial
Officer. From time to time, we may enter into a variety of derivative financial
instruments in connection with the management of our exposure to fluctuations in
foreign exchange rates and interest rates. We do not enter into derivative
transactions for speculative purposes; however, for accounting purposes, certain
transactions may not meet the criteria for hedge accounting.
As more fully described in Note 4 to our condensed consolidated financial
statements, we were a party to interest rate swap agreements with an aggregate
notional amount of $1.6 billion at December 31, 2002. We terminated these
agreements during the first quarter of 2003. As a result of these terminations,
we had an aggregate fair value adjustment of approximately $173.5 million
included in long-term debt in our condensed consolidated balance sheet, which is
being amortized as a reduction to interest expense over the life of the
underlying debt.
DD LLC, an unconsolidated joint venture in which we have a 50 percent
ownership interest, has entered into interest rate swaps with aggregate market
values netting to a liability of $5.0 million at March 31, 2003. Our interest in
these swaps is included in accumulated other comprehensive income, net of tax,
with corresponding reductions to deferred income taxes and investments in and
advances to joint ventures in our condensed consolidated balance sheet.
SPECIAL PURPOSE ENTITIES, SALE/LEASEBACK TRANSACTION AND RELATED PARTY
TRANSACTIONS
We have transactions with certain special purpose entities and related
parties and we are a party to a sale/leaseback transaction. These transactions
have been previously discussed and reported in our Annual Report on Form 10-K
for the year ended December 31, 2002.
In January 2003, Delta Towing LLC ("Delta Towing") failed to make its
scheduled quarterly interest payment of $1.7 million on the note receivable and
we signed a 90-day waiver of the terms requiring payment of interest. In April
2003, Delta Towing failed to make their scheduled quarterly interest payment. In
April 2003, Delta Towing also failed to make a quarterly interest payment
originally due in January 2003 that was deferred to April as a result of the
90-day waiver signed in January 2003. We consider Delta Towing to be in default
but believe future cash flows will result in payment ultimately being received.
We are in discussions with ConocoPhillips to purchase their interest in
DDII LLC. See "-Outlook."
There have been no other material developments with regards to the special
purpose entities, sale/leaseback transaction or other related party
transactions.
32
NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest
Entities. FIN 46 requires companies with a variable interest in a variable
interest entity to apply this guidance to that entity as of the beginning of the
first interim period beginning after June 15, 2003 for existing interests and
immediately for new interests. The application of the guidance could result in
the consolidation of a variable interest entity. We are evaluating the impact of
this interpretation on our consolidated financial position and results of
operations.
Effective January 2003, we implemented EITF 99-19, Reporting Revenues Gross
as a Principal versus Net as an Agent. As a result of the implementation of the
EITF, the costs incurred and charged to our clients on a reimbursable basis are
recognized as operating and maintenance expense. In addition, the amounts
billed to our clients associated with these reimbursable costs are being
recognized as client reimbursable revenue. We expect client reimbursable
revenues and operating and maintenance expense to be between $80 million and
$100 million as a result of implementation of EITF 99-19. The change in
accounting principle will have no effect on our results of operations or
consolidated financial position. Prior periods have not been reclassified, as
these amounts were not material.
FORWARD-LOOKING INFORMATION
The statements included in this quarterly report regarding future financial
performance and results of operations and other statements that are not
historical facts are forward-looking statements within the meaning of Section
27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act
of 1934. Statements to the effect that the Company or management "anticipates,"
"believes," "budgets," "estimates," "expects," "forecasts," "intends," "plans,"
"predicts," or "projects" a particular result or course of events, or that such
result or course of events "could," "might," "may," "scheduled" or "should"
occur, and similar expressions, are also intended to identify forward-looking
statements. Forward-looking statements in this quarterly report include, but are
not limited to, statements involving payment of severance costs, potential
revenues, increased expenses, the effect on revenues and expenses of the change
in accounting treatment for client reimbursables, client drilling programs,
supply and demand, utilization rates, dayrates, planned shipyard projects,
expected downtime, opportunities for deepwater rigs in India and the Far East,
positive signs in the U.S. Gulf of Mexico shallow and inland water sector,
deepwater, mid-water and the shallow and inland water markets, market outlooks
for our various geographical operating sectors, the non-U.S. jackup market
sector, client interest in the Gulf of Mexico Shallow and Inland Water barge
rigs, future activity in the International and U. S. Floater Contract Drilling
Services and Gulf of Mexico Shallow and Inland Water segments, the possible
purchase of the remaining interest in the joint venture that owns Deepwater
Frontier and related consequences, the effect of the strike in Nigeria, the
outcome and effect of the U.S. Internal Revenue Service audit and the various
tax assessments, deferred costs, the planned initial public offering of our Gulf
of Mexico Shallow and Inland Water business (including the timing of the
offering and portion sold), the U.S. gas drilling market, planned asset sales,
the Company's other expectations with regard to market outlook, expected capital
expenditures, results and effects of legal proceedings, liabilities for tax
issues, liquidity, positive cash flow from operations, the exercise of the
option of holders of Zero Coupon Convertible Debentures or the 1.5% Convertible
Debentures to require the Company to repurchase the debentures, the repurchase
of the 9.41% Nautilus Class A2 Notes due May 2005, the source of funds for the
repurchase prices, receipt of principal and interest on debt owed to the Company
by Delta Towing, adequacy of cash flow for 2003 obligations, effects of
accounting changes, and the timing and cost of completion of capital projects.
Such statements are subject to numerous risks, uncertainties and assumptions,
including, but not limited to, worldwide demand for oil and gas, uncertainties
relating to the level of activity in offshore oil and gas exploration and
development, exploration success by producers, oil and gas prices (including
U.S. natural gas prices), securities market conditions, demand for offshore and
inland water rigs, competition and market conditions in the contract drilling
industry, our ability to successfully integrate the operations of acquired
businesses, delays or terminations of drilling contracts due to a number of
events, delays or cost overruns on construction and shipyard projects and
possible cancellation of drilling contracts as a result of delays or
performance, our ability to enter into and the terms of future contracts, the
availability of qualified personnel, labor relations and the outcome of
negotiations with unions representing workers, operating hazards, political and
other uncertainties inherent in non-U.S. operations (including exchange and
currency fluctuations), risks of war, terrorism and cancellation or
unavailability of certain insurance coverage, the impact of governmental laws
and regulations, the adequacy of sources of liquidity, the effect and results of
litigation, audits and contingencies and other factors discussed in our Annual
Report on Form 10-K for the year ended December 31, 2002 and in the Company's
other filings with the SEC, which are available free of charge on the SEC's
website at www.sec.gov. Should one or more of these risks or uncertainties
materialize, or should underlying
33
assumptions prove incorrect, actual results may vary materially from those
indicated. You should not place undue reliance on forward-looking statements.
Each forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.
34
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
INTEREST RATE RISK
Our exposure to market risk for changes in interest rates relates primarily
to our long-term and short-term debt obligations. The table below presents
scheduled debt maturities and related weighted-average interest rates for each
of the twelve-month periods ending March 31 relating to debt obligations as of
March 31, 2003. Weighted-average variable rates are based on LIBOR rates at
March 31, 2003, plus applicable margins.
At March 31, 2003 (in millions, except interest rate percentages):
Scheduled Maturity Date (a) (b) Fair Value
-------------------------------------------------------------------- ----------
2004 2005 2006 2007 2008 Thereafter Total 03/31/03
------- ------- ------- ------- ------- ------------ --------- ----------
Total debt
Fixed Rate $912.6 $ 45.5 $407.9 $400.0 $100.0 $ 2,300.0 $4,166.0 $ 4,608.1
Average interest rate 4.6% 7.3% 7.1% 1.5% 7.5% 7.5% 6.2%
Variable Rate $150.0 $112.5 - - - - $ 262.5 $ 262.5
Average interest rate 2.1% 2.1% - - - - 2.1%
__________________________
(a) Maturity dates of the face value of our debt assumes the put options on the Zero Coupon
Convertible Debentures, 1.5% Convertible Debentures and 7.45% Notes will be exercised in May 2003,
May 2006 and April 2007, respectively.
(b) Expected maturity amounts are based on the face value of debt.
At March 31, 2003, we had approximately $262.5 million of variable rate
debt at face value (six percent of total debt at face value). This variable
rate debt represented term bank debt. Given outstanding amounts as of that date,
a one percent rise in interest rates would result in an additional $2.0 million
in interest expense per year. Offsetting this, a large part of our cash
investments would earn commensurately higher rates of return. Using March 31,
2003 cash investment levels, a one percent increase in interest rates would
result in approximately $15.2 million of additional interest income per year.
FOREIGN EXCHANGE RISK
Our international operations expose us to foreign exchange risk. We use a
variety of techniques to minimize the exposure to foreign exchange risk. Our
primary foreign exchange risk management strategy involves structuring client
contracts to provide for payment in both U.S. dollars and local currency. The
payment portion denominated in local currency is based on anticipated local
currency requirements over the contract term. Due to various factors, including
local banking laws, other statutory requirements, local currency convertibility
and the impact of inflation on local costs, actual foreign exchange needs may
vary from those anticipated in the client contracts, resulting in partial
exposure to foreign exchange risk. Fluctuations in foreign currencies have
minimal impact on overall results. In situations where the primary strategy is
not entirely attainable, foreign exchange derivative instruments, specifically
foreign exchange forward contracts or spot purchases, may be used. We do not
enter into derivative transactions for speculative purposes. At March 31, 2003,
we had no material open foreign exchange contracts.
In January 2003, Venezuela 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.
35
ITEM 4. CONTROLS AND PROCEDURES
Within the 90 days prior to the date of this report, the Company carried
out an evaluation, under the supervision and with the participation of the
Company's management, including the Chief Executive Officer and Chief Financial
Officer, of the effectiveness of the design and operation of the Company's
disclosure controls and procedures pursuant to Exchange Act Rule 13a-14. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
concluded that the Company's disclosure controls and procedures are effective in
timely alerting them to material information relating to the Company (including
its consolidated subsidiaries) required to be included in the Company's periodic
SEC filings. Subsequent to the date of their evaluation, there were no
significant changes in the Company's internal controls or in other factors that
could significantly affect the internal controls, including any corrective
actions with regard to significant deficiencies and material weaknesses.
36
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In 1990 and 1991, two of our subsidiaries were served with various
assessments collectively valued at approximately $7 million from the
municipality of Rio de Janeiro, Brazil to collect a municipal tax on services.
We believe that neither subsidiary is liable for the taxes and have contested
the assessments in the Brazilian administrative and court systems. The Brazil
Supreme Court rejected our appeal of an adverse lower court's ruling with
respect to a June 1991 assessment, which was valued at approximately $6 million.
We plan to challenge the assessment in a separate proceeding. We recently
received a favorable ruling from the Brazil Superior Court of Justice in
connection with a disputed August 1990 assessment. We are awaiting a ruling from
the Taxpayer's Council in connection with an October 1990 assessment. If our
defenses are ultimately unsuccessful, we believe that the Brazilian
government-controlled oil company, Petrobras, has a contractual obligation to
reimburse us for municipal tax payments required to be paid by them. We do not
expect the liability, if any, resulting from these assessments to have a
material adverse effect on our business or consolidated financial position.
In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration and affiliates and Samuel Geary
and Associates Inc. against us, certain underwriters at Lloyd's (the
"Underwriters") and an insurance broker in the 16th Judicial District Court of
St. Mary Parish, Louisiana. The plaintiffs alleged damages amounting to in
excess of $50 million in connection with the drilling of a turnkey well in 1995
and 1996. The case was tried before a jury in January and February 2000, and the
jury returned a verdict of approximately $30 million in favor of the plaintiffs
for excess drilling costs, loss of insurance proceeds, loss of hydrocarbons,
expenses and interest. 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 all
such petitions, we settled with the St. Mary group of plaintiffs and the State
of Louisiana. Thereafter, the Supreme Court of Louisiana denied the applications
for consideration by the remaining plaintiffs but has not yet ruled on our
application or the application of the Underwriters. The plaintiffs may seek
rehearing of the decision. We believe that any amounts, apart from a small
deductible, paid in settlement or which may ultimately be paid to the remaining
plaintiffs 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. While we cannot predict the outcome of
such litigation, we do not expect that the ultimate outcome of this case will
have a material adverse effect on our business or consolidated financial
position.
We have certain other actions or claims pending that have been previously
discussed and reported in our Annual Report on Form 10-K for the year ended
December 31, 2002 and our other reports filed with the Securities and Exchange
Commission. There have been no material developments in these previously
reported matters. We 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. 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.
37
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibits are filed in connection with this Report:
NUMBER DESCRIPTION
- ------ -----------
*3.1 Memorandum of Association of Transocean Inc., as amended (incorporated by
reference to Annex E to the Joint Proxy Statement/Prospectus dated October
30, 2000 included in a 424(b)(3) prospectus filed by the Company on
November 1, 2000)
*3.2 Articles of Association of Transocean Inc., as amended (incorporated by
reference to Annex F to the Joint Proxy Statement/Prospectus dated October
30, 2000 included in a 424(b)(3) prospectus filed by the Company on
November 1, 2000)
*3.3 Certificate of Incorporation on Change of Name to Transocean Inc.
(incorporated by reference to Exhibit 3.3 to the Company's Form 10-Q for
the quarter ended June 30, 2002)
4.1 364-Day Credit Agreement dated as of December 26, 2002 among the Company,
the Lenders party thereto, SunTrust Bank, as Administrative Agent, ABN AMRO
Bank, N.V. and The Royal Bank of Scotland plc, as Co-Syndication Agents,
Bank of America, N.A. and Wells Fargo Bank Texas, National Association, as
Co-Documentation Agents, and Citibank, N.A., Credit Lyonnais New York
Branch and HSBC Bank USA, as Managing Agents
99.1 CEO Certification Pursuant to Section 906 of the Sarbanes - Oxley Act of
2002
99.1 CFO Certification Pursuant to Section 906 of the Sarbanes - Oxley Act of
2002
_________________________
* Incorporated by reference as indicated.
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on January 2, 2003
(information furnished not filed) announcing that the "Monthly Fleet Update"
report as of January 1, 2003 was available on the Company's website and a
Current Report on Form 8-K on January 30, 2003 (information furnished not filed)
announcing that the "Monthly Fleet Update" report as of January 30, 2003 was
available on the Company's website.
38
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, hereunto duly authorized, on May 9, 2003.
TRANSOCEAN INC.
By: /s/ Gregory L. Cauthen
------------------------
Gregory L. Cauthen
Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
By: /s/ Brenda S. Masters
-----------------------
Brenda S. Masters
Vice President and Controller
(Principal Accounting Officer)
39
CERTIFICATIONS
Principal Executive Officer
---------------------------
I, Robert L. Long, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Transocean Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
c) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003 /s/ Robert L. Long
-------------------------------------
Robert L. Long
President and Chief Executive Officer
40
Principal Financial Officer
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I, Gregory L. Cauthen, certify that:
1. I have reviewed this quarterly report on Form 10-Q of Transocean Inc.;
2. Based on my knowledge, this quarterly report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by
this quarterly report;
3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and cash
flows of the registrant as of, and for, the periods presented in this
quarterly report;
4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined
in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:
a) Designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this quarterly
report is being prepared;
b) Evaluated the effectiveness of the registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date of
this quarterly report (the "Evaluation Date"); and
d) Presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The registrant's other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrant's auditors and the audit
committee of registrant's board of directors (or persons performing the
equivalent function):
a) All significant deficiencies in the design or operation of internal
controls which could adversely affect the registrant's ability to
record, process, summarize and report financial data and have
identified for the registrant's auditors any material weaknesses in
internal controls; and
b) Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrant's internal
controls; and
6. The registrant's other certifying officers and I have indicated in this
quarterly report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and material
weaknesses.
Date: May 9, 2003 /s/ Gregory L. Cauthen
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Gregory L. Cauthen
Senior Vice President, Chief
Financial Officer and Treasurer
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