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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 JUNE 30, 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)
Registrant's 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 July 31, 2003, 319,887,560 ordinary shares, par value $0.01 per
share, were outstanding.
================================================================================
TRANSOCEAN INC.
INDEX TO FORM 10-Q
QUARTER ENDED JUNE 30, 2003
Page
----
PART I - FINANCIAL INFORMATION
- ----------------------------------
ITEM 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Operations
Three and Six Months Ended June 30, 2003 and 2002. . . . . . . . 2
Condensed Consolidated Statements of Comprehensive Income (Loss)
Three and Six Months Ended June 30, 2003 and 2002. . . . . . . . 3
Condensed Consolidated Balance Sheets
June 30, 2003 and December 31, 2002. . . . . . . . . . . . . . . 4
Condensed Consolidated Statements of Cash Flows
Six Months Ended June 30, 2003 and 2002. . . . . . . . . . . . . 5
Notes to Condensed Consolidated Financial Statements . . . . . . . 7
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations. . . . . . . . . . . . . . . . 21
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk . . . . 44
ITEM 4. Controls and Procedures. . . . . . . . . . . . . . . . . . . . . . 45
PART II - OTHER INFORMATION
- -----------------------------
ITEM 1. Legal Proceedings. . . . . . . . . . . . . . . . . . . . . . . . . 46
ITEM 4. Submission of Matters to a Vote of Security Holders. . . . . . . . 46
ITEM 6. Exhibits and Reports on Form 8-K . . . . . . . . . . . . . . . . . 48
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 June 30, Six Months Ended June 30,
------------------------------- -----------------------------
2003 2002 2003 2002
-------------- --------------- ------------ ---------------
Operating Revenues
Contract drilling revenues $ 576.6 $ 646.2 $ 1,166.2 $ 1,314.1
Client reimbursable revenues 27.3 - 53.7 -
- --------------------------------------------------------------------------------------------------------------------------
603.9 646.2 1,219.9 1,314.1
- --------------------------------------------------------------------------------------------------------------------------
Costs and Expenses
Operating and maintenance 426.5 365.6 800.6 746.6
Depreciation 127.5 124.3 254.3 249.9
General and administrative 14.9 16.0 28.8 35.8
Impairment loss on long-lived assets 15.8 - 16.8 1.1
(Gain) loss from sale of assets, net (0.6) 1.3 (2.0) (0.6)
- --------------------------------------------------------------------------------------------------------------------------
584.1 507.2 1,098.5 1,032.8
- --------------------------------------------------------------------------------------------------------------------------
Operating Income 19.8 139.0 121.4 281.3
Other Income (Expense), net
Equity in earnings of joint ventures 1.8 2.5 5.4 4.4
Interest income 5.8 5.7 12.7 9.9
Interest expense (52.8) (52.5) (105.4) (108.4)
Loss on retirement of debt (15.7) - (15.7) -
Loss on impairment of note receivable from related party (21.3) - (21.3) -
Other, net (2.7) (0.4) (3.3) (1.1)
- --------------------------------------------------------------------------------------------------------------------------
(84.9) (44.7) (127.6) (95.2)
- --------------------------------------------------------------------------------------------------------------------------
Income (Loss) Before Income Taxes, Minority Interest and
Cumulative Effect of a Change in Accounting Principle (65.1) 94.3 (6.2) 186.1
Income Tax Expense (Benefit) (20.8) 13.9 (9.0) 27.7
Minority Interest 0.2 0.4 0.1 1.1
- --------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) Before Cumulative Effect of a Change in
Accounting Principle (44.5) 80.0 2.7 157.3
Cumulative Effect of a Change in Accounting Principle - - - (1,363.7)
- --------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ (44.5) $ 80.0 $ 2.7 $ (1,206.4)
==========================================================================================================================
Basic Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a Change in
Accounting Principle $ (0.14) $ 0.25 $ 0.01 $ 0.49
Loss on Cumulative Effect of a Change in Accounting
Principle - - - (4.27)
- --------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ (0.14) $ 0.25 $ 0.01 $ (3.78)
==========================================================================================================================
Diluted Earnings (Loss) Per Share
Income (Loss) Before Cumulative Effect of a Change in $ (0.14) $ 0.25 $ 0.01 $ 0.49
Accounting Principle
Loss on Cumulative Effect of a Change in Accounting
Principle - - - (4.22)
- --------------------------------------------------------------------------------------------------------------------------
Net Income (Loss) $ (0.14) $ 0.25 $ 0.01 $ (3.73)
==========================================================================================================================
Weighted Average Shares Outstanding
Basic 319.8 319.1 319.7 319.1
- --------------------------------------------------------------------------------------------------------------------------
Diluted 319.8 323.9 321.5 323.6
- --------------------------------------------------------------------------------------------------------------------------
Dividends Paid per Share $ - $ 0.03 $ - $ 0.06
- --------------------------------------------------------------------------------------------------------------------------
See accompanying notes.
2
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)
(Unaudited)
Three Months Ended June 30, Six Months Ended June 30,
------------------------------- -----------------------------
2003 2002 2003 2002
-------------- --------------- ------------ ---------------
Net income (loss) $ (44.5) $ 80.0 $ 2.7 $ (1,206.4)
- ----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Amortization of gain on terminated interest rate swaps (0.1) - (0.1) (0.1)
Change in unrealized loss on securities available for sale 0.2 - 0.2 0.1
Change in share of unrealized loss in unconsolidated
joint venture's interest rate swaps 1.4 (1.0) 1.1 2.1
Minimum pension liability adjustments 0.1 - 0.8 -
- ----------------------------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) 1.6 (1.0) 2.0 2.1
- ----------------------------------------------------------------------------------------------------------------------------
Total comprehensive income (loss) $ (42.9) $ 79.0 $ 4.7 $ (1,204.3)
============================================================================================================================
See accompanying notes.
3
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions)
(Unaudited)
June 30, December 31,
2003 2002
------------ -------------
(Unaudited)
ASSETS
Cash and Cash Equivalents $ 714.0 $ 1,214.2
Accounts Receivable, net of allowance for doubtful accounts of $19.8
and $20.8 at June 30, 2003 and December 31, 2002, respectively 442.3 499.3
Materials and Supplies, net of allowance for obsolescence of $18.6 160.0 155.8
at June 30, 2003 and December 31, 2002
Deferred Income Taxes 19.7 21.9
Other Current Assets 91.0 20.5
- --------------------------------------------------------------------------------------------------
Total Current Assets 1,427.0 1,911.7
- --------------------------------------------------------------------------------------------------
Property and Equipment 10,196.5 10,198.0
Less Accumulated Depreciation 2,413.8 2,168.2
- --------------------------------------------------------------------------------------------------
Property and Equipment, net 7,782.7 8,029.8
- --------------------------------------------------------------------------------------------------
Goodwill, net 2,222.9 2,218.2
Investments in and Advances to Joint Ventures 68.3 108.5
Deferred Income Taxes 26.2 26.2
Other Assets 178.7 370.7
- --------------------------------------------------------------------------------------------------
Total Assets $ 11,705.8 $ 12,665.1
==================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts Payable $ 140.0 $ 134.1
Accrued Income Taxes 64.4 59.5
Debt Due Within One Year 282.3 1,048.1
Other Current Liabilities 239.2 262.2
- --------------------------------------------------------------------------------------------------
Total Current Liabilities 725.9 1,503.9
- --------------------------------------------------------------------------------------------------
Long-Term Debt 3,476.0 3,629.9
Deferred Income Taxes 50.7 107.2
Other Long-Term Liabilities 291.7 282.7
- --------------------------------------------------------------------------------------------------
Total Long-Term Liabilities 3,818.4 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, 3.2 3.2
319,853,774 and 319,219,072 shares issued and outstanding at
June 30, 2003 and December 31, 2002, respectively
Additional Paid-in Capital 10,638.5 10,623.1
Accumulated Other Comprehensive Loss (29.5) (31.5)
Retained Deficit (3,450.7) (3,453.4)
- --------------------------------------------------------------------------------------------------
Total Shareholders' Equity 7,161.5 7,141.4
- --------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 11,705.8 $ 12,665.1
==================================================================================================
See accompanying notes.
4
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
Six Months Ended
June 30,
----------------------
2003 2002
--------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss) $ 2.7 $ (1,206.4)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation 254.3 249.9
Impairment loss on goodwill - 1,363.7
Stock-based compensation expense 2.9 0.4
Deferred income taxes (59.5) (38.3)
Equity in earnings of joint ventures (5.4) (4.4)
Net loss from disposal of assets 7.8 2.3
Loss on retirement of debt 15.7 -
Impairment loss on long-lived assets 16.8 1.1
Impairment of note receivable from related party 21.3 -
Amortization of debt-related discounts/premiums, fair value (7.9) 2.9
adjustments and issue costs, net
Deferred income, net (1.6) (6.0)
Deferred expenses, net 2.7 7.0
Other, net 13.5 9.3
Changes in operating assets and liabilities
Accounts receivable 51.6 84.1
Accounts payable and other current liabilities 4.0 (84.7)
Income taxes receivable/payable, net 9.6 22.3
Other current assets (23.3) (22.7)
- --------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 305.2 380.5
- --------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (50.2) (81.2)
Note issued to related party, net of repayments (45.3) -
Proceeds from disposal of assets, net 3.2 65.0
Acquisition of 40 percent interest in Deepwater Drilling II L.L.C., 18.1 -
net of cash acquired
Joint ventures and other investments, net 2.2 -
- --------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (72.0) (16.2)
- --------------------------------------------------------------------------------------------
See accompanying notes.
5
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
Six Months Ended
June 30,
----------------------
2003 2002
--------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES
Repayments under commercial paper program - (326.4)
Repayments on other debt instruments (919.2) (119.6)
Cash from termination of interest rate swaps 173.5 -
Decrease in cash dedicated to debt service 1.2 -
Net proceeds from issuance of ordinary shares under
stock-based compensation plans 11.7 10.3
Dividends paid - (19.1)
Financing costs (0.1) (8.1)
Other, net (0.5) 1.1
- ---------------------------------------------------------------------------
Net Cash Used in Financing Activities (733.4) (461.8)
- ---------------------------------------------------------------------------
Net Decrease in Cash and Cash Equivalents (500.2) (97.5)
- ---------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Period 1,214.2 853.4
- ---------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 714.0 $ 755.9
===========================================================================
See accompanying notes.
6
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 June 30, 2003, the Company owned, had partial ownership
interests in or operated more than 160 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 and
six months ended June 30, 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 $106.1 million and $40.9 million, respectively, for the six
months ended June 30, 2003 and $109.8 million and $44.2 million, respectively,
for the six months ended June 30, 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,
7
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
International and U.S. Floater Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water, at a ratio of 68 percent and 32 percent, respectively.
The allocation was determined based on the percentage of each reporting unit's
assets at fair value to the total fair value of assets acquired in the R&B
Falcon merger. The fair value was determined from a third party valuation.
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 was $2.2 billion as of June 30, 2003. The
changes in the carrying amount of goodwill as of June 30, 2003 were as follows
(in millions):
Balance at Balance at
January 1, June 30,
2003 Other (a) 2003
----------- ---------- -----------
International and U.S. Floater Contract Drilling Services $ 2,218.2 $ 4.7 $ 2,222.9
_________________
(a) Represents net unfavorable adjustments during 2003 of income 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 8.
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,
particularly in countries with revenue-based taxes. There is no expected
relationship between the provision for income taxes and income before income
taxes because the countries in which we operate have different taxation regimes,
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 than in 2002.
8
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
COMPREHENSIVE INCOME - The components of accumulated other comprehensive
income (loss), net of tax, as of June 30, 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 (0.1) 0.2 1.1 0.8 2.0
(loss), net of tax
--------------- ------------ ----------------- ----------- ---------------
Balance at June 30, 2003 $ 3.5 $ (0.4) $ (0.9) $ (31.7) $ (29.5)
=============== ============ ================= =========== ===============
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 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 7.
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.
9
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
If compensation expense for grants to employees under the Company's
long-term incentive plan and employee stock purchase plan prior to January 1,
2003 was recognized using the fair value method of accounting under SFAS 123
rather than the intrinsic value method under APB 25, net income (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 Six Months Ended
June 30, June 30,
------------------------ ----------------------
2003 2002 2003 2002
----------- ----------- ---------- ----------
Net Income (Loss) as Reported $ (44.5) $ 80.0 $ 2.7 $(1,206.4)
Add back: Stock-based compensation expense included in 1.3 0.2 2.5 0.4
reported net income (loss), net of related tax effects
Deduct: Total stock-based compensation expense determined
under fair value based method for all awards, net of related
tax effects
Long-Term Incentive Plan (3.7) (5.7) (8.3) (10.1)
Employee Stock Purchase Plan (1.2) (0.6) (2.1) (1.2)
----------- ----------- ---------- ----------
Pro Forma Net Income (Loss) $ (48.1) $ 73.9 $ (5.2) $(1,217.3)
=========== =========== ========== ==========
Basic Earnings (Loss) Per Share
As Reported $ (0.14) $ 0.25 $ 0.01 $ (3.78)
Pro Forma (0.15) 0.23 (0.02) (3.81)
Diluted Earnings (Loss) Per Share
As Reported $ (0.14) $ 0.25 $ 0.01 $ (3.73)
Pro Forma (0.15) 0.23 (0.02) (3.76)
NEW ACCOUNTING PRONOUNCEMENTS - In January 2003, the FASB issued
Interpretation No. 46, Consolidation of Variable Interest Entities, an
Interpretation of Accounting Research Bulletin No. 51 (the "Interpretation").
The Interpretation requires the consolidation of entities in which an enterprise
absorbs a majority of the entity's expected losses, receives a majority of the
entity's expected residual returns, or both, as a result of ownership,
contractual or other financial interests in the entity. The Interpretation is
effective as of the beginning of the first interim period beginning after June
15, 2003 for existing interests and immediately for new interests. Currently,
the Company generally consolidates an entity when it has a controlling interest
through ownership of a majority voting interest in the entity.
The Company has investments in and advances to six joint ventures. One
joint venture, Deepwater Drilling L.L.C. ("DD LLC"), was established for the
purpose of constructing and leasing a drillship. One joint venture, Delta Towing
Holdings, LLC ("Delta Towing"), was established for the purpose of owning and
operating inland and shallow water marine support vessel equipment. The
remaining four joint ventures were primarily established for the purpose of
owning and operating certain drilling units. While the operations of DD LLC are
funded by cash flows from operating activities, the Company guarantees the debt
and equity financing on the drillship equally with its joint venture partner.
The debt and equity financing balance for the leased drillship was $194.1
million at June 30, 2003. The Company holds notes receivable from the Delta
Towing joint venture with a carrying value of $54.8 million at June 30, 2003.
The remaining joint ventures are funded primarily by cash flows from operating
activities.
The Company accounts for these investments using the equity method of
accounting, recording its share of the net income or loss based upon the terms
of the joint venture agreements. Because the Company has a 50 percent or less
ownership interest in these joint ventures, it does not have a controlling
interest in the joint ventures nor does it have the ability to exercise
significant influence over operating and financial policies.
10
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
At the time the Delta Towing joint venture was formed, it issued $144.0
million in notes to TODCO. Prior to the R&B Falcon merger, $64.0 million of the
notes were fully reserved leaving an $80.0 million balance at January 31, 2001.
This note agreement was subsequently amended to provide for a $4.0 million,
three-year revolving credit facility. Delta Towing's assets serve as collateral
for the Company's notes receivable. The Delta Towing joint venture also issued a
$3.0 million note to the 75 percent joint venture partner. Because the Company
has the largest percentage of investment at risk through the notes receivable
and Delta Towing's equity is not sufficient to absorb its expected losses, the
Company is expected to absorb the majority of the joint venture's expected
losses and, therefore, the Company is deemed to be the primary beneficiary of
Delta Towing for accounting purposes. As such, the Company will consolidate
Delta Towing effective July 1, 2003. The Company expects the consolidation of
Delta Towing to result in an increase in current assets of approximately $5.0
million, an increase in property and equipment, net of approximately $55.0
million, a decrease in investments in and advances to joint ventures of
approximately $55.0 million, an increase in current liabilities of approximately
$1.0 million and an increase in long-term debt of approximately $3.0 million.
The Company is currently evaluating the effects of adopting the
Interpretation on the accounting for its ownership interest in its other joint
ventures.
The Company has a wholly owned subsidiary, Deepwater Drilling II L.L.C.
("DDII LLC"), that was established as a joint venture with a major oil company
for the purpose of constructing and leasing a drillship, the Deepwater Frontier.
The drillship was purchased by a trust that was established to finance the
purchase through debt and equity financing, which the Company, under certain
circumstances, fully guarantees. On May 29, 2003, the Company purchased the
entire 40 percent interest of the major oil company in DDII LLC. The Company
currently accounts for DDII LLC's lease of the drillship as an operating lease.
The balance of the trust's debt and equity financing at June 30, 2003 was
approximately $162.0 million. Because the Company is at risk for this amount,
the Company is deemed to be the primary beneficiary of the trust for accounting
purposes and will consolidate the trust effective July 1, 2003. The drillship
serves as collateral for the trust's debt and equity financing. Effective with
the consolidation of the trust, the debt and equity financing to be reflected in
the Company's balance sheet will be approximately $153.0 million and $9.0
million, respectively. The debt financing will be reflected as debt due within
one year while the equity financing will be reflected as minority interest
within other long-term liabilities in the Company's balance sheet. In addition,
the Company will record approximately $207.0 million for the drillship as
property and equipment, net in its balance sheet and will eliminate its notes
receivable to related party of $45.3 million (see Note 11).
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 $90 million and $110 million
in 2003 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.
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
requires an issuer to measure and classify as liabilities certain financial
instruments that have characteristics of both liabilities and equity as
liabilities. SFAS 150 applies to those instruments that represent, or are
indexed to, an obligation to buy back the issuer's shares and obligations that
can be settled in shares and meet certain conditions. It does not, however,
apply to financial instruments that are indexed to and potentially settled in an
issuer's own shares. This statement is effective for financial instruments
entered into or modified after May 31, 2003, and otherwise is effective at the
beginning of the first interim period beginning after June 15, 2003. The Company
will adopt this statement effective July 1, 2003. However, management does not
expect the
11
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
adoption of this statement to have a material effect on the Company's
consolidated financial position or results of operations.
RECLASSIFICATIONS - Certain reclassifications have been made to prior
period amounts to conform with the current period's presentation.
NOTE 3 - DEBT
Debt, net of unamortized discounts, premiums and fair value adjustments, is
comprised of the following (in millions):
June 30, December 31,
2003 2002
--------- -------------
6.5% Senior Notes, due April 2003 $ - $ 239.7
9.125% Senior Notes, due December 2003 88.2 89.5
Amortizing Term Loan Agreement - Final Maturity December 2004 225.0 300.0
6.75% Senior Notes, due April 2005 (a) 365.4 371.8
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005 84.6 104.7
9.41% Nautilus Class A2 Notes, due May 2005 - 51.7
6.95% Senior Notes, due April 2008 (a) 271.6 277.2
9.5% Senior Notes, due December 2008 (a) 362.7 371.8
6.625% Notes, due April 2011 (a) 802.8 803.7
7.375% Senior Notes, due April 2018 250.5 250.5
Zero Coupon Convertible Debentures, due May 2020 (put options exercisable May 2008
and May 2013) (b) 16.3 527.2
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 198.1 198.0
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 1.0 0.2
--------- -------------
Total Debt 3,758.3 4,678.0
Less Debt Due Within One Year (b) 282.3 1,048.1
--------- -------------
Total Long-Term Debt $ 3,476.0 $ 3,629.9
========= =============
_________________
(a) At December 31, 2002, the Company was a party to interest rate swap agreements with respect to these debt instruments.
See Note 6.
(b) At December 31, 2002, the Zero Coupon Convertible Debentures were classified as debt due within one year since the put
options were exercisable in May 2003. At June 30, 2003, the remaining balance was classified as long-term debt.
12
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 1.5%
Convertible Debentures, 7.45% Notes and Zero Coupon Convertible Debentures in
May 2006, April 2007 and May 2008, respectively, and is as follows for the
twelve months ending June 30 (in millions):
2004 $ 281.2
2005 467.3
2006 400.0
2007 100.0
2008 269.0
Thereafter 2,050.0
--------
Total $3,567.5
========
Commercial Paper Program - The Company has two revolving credit agreements,
described below, which provide liquidity for commercial paper borrowings. At
June 30, 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 June 30, 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 June 30, 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 June 30, 2003, $225.0
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% (see
"-Retired and Repurchased Debt"), 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.
Retired and Repurchased Debt - 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 maturity. The Company funded
the repayment from existing cash balances.
13
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In May 2003, the Company repurchased and retired all of the $50.0 million
principal amount outstanding 9.41% Nautilus Class A2 Notes due May 2005 and
funded the repurchase from existing cash balances. The Company recognized a loss
on the early retirement of debt of approximately $3.6 million ($0.01 per diluted
share), net of tax of $1.9 million, in the second quarter of 2003.
In April 2003, the Company announced that holders of its Zero Coupon
Convertible Debentures due May 24, 2020 had the option to require the Company to
repurchase their debentures in May 2003. Holders of $838.6 million aggregate
principal amount, or approximately 97 percent, of these debentures exercised
this option and the Company repurchased their debentures at a repurchase price
of $628.57 per $1,000 principal amount. Under the terms of the debentures, the
Company had the option to pay for the debentures with cash, the Company's
ordinary shares, or a combination of cash and shares, and elected to pay the
$527.2 million repurchase price from existing cash balances. The Company
recognized additional expense of approximately $10.2 million ($0.03 per diluted
share) as an after-tax loss on retirement of debt in the second quarter of 2003
to fully amortize the remaining debt issue costs related to the repurchased
debentures. The holders of the $26.4 million aggregate principal amount of
debentures that remain outstanding have the right to require the Company to
repurchase the debentures in May 2008 at a price of $720.55 per $1,000 principal
amount. The Company also has the right to redeem the remaining debentures at any
time at a price equal to the debentures' then accreted value. The outstanding
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.
NOTE 4 - INCOME TAXES
In June 2003, the Company recorded a $14.6 million ($0.04 per diluted
share) foreign tax benefit attributable to the favorable resolution of a
non-U.S. income tax liability, as well as tax benefits resulting from non-cash
impairments and loss on debt retirements. As a result of the deterioration in
2003 profitability, the annual effective tax rate is now estimated to be
approximately 38 percent during 2003 on earnings before asset impairments, note
receivable impairments and loss on debt retirements. Due to the change in the
estimated annual effective tax rate from approximately 20 percent at March 31,
2003, earnings for the three months ended June 30, 2003 were reduced by $10.7
million ($0.03 per diluted share) as a result of applying the adjusted estimated
annual effective tax rate to the three months ended March 31, 2003.
NOTE 5 - FINANCIAL INSTRUMENTS AND RISK CONCENTRATION
Foreign Exchange Risk - The Company's international operations expose the
Company to foreign exchange risk. This risk is primarily associated with
compensation costs denominated in currencies other than the U.S. dollar and with
purchases from foreign suppliers. The Company uses a variety of techniques to
minimize exposure to foreign exchange risk, including customer contract payment
terms and foreign exchange derivative instruments.
The Company's primary foreign exchange risk management strategy involves
structuring customer contracts to provide for payment in both U.S. dollars and
local currency. The payment portion denominated in local currency is based on
anticipated local currency requirements over the contract term. 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 customer
contracts, resulting in partial exposure to foreign exchange risk. Fluctuations
in foreign currencies typically have minimal impact on overall results. In
situations where payments of local currency do not equal local currency
requirements, foreign exchange derivative instruments, specifically foreign
exchange forward contracts, or spot purchases may be used. A foreign exchange
forward contract obligates the Company to exchange predetermined amounts of
specified foreign currencies at specified exchange rates on specified dates or
to make an equivalent U.S. dollar payment equal to the value of such exchange.
The Company does not enter into derivative transactions for speculative
purposes. At June 30, 2003, the Company had no material open foreign exchange
contracts.
14
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
In January 2003, Venezuela implemented foreign exchange controls that limit
the Company's ability to convert local currency into U.S. dollars and transfer
excess funds out of Venezuela. The Company's drilling contracts in Venezuela
typically call for payments to be made in local currency, even when the dayrate
is denominated in U.S. dollars. The exchange controls could also result in an
artificially high value being placed on the local currency. As a result, the
Company recognized a loss of $1.5 million, net of tax of $0.8 million, on the
revaluation of the local currency into functional U.S dollars for the six months
ended June 30, 2003.
NOTE 6 - 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
requirement 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 reduction is
expected to be approximately $23.1 million ($0.07 per diluted share) in 2003.
DD LLC, an unconsolidated subsidiary in which the Company has a 50 percent
ownership interest, entered into interest rate swaps in August 1998 that have
aggregate market values netting to a liability of $2.9 million at June 30, 2003.
The Company's interest in these swaps has been 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 7 - 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.
15
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
Operating revenues and income (loss) before income taxes, minority interest
and cumulative effect of a change in accounting principle by segment are as
follows (in millions):
Three Months Ended Six Months Ended
June 30, June 30,
------------------------ ----------------------
2003 2002 2003 2002
----------- ----------- --------- -----------
Operating Revenues
International and U.S. Floater Contract Drilling Services $ 548.5 $ 609.1 $1,111.2 $ 1,232.3
Gulf of Mexico Shallow and Inland Water 55.4 37.1 108.7 81.8
----------- ----------- --------- -----------
Total Operating Revenues $ 603.9 $ 646.2 $1,219.9 $ 1,314.1
----------- ----------- --------- -----------
Operating income (loss) before general and administrative
expense
International and U.S. Floater Contract Drilling Services $ 84.2 $ 185.9 $ 228.2 $ 380.8
Gulf of Mexico Shallow and Inland Water (49.5) (30.9) (78.0) (63.7)
----------- ----------- --------- -----------
34.7 155.0 150.2 317.1
Unallocated general and administrative expense (14.9) (16.0) (28.8) (35.8)
Unallocated other income (expense), net (84.9) (44.7) (127.6) (95.2)
----------- ----------- --------- -----------
Income (Loss) before Income Taxes, Minority Interest
and Cumulative Effect of a Change in Accounting
Principle $ (65.1) $ 94.3 $ (6.2) $ 186.1
=========== =========== ========= ===========
Total assets by segment were as follows (in millions):
June 30, December 31,
2003 2002
--------- -------------
International and U.S. Floater Contract Drilling Services $10,913.8 $ 11,804.1
Gulf of Mexico Shallow and Inland Water 792.0 861.0
--------- -------------
Total Assets $11,705.8 $ 12,665.1
========= =============
NOTE 8 - ASSET DISPOSITIONS AND IMPAIRMENT LOSS
Asset Dispositions - 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 gain of
$0.2 million, net of tax of $0.1 million. The proceeds were received in December
2002.
During the six months ended June 30, 2003, the Company settled an insurance
claim and sold certain other assets for net proceeds of approximately $3.2
million and recorded net after-tax gains of $1.4 million in its International
and U.S. Floater Contract Drilling Services segment and $0.2 million, net of tax
of $0.1 million, in its Gulf of Mexico Shallow and Inland Water segment.
During the six months ended June 30, 2002, in the International and U.S.
Floater Contract Drilling Services segment, the Company sold the jackup rig RBF
209 and two semisubmersible rigs, the Transocean 96 and Transocean 97, for net
proceeds of $49.4 million and recognized net losses of $0.3 million, net of tax
of $0.1 million.
During the six months ended June 30, 2002, the Company settled an insurance
claim and sold certain other assets for net proceeds of approximately $15.6
million and recorded net gains of $1.0 million, net of tax of $0.5
16
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
million, in its International and U.S. Floater Contract Drilling Services
segment and net losses of $0.3 million, net of tax of $0.1 million, in its Gulf
of Mexico Shallow and Inland Water segment.
Impairments - During the six months ended June 30, 2003, the Company
recorded non-cash impairment charges of $6.9 million ($0.02 per diluted share),
net of tax of $3.7 million, in the Gulf of Mexico Shallow and Inland Water
segment, which resulted from the Company's decision to take five jackup rigs out
of drilling service and market the rigs for alternative uses. The Company does
not anticipate returning these rigs to drilling service as it is believed to be
cost prohibitive. As a result of this decision, and in accordance with SFAS 144,
the carrying value of these assets was adjusted to fair market value. The fair
market values of these units as non-drilling rigs were based on third party
valuations. The Company also recorded a non-cash impairment charge in this
segment of $0.7 million, net of tax of $0.3 million, related to its
approximately 12 percent investment in Energy Virtual Partners, LP and Energy
Virtual Partners Inc., which resulted from the Company's determination that the
fair value of the assets of those entities did not support its carrying value,
which is included in investments in and advances to joint ventures in the
Company's condensed consolidated balance sheets. The impairment was determined
and measured based on the remaining book value of the Company's investment and
management's assessment of the fair value of that investment at the time the
decision was made.
During the six months ended June 30, 2003, the Company recorded an
after-tax, non-cash impairment charge of $4.2 million ($0.01 per diluted share)
related to assets held and used in the International and U.S. Floater Contract
Drilling Services segment, which resulted from the Company's decision to remove
one mid-water semisubmersible rig and one self-erecting tender rig from drilling
service. The impairment was determined and measured based on an estimate of fair
value derived from an offer from a potential buyer. The Company also recorded an
after-tax, non-cash impairment charge of $1.0 million in this segment, which
resulted from the 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 assets and management's assessment of the fair value
at the time the decision was made.
During the six months ended June 30, 2002, the Company recorded a non-cash
impairment charge of $0.7 million, net of tax of $0.4 million, related to an
asset held for sale in the Gulf of Mexico Shallow and Inland Water segment,
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.
17
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
NOTE 9 - 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 Six Months Ended
June 30, June 30,
----------------------- ---------------------
2003 2002 2003 2002
----------- ---------- -------- -----------
NUMERATOR FOR BASIC AND DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of a Change in
Accounting Principle $ (44.5) $ 80.0 $ 2.7 $ 157.3
Cumulative Effect of a Change in Accounting Principle - - - (1,363.7)
----------- ---------- -------- -----------
Net Income (Loss) $ (44.5) $ 80.0 $ 2.7 $ (1,206.4)
=========== ========== ======== ===========
DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share 319.8 319.1 319.7 319.1
Effect of dilutive securities:
Employee stock options and unvested stock grants - 2.7 1.2 2.6
Warrants to purchase ordinary shares - 2.1 0.6 1.9
----------- ---------- -------- -----------
Adjusted weighted-average shares and assumed
conversions for diluted earnings per share 319.8 323.9 321.5 323.6
=========== ========== ======== ===========
BASIC EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of a Change in
Accounting Principle $ (0.14) $ 0.25 $ 0.01 $ 0.49
Cumulative Effect of a Change in Accounting Principle - - - (4.27)
----------- ---------- -------- -----------
Net Income (Loss) $ (0.14) $ 0.25 $ 0.01 $ (3.78)
=========== ========== ======== ===========
DILUTED EARNINGS (LOSS) PER SHARE
Income (Loss) Before Cumulative Effect of a Change in
Accounting Principle $ (0.14) $ 0.25 $ 0.01 $ 0.49
Cumulative Effect of a Change in Accounting Principle - - - (4.22)
----------- ---------- -------- -----------
Net Income (Loss) $ (0.14) $ 0.25 $ 0.01 $ (3.73)
=========== ========== ======== ===========
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 for all periods
presented. Incremental shares related to stock options, unvested stock grants
and warrants are not included in the calculation of adjusted weighted-average
shares and assumed conversions for diluted earnings per share for the three
months ended June 30, 2003, because the effect of including those shares is
anti-dilutive for that period.
NOTE 10 - CONTINGENCIES
Legal Proceedings - In March 1997, an action was filed by Mobil Exploration
and Producing U.S. Inc. and affiliates, St. Mary Land & Exploration Company and
affiliates and Samuel Geary and Associates Inc. against a subsidiary of the
Company, Cliffs Drilling, its underwriters at Lloyd's (the "Underwriters") and
an insurance broker in the 16th Judicial District Court of St. Mary Parish,
Louisiana. The plaintiffs alleged damages 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
18
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
requesting that the Court reduce the verdict or, in the case of the
Underwriters, eliminate any liability for the verdict. Prior to the Supreme
Court of Louisiana ruling on these petitions, the Company settled with the St.
Mary group of plaintiffs and the State of Louisiana. Subsequently, the Supreme
Court of Louisiana denied the applications of all remaining plaintiffs. The
Company settled with all remaining plaintiffs in the second quarter of 2003. The
Company believes that the amounts, apart from a small deductible, paid in the
settlement are covered by relevant primary and excess liability insurance
policies. However, the insurers and the Underwriters have denied all coverage.
The Company has instituted litigation against those insurers and Underwriters to
enforce its rights under the relevant policies. One group of issuers has
asserted a counterclaim against the Company claiming that they issued the policy
as a result of misrepresentation. The settlements did not have a material
adverse effect on the Company's business or consolidated financial position. The
Company does not expect the ultimate outcome of the case to 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 June 30, 2003 totaling $78.7 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 $159.6 million in place that secure customs
obligations relating to the importation of its rigs and certain performance and
other obligations.
NOTE 11 - RELATED PARTY TRANSACTIONS
Delta Towing - In January 2003, 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. In April
2003, Delta Towing again failed to make its interest payment of $1.7 million
originally due January 2003 after expiration of the 90-day waiver. In April
2003, Delta Towing failed to make another scheduled quarterly interest payment
of $1.6 million. During the six months ended June 30, 2003, the Company received
partial interest payments of approximately $0.6 million. At June 30, 2003, the
Company had interest receivable from Delta Towing of $4.3 million. As a result
of the Company's continued evaluation of the collectibility of the Delta Towing
notes, the Company recorded an impairment on the notes receivable of $13.8
million ($0.04 per diluted share), net of tax of $7.5 million, in the second
quarter of 2003 as an allowance for credit losses. The Company based the
impairment on Delta Towing's discounted projected cash flows over the term of
the notes, which deteriorated in the second quarter of 2003 as a result of the
continued decline in Delta Towing's business outlook. The amount of the notes
receivable outstanding prior to the impairment was $82.8 million. At June 30,
2003, the carrying value of the notes receivable, net of the related allowance
for credit losses, was $54.8 million. The Company will establish a reserve for
future interest income earned and recorded on the notes receivable and will
apply cash payments to interest receivable currently outstanding and then to
interest income for which a reserve has been established.
DDII LLC is the lessee in a synthetic lease financing facility entered into
in connection with the construction of the Deepwater Frontier. In May 2003,
WestLB AG, one of the lenders in the synthetic lease financing facility to which
DDII LLC is the lessee, assigned its $46.1 million remaining promissory note
receivable to the Company in exchange for cash of $46.1 million. As a result of
this assignment, the Company assumed all the rights and obligations
19
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(Unaudited)
of WestLB AG. The balance of the note receivable was $45.3 million at June 30,
2003 and is included in other current assets in the Company's condensed
consolidated balance sheets.
Also in May 2003, but subsequent to the WestLB AG assignment, the Company
purchased ConocoPhillips' 40 percent interest in DDII LLC for approximately $5.0
million. As a result of this purchase, the Company consolidated DDII LLC in the
second quarter of 2003. In addition, the Company acquired certain drilling and
other contracts from ConocoPhillips for approximately $9 million in cash.
NOTE 12 - 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 condensed
consolidated statements of operations. Through June 30, 2003, $2.1 million had
been paid representing full or partial payments to all 16 employees whose
positions were eliminated as a result of this plan. The Company released the
expected surplus liability of $0.3 million to operating and maintenance expense
in June 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 eight
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 condensed consolidated statements of
operations. Through June 30, 2003, $0.8 million had been paid representing full
or partial payments to eight 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 condensed consolidated statements of operations. Through June 30,
2003, substantially all of the $1.2 million previously established liability was
paid to 50 employees whose employment was terminated as a result of this plan.
20
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 July 31, 2003, we owned,
had partial ownership interests in or operated more than 160 mobile offshore and
barge drilling units. As of this date, our fleet included 13 fifth-generation
semisubmersibles and drillships ("floaters"), 15 other deepwater floaters, 31
mid-water floaters and 50 jackup drilling rigs. Our fleet also included 34
drilling barges, four 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"
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 floaters, 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 $90 million and $110 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 have completed our reorganization of
TODCO as
21
the entity that owns that 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. 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
as our Gulf of Mexico Shallow and Inland Water segment.
In April 2003, our deepwater drillship Peregrine I temporarily suspended
drilling operations as a result of an electrical fire requiring repairs at a
shipyard. The rig resumed operations in early July 2003. See "-Operating
Results."
In April 2003, we announced that drilling operations had ceased on four of
our mobile offshore drilling units located offshore Nigeria due to a strike by
local members of the National Union of Petroleum and Natural Gas Workers on the
semisubmersible rigs M.G. Hulme, Jr. and Sedco 709 and the jackup rigs Trident
VI and Trident VIII. All rigs have since returned to operations. We continue
negotiations to resolve the issues relating to the labor strike in Nigeria.
In May 2003, we purchased ConocoPhillips' 40 percent interest in Deepwater
Drilling II L.L.C. ("DDII LLC"). DDII LLC is the lessee in a synthetic lease
financing facility entered into in connection with the construction of the
Deepwater Frontier. As a result of this purchase, we consolidated DDII LLC in
the second quarter of 2003. See "-Special Purpose Entities, Sale/Leaseback
Transaction and Related Party Transactions."
In May 2003, we announced that a drilling riser had separated on our
deepwater drillship Discoverer Enterprise and that the rig had temporarily
suspended drilling operations for our customer. The rig has resumed operations
but we are in discussion with our customer regarding the appropriate dayrate
treatment. See "-Operating Results."
In June 2003, we incurred a loss as a result of a well blowout and fire
aboard our inland barge Rig 62. Our insurance coverage has a $12.5 million
aggregate deductible for this incident. See "-Operating Results."
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. This
discussion should be read in conjunction with disclosures included in the notes
to our condensed consolidated financial statements related to estimates,
contingencies and new accounting pronouncements. Significant accounting policies
are discussed in Note 2 to our condensed consolidated financial statements
included elsewhere and in Note 2 to our consolidated financial statements in our
Annual Report on Form 10-K for the year ended December 31, 2002. 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. Management has discussed each of these
critical accounting policies and estimates with the Audit Committee of the Board
of Directors.
Allowance for doubtful accounts-We establish reserves for doubtful accounts
on a case-by-case basis when we believe the required payment of specific amounts
owed to us is unlikely to occur. We derive a majority of our revenue from
services to international oil companies and government-owned or
government-controlled oil companies. Our
22
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. Deferred tax assets generally represent items that can be used as a
tax deduction or credit in our tax return in future years for which we have
already recorded the tax benefit in our income statement. 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. See Note 2 to our condensed
consolidated financial statements.
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
23
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
QUARTER ENDED JUNE 30, 2003 COMPARED TO QUARTER ENDED JUNE 30, 2002
Our revenues for the quarter ended June 30, 2003 decreased by $42.3 million
and our operating and maintenance expense increased by $60.9 million compared to
the quarter ended June 30, 2002. Our overall average dayrate decreased from
$78,000 for the quarter ended June 30, 2002 to $65,300 for the quarter ended
June 30, 2003, while utilization remained flat at 56 percent for each of these
periods. The decreases in our contract drilling revenue and average dayrates
were mainly attributable to the decline in overall market conditions. In
addition, our revenues, utilization and operating and maintenance expense were
negatively impacted by the labor strike in Nigeria, the riser separation
incident on the drillship Discoverer Enterprise, the well control incident on
inland barge Rig 62 and the electrical fire on the Peregrine I. 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.
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT
Three Months Ended
June 30,
----------------------------
2003 2002 Change % Change
------------ -------------- ------------- ---------
(In millions, except day amounts and percentages)
Operating days (a) 5,887.1 6,487.4 (600.3) (9.3)%
Utilization (a) (b) (d) 67.9% 78.4% N/A (13.4)%
Average dayrate (a) (c) (d) $ 88,900 $ 93,500 $ (4,600) (4.9)%
Contract drilling revenues $ 525.5 $ 609.1 $ (83.6) (13.7)%
Client reimbursable revenues 23.0 - 23.0 N/M
------------ -------------- ------------- ---------
548.5 609.1 (60.6) (9.9)%
Operating and maintenance 355.9 320.1 35.8 11.2%
Depreciation 104.4 101.4 3.0 3.0%
Impairment loss on long-lived assets 4.2 - 4.2 N/M
(Gain) loss from sale of assets, net (0.2) 1.7 (1.9) N/M
------------ -------------- ------------- ---------
Operating income before general and administrative
expense $ 84.2 $ 185.9 $ (101.7) (54.7)%
============ ============== ============= =========
_________________
"N/A" means not applicable
"N/M" means not meaningful
(a) Applicable to all rigs.
24
(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.
Lower average dayrates and utilization resulted in a decrease in this
segment's contract drilling revenues of approximately $68.0 million, excluding
the impact of the items discussed separately below. Contract drilling revenues
were also adversely impacted by approximately $22.0 million due to the labor
strike in Nigeria, the riser separation incident on the Discoverer Enterprise
and the electrical fire on the Peregrine I. Decreases also resulted from the
sale of a rig and a leased rig returned to its owner during or subsequent to the
second quarter of 2002 ($2.8 million). These decreases were partially offset by
increases in contract drilling revenues from a rig transferred into this segment
from the Gulf of Mexico Shallow and Inland Water segment during the second
quarter of 2002 ($4.7 million) and from the Deepwater Frontier ($4.8 million),
as a result of the consolidation of DDII LLC. See "-Overview."
Operating revenues for the three months ended June 30, 2003 included $23.0
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 higher shipyard and maintenance expenses, including $5.2
million in costs associated with the riser separation incident on the Discoverer
Enterprise. Rig hire expense increased by $2.2 million resulting from the
consolidation of DDII LLC, which leases the Deepwater Frontier. We also incurred
additional expense in the second quarter of 2003 resulting from the transfer of
a jackup rig into this segment from the Gulf of Mexico Shallow and Inland Water
segment during the second quarter of 2002 ($2.7 million), costs incurred related
to the labor strike in Nigeria ($2.6 million), costs incurred related to the
electrical fire on the Peregrine I ($2.2 million) and an increase in allowance
for doubtful accounts related to two client receivables ($4.5 million). In
addition, expenses increased due to additional costs incurred and recognized as
operating and maintenance expense relating to client reimbursable expenses as a
result of implementing EITF 99-19 in 2003 (see "-Overview"). Partially
offsetting these increases were decreased operating and maintenance expenses
resulting from rigs sold or returned to owner during and subsequent to the
second quarter of 2002 ($2.4 million). We also recognized a $4.1 million release
of a litigation reserve in the second quarter of 2003 relating to the settlement
of a dispute.
The increase in this segment's depreciation expense resulted primarily from
the transfer of a rig from the Gulf of Mexico Shallow and Inland Water segment
into this segment and depreciation expense related to assets reclassified from
held for sale to our active fleet because they no longer met the criteria for
assets held for sale under SFAS 144 during and subsequent to the three months
ended June 30, 2002. These increases were partially offset by lower depreciation
expense following the sale of a rig classified as held and used during the
second quarter of 2002.
During the three months ended June 30, 2003, we recorded non-cash
impairment charges of $4.2 million related to assets held and used in this
segment, which resulted from our decision to remove one mid-water
semisubmersible rig and one self-erecting tender rig from drilling service. The
impairment was determined and measured based on an estimate of fair value
derived from an offer from a potential buyer.
25
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT
Three Months Ended
June 30,
---------------------------
2003 2002 Change % Change
------------ ------------- ------------- ---------
(In millions, except day amounts and percentages)
Operating days (a) 2,918.7 1,765.7 1,153.0 65.3%
Utilization (a) (b) (d) 42.2% 27.0% N/A 56.3%
Average dayrate (a) (c) (d) $ 17,500 $ 21,000 $ (3,500) (16.7)%
Contract drilling revenues $ 51.1 $ 37.1 $ 14.0 37.7%
Client reimbursable revenues 4.3 - 4.3 N/M
------------ ------------- ------------- ---------
55.4 37.1 18.3 49.3%
Operating and maintenance 70.6 45.5 25.1 55.2%
Depreciation 23.1 22.9 0.2 0.9%
Impairment loss on long-lived assets 11.6 - 11.6 N/M
Gain from sale of assets, net (0.4) (0.4) - N/M
------------ ------------- ------------- ---------
Operating loss before general and administrative
expense $ (49.5) $ (30.9) $ (18.6) (60.2)%
============ ============= ============= =========
_________________
"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.
Higher utilization resulted in an increase in this segment's contract
drilling revenues of $25.7 million, partially offset by decreased average
dayrates ($10.4 million) and the transfer of a jackup rig from this segment into
the International and U.S. Floater Contract Drilling Services segment during the
second quarter of 2002 ($1.4 million).
Operating revenues for the three months ended June 30, 2003 included $4.3
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 costs associated with the well control incident on inland barge
Rig 62 ($7.2 million), an increase in insurance expense ($2.4 million) and an
increase in activity ($11.9 million). In addition, operating and maintenance
expenses increased due to costs incurred and recognized as operating and
maintenance expense relating to client reimbursable expenses as a result of
implementing EITF 99-19 during 2003 (see "-Overview"). Partially offsetting the
above increases was a decrease resulting from the transfer of a jackup rig from
this segment into the International and U.S. Floater Contract Drilling Services
segment in the second quarter of 2002 ($1.1 million).
During the three months ended June 30, 2003, we recorded a non-cash
impairment charge of $10.6 million in this segment, which resulted from our
decision to take five jackup rigs out of drilling service and market the rigs
for alternative uses. We do not anticipate returning these rigs to drilling
service, as we believe it would be cost prohibitive.
26
As a result of this decision, and in accordance with SFAS 144, the carrying
value of these assets was adjusted to fair market value. The fair market values
of these units as non-drilling rigs were based on third party valuations. During
the three months ended June 30, 2003, we also recorded a non-cash impairment
charge of $1.0 million in this segment, which resulted from our determination
that the fair value of the assets of an entity in which we have an investment
did not support our carrying value. The impairment was determined and measured
based on the remaining book value of our investment and our assessment of the
fair value of that investment at the time the decision was made.
TOTAL COMPANY RESULTS OF OPERATIONS
Three Months Ended
June 30,
------------------------
2003 2002 Change % Change
----------- ----------- -------- ---------
(In millions, except % change)
General and Administrative Expense $ 14.9 $ 16.0 $ (1.1) (6.9)%
Other (Income) Expense, net
Equity in earnings of joint ventures (1.8) (2.5) 0.7 (28.0)%
Interest income (5.8) (5.7) (0.1) 1.8%
Interest expense 52.8 52.5 0.3 (0.6)%
Loss on retirement of debt 15.7 - 15.7 N/M
Loss on impairment of note receivable from related party 21.3 - 21.3 N/M
Other, net 2.7 0.4 2.3 N/M
Income Tax Expense (Benefit) (20.8) 13.9 (34.7) N/M
_________________
"N/M" means not meaningful
The decrease in general and administrative expense was attributable to
decreased personnel expenses of $1.2 million primarily due to lower pension
expense in 2003 and an adjustment to cash surrender value of executive life
insurance.
The decrease in equity in earnings of joint ventures was primarily related
to our 25 percent share of losses from Delta Towing Holdings, LLC ("Delta
Towing"), which included our share of a $2.5 million non-cash impairment charge
on the carrying value of idle equipment recorded by the joint venture.
Offsetting the decrease was our 60 percent share of earnings of DDII LLC, which
leases the Deepwater Frontier. The rig experienced increased utilization and
average dayrates during the two month period ended May 31, 2003, at which time
we completed the buyout of ConocoPhillips' 40 percent interest in the joint
venture, compared to the three months ended June 30, 2002. The increase in
interest income was primarily due to interest earned on higher average cash
balances for the three months ended June 30, 2003 compared to the same period in
2002. The increase in interest expense was primarily due to the termination of
our fixed to floating interest rate swaps in the first quarter of 2003, which
resulted in an increase of $13.5 million, partially offset by reductions in
interest expense of $6.5 million related to the recognition of the gain from the
termination of the interest rate swaps (see "-Derivative Instruments"). Debt
repaid or retired during and subsequent to the three months ended June 30, 2002
resulted in an additional $6.8 million reduction in interest expense.
During the three months ended June 30, 2003, we recognized a $15.7 million
loss on early retirements of debt as more fully described in Note 3 to our
condensed consolidated financial statements.
During the three months ended June 30, 2003, we recorded a $21.3 million
impairment of the notes receivable due from Delta Towing as more fully described
in Note 11 to our condensed consolidated financial statements.
We recognized a $2.3 million loss in other, net relating to the revaluation
of a local currency into functional U.S dollars for the three months ended June
30, 2003 (see "-Item 3. Quantitative and Qualitative Disclosures about Market
Risk-Foreign Exchange Risk").
27
We operate internationally and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected relationship between the provision for income taxes and income before
income taxes. The three months ended June 30, 2003 included a tax benefit of
$14.6 million attributable to the favorable resolution of a non-U.S. income tax
liability and income tax benefits resulting from non-cash impairments and loss
on debt retirements. As a result of the deterioration in 2003 profitability, our
annual effective tax rate is now estimated to be approximately 38 percent during
2003 on earnings before asset impairments, notes receivable impairment and loss
on debt retirements. Due to this change in estimate from approximately 20
percent at March 31, 2003, earnings for the three months ended June 30, 2003
were reduced by $10.7 million as a result of applying the adjusted estimated
annual effective tax rate to the three months ended March 31, 2003.
SIX MONTHS ENDED JUNE 30, 2003 COMPARED TO SIX MONTHS ENDED JUNE 30, 2002
Our revenues for the six months ended June 30, 2003 decreased by $94.2
million and our operating and maintenance expense increased by $54.0 million
compared to the six months ended June 30, 2002. In addition, our overall average
dayrate and utilization decreased from $75,100 and 59 percent, respectively, for
the six months ended June 30, 2002 to $67,100 and 56 percent for the six months
ended June 30, 2003. The decreases in our revenue and average dayrates were
mainly attributable to the decline in overall market conditions. In addition,
our contract drilling revenues, utilization and operating and maintenance
expense were negatively impacted by the labor strike in Nigeria, the riser
separation incident on the drillship Discoverer Enterprise, the well control
incident on inland barge Rig 62 and the electrical fire on the Peregrine I.
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.
Six Months Ended
June 30,
------------------------------
2003 2002 Change % Change
------------------ ---------- ---------- ---------
(In millions, except day amounts and percentages)
Operating days (a) 11,769.4 13,371.3 (1,601.9) (12.0)%
Utilization (a) (b) (d) 68.3% 80.2% N/A (14.8)%
Average dayrate (a) (c) (d) $ 90,300 $ 91,800 $ (1,500) (1.6)%
Contract drilling revenues $ 1,066.6 $ 1,232.3 $ (165.7) (13.4)%
Client reimbursable revenues 44.6 - 44.6 N/M
------------------ ---------- ---------- ---------
1,111.2 1,232.3 (121.1) (9.8)%
Operating and maintenance 671.4 648.8 22.6 3.5%
Depreciation 208.0 203.7 4.3 2.1%
Impairment loss on long-lived assets 5.2 - 5.2 N/M
Gain from sale of assets, net (1.6) (1.0) (0.6) 60.0%
------------------ ---------- ---------- ---------
Operating income before general and administrative expense $ 228.2 $ 380.8 $ (152.6) (40.1)%
================== ========== ========== =========
_________________
"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.
28
(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.
Lower average dayrates and utilization resulted in a decrease in this
segment's contract drilling revenues of approximately $144.0 million, excluding
the impact of the items discussed separately below. Contract drilling revenues
were also adversely impacted by approximately $22.0 million due to the labor
strike in Nigeria, the riser separation incident on the Discoverer Enterprise
and the electrical fire on the Peregrine I. Additional decreases resulted from
the sale of rigs ($7.9 million), the return of a leased rig to its owner ($2.8
million) and the transfer of a jackup rig from this segment to the Gulf of
Mexico Shallow and Inland Water segment ($2.1 million) during 2002. These
decreases were partially offset by increases in contract drilling revenue from a
rig transferred into this segment from the Gulf of Mexico Shallow and Inland
Water segment during the second quarter of 2002 ($9.3 million) and from the
Deepwater Frontier ($4.2 million), as a result of the consolidation of DDII LLC.
See "-Overview."
Operating revenues for the six months ended June 30, 2003 included $44.6
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 increase in this segment's operating and maintenance expense was
primarily due to higher shipyard and maintenance expenses, including $5.2
million in costs associated with the riser separation incident on the Discoverer
Enterprise. Rig hire expenses increased by $2.2 million resulting from the
consolidation of DDII LLC, which leases the Deepwater Frontier. We also incurred
additional expense in 2003 resulting from the transfer of a jackup rig into this
segment from the Gulf of Mexico Shallow and Inland Water segment during the
second quarter of 2002 ($5.3 million), costs incurred related to the labor
strike in Nigeria ($2.6 million), costs incurred related to the electrical fire
on the Peregrine I ($2.2 million) and an increase in allowance for doubtful
accounts related to two client receivables ($4.5 million). In addition, expenses
increased due to additional costs incurred and recognized as operating and
maintenance expense relating to client reimbursable expenses as a result of
implementing EITF 99-19 in 2003 (see "-Overview"). Partially offsetting these
increases were decreased operating and maintenance expenses resulting from rigs
sold ($6.2 million) or returned to owner ($2.6 million) during and subsequent to
the six months ended June 30, 2002. We also recognized a $4.1 million release of
a litigation reserve in the second quarter of 2003 relating to the settlement of
a dispute and a $2.6 million expense reduction from the settlement of an
insurance claim during the six months ended June 30, 2003.
The increase in this segment's depreciation expense resulted primarily from
the transfer of a rig from the Gulf of Mexico Shallow and Inland Water segment
into this segment and depreciation expense related to assets reclassified from
held for sale to our active fleet because they no longer met the criteria for
assets held for sale under SFAS 144 during and subsequent to the six months
ended June 30, 2002. These increases were partially offset by lower depreciation
expense following the sale of rigs classified as held and used during and
subsequent to the six months ended June 30, 2002.
During the six months ended June 30, 2003, we recorded a non-cash
impairment charge of $4.2 million related to assets held and used in this
segment, which resulted from our decision to remove one mid-water
semisubmersible rig and one self-erecting tender rig from drilling service. The
impairment was determined and measured based on an estimate of fair value
derived from an offer from a potential buyer. During the six months ended June
30, 2003, we also recorded a non-cash impairment charge of $1.0 million in this
segment, which resulted from our decision to discontinue the leases on our oil
and gas properties. The impairment was determined and measured based on the
carrying value of the leases at the time the decision was made.
29
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT
Six Months Ended
June 30,
--------------------------------
2003 2002 Change % Change
------------------ ------------ ------------ ------------
(In millions, except day amounts and percentages)
Operating days (a) 5,540.7 4,047.0 1,493.7 36.9%
Utilization (a) (b) (d) 40.3% 30.9% N/A 30.4%
Average dayrate (a) (c) (d) $ 18,000 $ 20,200 (2,200) (10.9)%
%
Contract drilling revenues $ 99.6 $ 81.8 17.8 21.8%
Client reimbursable revenues 9.1 - 9.1 N/M
------------------ ------------ ------------ ------------
108.7 81.8 26.9 32.9%
Operating and maintenance 129.2 97.8 31.4 32.1%
Depreciation 46.3 46.2 0.1 0.2%
Impairment loss on long-lived assets 11.6 1.1 10.5 N/M
(Gain) loss from sale of assets, net (0.4) 0.4 (0.8) N/M
------------------ ------------ ------------ ------------
Operating loss before general and administrative
expense $ (78.0) $ (63.7) (14.3) (22.4)%
================== ============ ============ ============
_________________
"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.
Higher utilization resulted in an increase in this segment's contract
drilling revenue of $34.5 million, partially offset by decreased average
dayrates ($14.7 million) and the transfer of a jackup rig from this segment into
the International and U.S. Floater Contract Drilling Services segment and rigs
sold during the six months ended June 30, 2002 ($2.0 million).
Operating revenues for the six months ended June 30, 2003 included $9.1
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 due
primarily to costs associated with the well control incident on inland barge Rig
62 ($7.2 million) and an increase in activity of approximately $15.0 million. In
addition, operating and maintenance expenses increased due to costs incurred and
recognized as operating and maintenance expense relating to client reimbursable
expenses as a result of implementing EITF 99-19 during the six months ended June
30, 2003 (see "-Overview"). Operating and maintenance expenses also increased
due to an insurance claim provision ($2.5 million). These increases were
partially offset by the release of a provision for doubtful accounts ($1.8
million) during the first six months of 2003 upon collection of amounts
previously reserved and by lower expenses resulting from the transfer of a
jackup rig from this segment into the International and U.S. Floater Contract
Drilling Services segment ($1.9 million) during the second quarter of 2002.
30
During the six months ended June 30, 2003, we recorded a non-cash
impairment charge of $10.6 million in this segment, which resulted from our
decision to take five jackup rigs out of drilling service and market the rigs
for alternative uses. We do not anticipate returning these rigs to drilling
service as we believe it would be cost prohibitive. As a result of this
decision, and in accordance with SFAS 144, the carrying value of these assets
was adjusted to fair market value. The fair market value of these units as
non-drilling rigs were based on third party valuations. During the six months
ended June 30, 2003, we also recorded a non-cash impairment charge of $1.0
million in this segment, which resulted from our determination that the assets
of an entity in which we have an investment did not support our carrying value.
The impairment was determined and measured based on the remaining book value of
our investment and our assessment of the fair value of that investment at the
time the decision was made. During the six months ended June 30, 2002, we
recorded a non-cash impairment charge of $1.1 million related to an asset held
for sale in this segment, 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.
TOTAL COMPANY RESULTS OF OPERATIONS
Six Months Ended
June 30,
--------------------------------
2003 2002 Change % Change
------------------ ------------ ------------- ------------
(In millions, except % change)
General and Administrative Expense $ 28.8 $ 35.8 $ (7.0) (19.6)%
Other (Income) Expense, net
Equity in earnings of joint ventures (5.4) (4.4) (1.0) 22.7%
Interest income (12.7) (9.9) (2.8) 28.3%
Interest expense 105.4 108.4 (3.0) (2.8)%
Loss on retirement of debt 15.7 - 15.7 N/M
Loss on impairment of note receivable from related party 21.3 - 21.3 N/M
Other, net 3.3 1.1 2.2 N/M
Income Tax Expense (Benefit) (9.0) 27.7 (36.7) N/M
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 $4.4 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
$2.2 million primarily due to lower pension expense in 2003, a one-time
curtailment gain related to retiree life insurance and an adjustment to cash
surrender value of executive life insurance.
The increase in equity in earnings of joint ventures was primarily related
to our 60 percent share of the earnings of DDII LLC, which leases the Deepwater
Frontier. This rig experienced increased utilization during the five months
ended May 31, 2003, at which time we completed the buyout of ConocoPhillips' 40
percent interest in DDII LLC, compared to the first six months of 2002, due to
shipyard downtime in 2002. Offsetting the increase in equity in earnings of
joint ventures was our 25 percent share of losses from Delta Towing, which
included our share of a $2.5 million non-cash impairment charge on the carrying
value of idle equipment recorded by the joint venture. The increase in interest
income was primarily due to interest earned on higher average cash balances for
the six months ended June 30, 2003 compared to the same period in 2002. The
decrease in interest expense was attributable to reductions of interest expense
of $8.1 million associated with debt refinanced, repaid or retired during and
subsequent to June 30, 2002. We also received a refund of interest in 2003 from
a taxing authority compared to an interest payment in 2002 that resulted in a
reduction in interest expense of $1.8 million. We terminated our fixed to
floating interest rate swaps in the first quarter of 2003, which resulted in an
increase in interest expense of $17.1 million,
31
partially offset by a $10.0 million decrease in interest expense related to the
recognition of the gain from the termination of these interest rate swaps (see
"-Derivative Instruments").
During the six months ended June 30, 2003, we recognized a $15.7 million
loss on early retirements of debt as more fully described in Note 3 to our
condensed consolidated financial statements.
During the six months ended June 30, 2003, we recorded a $21.3 million
impairment of the notes receivable due from Delta Towing as more fully described
in Note 11 to our condensed consolidated financial statements.
We recognized a $2.3 million loss in other, net relating to the revaluation
of a local currency into functional U.S dollars for the six months ended June
30, 2003 (see "-Item 3. Quantitative and Qualitative Disclosures about Market
Risk-Foreign Exchange Risk").
We operate internationally and provide for income taxes based on the tax
laws and rates in the countries in which we operate and earn income. There is no
expected relationship between the provision for income taxes and income before
income taxes. The six months ended June 30, 2003 included a tax benefit of $14.6
million attributable to the favorable resolution of a non-U.S. income tax
liability and income tax benefits resulting from non-cash impairments and loss
on debt retirements, partially offset by an increase in the estimated annual
effective tax rate for the six months ended June 30, 2003 to approximately 38
percent of earnings before asset impairments, notes receivable impairment and
loss on debt retirements compared to approximately 15 percent for the comparable
period in 2002.
During the six months ended June 30, 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.
FINANCIAL CONDITION
June 30, December 31, %
2003 2002 Change Change
--------- ------------- -------- -------
(In millions)
TOTAL ASSETS
International and U.S. Floater Contract Drilling Services $10,913.8 $ 11,804.1 $(890.3) (7.5)%
Gulf of Mexico Shallow and Inland Water 792.0 861.0 (69.0) (8.0)%
--------- ------------- -------- -------
$11,705.8 $ 12,665.1 $(959.3) (7.6)%
========= ============= ======== =======
The decrease in the assets of the International and U.S. Floater Contract
Drilling Services segment was mainly due to a decrease in cash and cash
equivalents ($514.5 million) that resulted primarily from the repayment of debt
during 2003 (see Note 3 to our condensed consolidated financial statements).
Also contributing to the decrease in this segment's assets was a reduction in
other assets primarily due to the termination of interest rate swaps ($181.3
million) during 2003 (see Note 6 to our condensed consolidated financial
statements). In addition, the sale of a jackup rig ($18.0 million net book
value), normal depreciation ($208.0 million) and asset impairments ($5.2
million) during 2003 further reduced the assets in this segment (see Note 8 to
our condensed consolidated financial statements). The decrease in the assets of
the Gulf of Mexico Shallow and Inland Water segment was primarily due to normal
depreciation ($46.3 million) and asset impairments ($11.6 million) and the
impairment of a related party note receivable ($21.3 million) during 2003 (see
Notes 8 and 11 to our condensed consolidated financial statements).
32
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 condensed consolidated
statements of operations. As of June 30, 2003, $2.1 million had been paid
representing full or partial payments to all 16 employees whose positions were
eliminated as a result of this plan. We released the expected surplus liability
of $0.3 million to operating and maintenance expense in June 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 eight 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
condensed consolidated statements of operations. As of June 30, 2003, $0.8
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 condensed
consolidated statements of operations. As of June 30, 2003, substantially all of
the $1.2 million previously established liability was paid to 50 employees whose
employment was terminated as a result of this plan.
33
OUTLOOK
Fleet utilization and average dayrates decreased within our International
and U.S. Floater Contract Drilling Services business segment during the second
quarter of 2003 compared with the first quarter of 2003. Within our Gulf of
Mexico Shallow and Inland Water business segment fleet utilization increased
slightly and average dayrates decreased during the second quarter of 2003
compared with the first quarter of 2003.
Comparative average dayrates and utilization figures are set forth in the
table below.
Three Months Ended
---------------------------------------------
June 30, March 31, June 30,
2003 2003 2002
--------------- ---------------- ----------
AVERAGE DAYRATES (A)(B)(D)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation $ 185,100 $ 183,800 $ 188,400
Other Deepwater $ 111,500 $ 113,600 $ 124,300
Total Deepwater $ 147,500 $ 147,500 $ 152,200
Mid-Water $ 73,600 $ 77,200 $ 81,300
Jackups - Non-U.S. $ 57,400 $ 56,900 $ 57,400
Other Rigs $ 41,500 $ 43,200 $ 40,400
--------------- ---------------- ----------
Segment Total $ 88,900 $ 91,600 $ 93,500
--------------- ---------------- ----------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles $ 18,200 $ 19,700 $ 20,200
Inland Barges $ 16,100 $ 17,600 $ 20,200
Other Rigs $ 18,600 $ 19,000 $ 24,100
--------------- ---------------- ----------
Segment Total $ 17,500 $ 18,500 $ 21,000
--------------- ---------------- ----------
Total Mobile Offshore Drilling Fleet $ 65,300 $ 69,100 $ 78,000
=============== ================ ==========
UTILIZATION (A)(C)(D)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation 88% 97% 89%
Other Deepwater 70% 76% 85%
Total Deepwater 78% 85% 87%
Mid-Water 55% 53% 72%
Jackups - Non-U.S. 86% 87% 82%
Other Rigs 41% 36% 64%
--------------- ---------------- ----------
Segment Total 68% 69% 78%
--------------- ---------------- ----------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles 44% 31% 27%
Inland Barges 39% 47% 24%
Other Rigs 44% 35% 37%
--------------- ---------------- ----------
Segment Total 42% 38% 27%
--------------- ---------------- ----------
Total Mobile Offshore Drilling Fleet 56% 55% 56%
=============== ================ ==========
_________________
(a) Applicable to all rigs.
34
(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.
Commodity prices have continued at relatively strong levels during 2003.
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 with the exception of Mexico and India where
activity continues to increase.
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 West
Africa 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 demand for deepwater rigs in India are
positive developments supporting long-term deepwater activity.
The non-U.S. jackup market sector remains strong despite some current idle
capacity in West Africa, 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 we have seen 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. Dayrates for shallow water jackups have strengthened
marginally and the demand for jackups in Mexico and India should continue to
indirectly help this sector as rigs leave the U.S. Gulf of Mexico for these
countries. The inland barge drilling market continues to be soft and
industry-wide utilization has decreased since the beginning of 2003.
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 May 2003, we purchased ConocoPhillips' 40 percent interest in DDII LLC.
DDII LLC is the lessee in a synthetic lease financing facility entered into in
connection with the construction of the Deepwater Frontier. As a result of this
purchase, we consolidated DDII LLC during the second quarter of 2003. Pursuant
to the lease financings, the rig is owned by a special purpose entity and leased
to DDII LLC. In July 2003, the value of the rig and the debt and equity
financing associated with the lease will 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, an
Interpretation of Accounting Research Bulletin No. 51. We expect the amount of
the rig and debt and equity financing to be reflected on our balance sheet to be
approximately $207 million and $162 million, respectively. See "-Special Purpose
Entities, Sale/Leaseback Transaction and Related Party Transactions."
During the quarter ended June 30, 2003, we deferred costs primarily related
to mobilizations and contract preparation of $19.7 million and recognized
amortization expense of previously deferred mobilization and contract
preparation costs of $26.8 million. We expect to defer approximately $31 million
in mobilization and contract preparation costs and to amortize to expense
approximately $26 million in the third 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
35
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 a result of the deterioration in
2003 profitability, our annual effective tax rate is now estimated to be
approximately 38 percent for 2003, excluding the income tax benefit attributable
to the favorable resolution of a non-U.S. income tax liability, the non-cash
asset impairments and the loss on retirements of debt.
We previously reported that we expected to begin making annual
contributions to our qualified defined benefit pension plans (the "Retirement
Plans") in 2003 of approximately $11 million and that we expected pension
expense related to these plans to increase by approximately $7 million in 2003
as compared to 2002. Based on the most recent actuarial valuations received, we
now expect to make no annual contribution to the Retirement Plans in 2003. Also,
we expect the required contribution to the Retirement Plans in 2004 to be
approximately $5 million and pension expense related to these plans to increase
by approximately $1 million in 2003 compared to 2002. Continued poor performance
in the equity markets and significant plan changes could result in additional
significant changes to the accumulated other comprehensive loss component of
shareholders' equity and additional increases in future pension expense and
funding requirements.
As of July 29, 2003, approximately 58 percent and 32 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 10
percent for the remainder of 2003 and five percent is currently committed for
the year 2004.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES AND USES OF CASH
Six Months Ended June 30,
--------------------------------
2003 2002 Change
-------------- ---------------- ----------
(In millions)
NET CASH PROVIDED BY OPERATING ACTIVITIES
Net income (loss) $ 2.7 $ (1,206.4) $ 1,209.1
Depreciation 254.3 249.9 4.4
Other non-cash items 6.3 1,338.0 (1,331.7)
Changes in working capital items 41.9 (1.0) 42.9
-------------- ---------------- ----------
$ 305.2 $ 380.5 $ (75.3)
============== ================ ==========
Cash generated from net income items adjusted for non-cash activity
decreased $118.2 million. Cash provided by working capital items increased $42.9
million due to lower revenue resulting in a reduction in accounts receivable
coupled with an increase in net interest payable due to the termination of our
interest rate swaps in the first quarter of 2003 (see "- Derivative
Instruments"), partially offset by a decrease in income tax payable.
36
Six Months Ended June 30,
---------------------------------
2003 2002 Change
--------------- ---------------- --------
(In millions)
NET CASH USED IN INVESTING ACTIVITIES
Capital expenditures $ (50.2) $ (81.2) $ 31.0
Note issued to related party, net of repayments (45.3) - (45.3)
Proceeds from disposal of assets 3.2 65.0 (61.8)
Acquisition of 40% interest in DDII LLC, net of cash acquired 18.1 - 18.1
Other, net 2.2 - 2.2
--------------- ---------------- --------
$ (72.0) $ (16.2) $ (55.8)
=============== ================ ========
Net cash used in investing activities increased for the six months ended
June 30, 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"). A note receivable of $46.1 million was issued to a related party
and we acquired ConocoPhillips' 40 percent interest in DDII LLC in May 2003 (see
Note 11 to our condensed consolidated financial statements).
Six Months Ended June 30,
---------------------------------
2003 2002 Change
--------------- ---------------- --------
(In millions)
NET CASH 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 (919.2) (119.6) (799.6)
Other, net 12.3 (15.8) 28.1
--------------- ---------------- --------
$ (733.4) $ (461.8) $(271.6)
=============== ================ ========
We repaid $326.4 million under our commercial paper program during the six
months ended June 30, 2002 while no such payment was made for the same period in
2003. For the six months ended June 30, 2003, we received interest rate swap
termination proceeds of $173.5 million (see "-Derivative Instruments"). In 2003,
we used cash of $527.2 million to repurchase our Zero Coupon Convertible
Debentures that were put to us in May 2003, $50.0 million for the early
repayment of our 9.41% Nautilus Class A2 Notes, and $342.0 million for other
scheduled debt maturities. This compares to cash paid of $50.6 million for the
early repayment of secured rig financing on the Trident IX and Trident 16 and
$69.0 million for other scheduled debt maturities in 2002. The increase in cash
provided in other, net is due to $8.3 million in consent payments in 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 issuance of shares to the Employee Share
Purchase Program. Additionally, dividends of $19.1 million were paid in the six
months ended June 30, 2002. Payment of dividends was discontinued after the
second quarter of 2002.
CAPITAL EXPENDITURES
Capital expenditures totaled $50.2 million during the six months ended June
30, 2003. During 2003, we expect to spend between $140.0 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.
37
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 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 six months ended June 30, 2003, we settled an insurance claim
and sold certain other assets for net proceeds of approximately $3.2 million and
recorded net after-tax gains of $1.4 million in our International and U.S.
Floater Contract Drilling Services segment and $0.2 million in our Gulf of
Mexico Shallow and Inland Water 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 have completed our reorganization of 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 second quarter of 2003 were our
cash flows from operations and existing cash balances. The primary use of cash
was debt repayment. At June 30, 2003, we had $714.0 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. See Note 3 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.
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 June 30, 2003 and December 31, 2002, our total debt was $3,758.3
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 six months ended June 30, 2003, we reduced
net debt, defined as total debt less swap receivables and cash and cash
equivalents, by $238.2 million. The components of net debt at carrying value
were as follows (in millions):
June 30, December 31,
2003 2002
---------- --------------
Total Debt $ 3,758.3 $ 4,678.0
Less: Cash and cash equivalents (714.0) (1,214.2)
Swap receivables - (181.3)
38
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 June 30, 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 fair value adjustments attributable to current or
terminated interest rate swaps as well as 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 June 30, 2003, $1.6 billion in gross proceeds of securities
remained unissued under the shelf registration statement.
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 June 30,
----------------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
-------- ------- -------------- ---------- -----------
(In millions)
CONTRACTUAL OBLIGATIONS
Debt $3,567.5 $ 281.2 $ 867.3 $ 369.0 $ 2,050.0
======== ======= ============== ========== ===========
The bondholders may, at their option, require us to repurchase the 1.5%
Convertible Debentures due 2021, the 7.45% Notes due 2027 and the Zero Coupon
Convertible Debentures due 2020 in May 2006, April 2007 and May 2008,
respectively. With regard to both series of the Convertible Debentures, we have
the option to pay the repurchase price in cash, ordinary shares, or any
combination of cash and ordinary shares. The chart above assumes that the
holders of these Convertible Debentures and notes exercise the options at the
first available date. We are also required
39
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.
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.
At June 30, 2003, we had other commitments that we are contractually
obligated to fulfill with cash should the obligations be called. These
obligations include standby letters of credit and surety bonds that guarantee
our performance as it relates to our drilling contracts, insurance, tax and
other obligations in various jurisdictions. 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.
We currently expect to use cash on hand to repay our portion of the debt
and equity financing with respect to Deepwater Drilling L.L.C. ("DD LLC") and
the related purchase option guarantees-joint venture and all of the debt and
equity financing with respect to DDII LLC and the purchase option
guarantees-related party included in the table below. We could, however, decide
to finance these amounts with new debt.
For the twelve months ending June 30,
----------------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
-------- ------- -------------- ---------- -----------
(In millions)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit $ 78.7 $ 65.2 $ 6.3 $ 7.2 $ -
Surety Bonds 159.6 96.5 63.1 - -
Purchase Option Guarantees- Related Party (a) 151.8 151.8 - - -
Purchase Option Guarantees- Joint Ventures (a) 92.6 92.6 - - -
Other Commitments 0.1 - 0.1 - -
-------- ------- -------------- ---------- -----------
Total $ 482.8 $ 406.1 $ 69.5 $ 7.2 $ -
======== ======= ============== ========== ===========
____________________________
(a) See "-Special Purpose Entities, Sale/Leaseback Transaction and Related Party Transactions".
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 6 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 recognized 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, entered into interest rate swaps in August 1998 that have
aggregate market values netting to a liability of $2.9 million at June 30, 2003.
Our interest in these swaps has been included in accumulated other comprehensive
income, net of tax, with
40
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 failed to make its scheduled quarterly
interest payment of $1.7 million on the notes receivable and we signed a 90-day
waiver of the terms requiring payment of interest. In April 2003, Delta Towing
again failed to make its interest payment of $1.7 million originally due January
2003 after expiration of the 90-day waiver. In April 2003, Delta Towing also
failed to make another scheduled quarterly interest payment of $1.6 million.
During the six months ended June 30, 2003, we received partial interest payments
of approximately $0.6 million. At June 30, 2003, we had interest receivable from
Delta Towing of $4.3 million. As a result of our continued evaluation of the
collectibility of the Delta Towing notes, we recorded an impairment on the notes
receivable of $13.8 million ($0.04 per diluted share), net of tax of $7.5
million, in the second quarter of 2003 as an allowance for credit losses. We
based the impairment on Delta Towing's discounted projected cash flows over the
term of the notes, which deteriorated in the second quarter of 2003 as a result
of the continued decline in Delta Towing's business outlook. The amount of the
notes receivable outstanding prior to the impairment was $82.8 million. At June
30, 2003, the carrying value of the notes receivable, net of the related
allowance for credit losses, was $54.8 million. We will establish a reserve for
interest income earned on the notes receivable and will apply cash payments to
interest receivable currently outstanding and then to interest income for which
a reserve has been established.
In May 2003, WestLB AG, one of the lenders in the synthetic lease financing
facility to which DDII LLC is the lessee, assigned its $46.1 million remaining
promissory note receivable to us in exchange for cash. As a result of this
assignment, we assumed all the rights and obligations of WestLB AG. At June 30,
2003, the balance of the note receivable was $45.3 million and was recorded as
other current assets in our condensed consolidated balance sheets.
Also in May 2003, but subsequent to the WestLB AG assignment, we purchased
ConocoPhillips' 40 percent interest in DDII LLC for approximately $5 million. As
a result of this purchase, we consolidated DDII LLC in the second quarter of
2003. In addition, we acquired certain drilling and other contracts from
ConocoPhillips for approximately $9 million. See "-New Accounting
Pronouncements."
There have been no other material developments with regards to the special
purpose entity related to DD LLC, the sale/leaseback transaction or other
related party transactions.
NEW ACCOUNTING PRONOUNCEMENTS
In January 2003, the FASB issued FIN 46, Consolidation of Variable Interest
Entities, an Interpretation of Accounting Research Bulletin No. 51 (the
"Interpretation"). The Interpretation requires the consolidation of entities in
which an enterprise absorbs a majority of the entity's expected losses, receives
a majority of the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the entity. The
Interpretation is effective as of the beginning of the first interim period
beginning after June 15, 2003 for existing interests and immediately for new
interests. Currently, we generally consolidate an entity when we have a
controlling interest through ownership of a majority voting interest in the
entity.
We have investments in and advances to six joint ventures. One joint
venture, DD LLC, was established for the purpose of constructing and leasing a
drillship. One joint venture, Delta Towing, was established for the purpose of
owning and operating inland and shallow water marine support vessel equipment.
The remaining four joint ventures were primarily established for the purpose of
owning and operating certain drilling units. While the operations of DD LLC are
funded from cash flows from operating activities, we guarantee the debt and
equity financing on the drillship equally with our joint venture partner. The
debt and equity financing balance for the leased drillship was $192.6
41
million at August 1, 2003. We hold notes receivable from Delta Towing with a
carrying value of $54.7 million at August 1, 2003. The remaining joint ventures
are funded primarily by cash flows from operating activities.
We account for these investments using the equity method of accounting,
recording our share of the net income or loss based upon the terms of the joint
venture agreements. Because we have a 50 percent or less ownership interest in
these joint ventures, we do not have a controlling interest in the joint
ventures nor do we have the ability to exercise significant influence over
operating and financial policies.
At the time the Delta Towing joint venture was formed, it issued $144.0
million in notes to TODCO. Prior to the R&B Falcon merger, $64.0 million of the
notes were fully reserved leaving an $80.0 million balance at January 31, 2001.
This note agreement was subsequently amended to provide for a $4.0 million,
three-year revolving credit facility. Delta Towing's assets serve as collateral
for our notes receivable. The Delta Towing joint venture also issued a $3.0
million note to the 75 percent joint venture partner. Because we have the
largest percentage of investment at risk through the notes receivable, we will
absorb the majority of the joint venture's expected losses and, therefore, we
are deemed to be the primary beneficiary of Delta Towing for accounting
purposes. As such, we will consolidate Delta Towing effective July 1, 2003. We
expect the consolidation of Delta Towing to result in an increase in current
assets of approximately $5.0 million, an increase in property and equipment, net
of approximately $55.0 million, a decrease in investments in and advances to
joint ventures of approximately $55.0 million, an increase in current
liabilities of approximately $1.0 million and an increase in long-term debt of
approximately $3.0 million.
We are currently evaluating the effects of adopting the Interpretation on
the accounting for our ownership interest in our other joint ventures.
We have a wholly owned subsidiary, DDII LLC, that was established as a
joint venture with a major oil company for the purpose of constructing and
leasing a drillship, the Deepwater Frontier. The drillship was purchased by a
trust that was established to finance the purchase through debt and equity
financing, which we, under certain circumstances, fully guarantee. On May 29,
2003, the Company purchased the entire 40 percent interest of the major oil
company in DDII LLC. We currently account for DDII LLC's lease of the drillship
as an operating lease. The balance of the trust's debt and equity financing at
June 30, 2003 was approximately $162.0 million. Because we are at risk for this
amount, we are deemed to be the primary beneficiary of the trust for accounting
purposes and will consolidate the trust effective July 1, 2003. The drillship
serves as collateral for the trust's debt and equity financing. Effective with
the consolidation of the trust, the debt and equity financing to be reflected in
our balance sheet will be approximately $153.0 million and $9.0 million,
respectively. The debt financing will be reflected as debt due within one year
while the equity financing will be reflected as minority interest within other
long-term liabilities in our balance sheet. In addition, we will record
approximately $207.0 million for the drillship as property and equipment, net in
our balance sheet and will eliminate our note receivable to related party of
$45.3 million (see Note 11 to our condensed consolidated financial statements).
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 $90 million and $110 million in
2003 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.
In May 2003, the FASB issued SFAS 150, Accounting for Certain Financial
Instruments with Characteristics of both Liabilities and Equity. This statement
requires an issuer to measure and classify as liabilities certain financial
instruments that have characteristics of both liabilities and equity. SFAS 150
applies to those instruments that represent, or are indexed to, an obligation to
buy back the issuer's shares and obligations that can be settled in shares and
meet certain conditions. It does not, however, apply to financial instruments
that are indexed to and potentially settled in an issuer's own shares. This
statement is effective for financial instruments entered into or modified after
May 31, 2003, and otherwise is effective at the beginning of the first interim
period beginning after June 15, 2003. We
42
will adopt this statement effective July 1, 2003. However, management does not
expect the adoption of this statement to have a material effect on our
consolidated financial position or results of operations.
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 West Africa,
oversupply in the global mid-water sector, outlook for the deepwater sector,
activity in India and Mexico, market outlooks for our various geographical
operating sectors, the non-U.S. jackup market sector, future activity in the
International and U. S. Floater Contract Drilling Services and Gulf of Mexico
Shallow and Inland Water segments, the outcome and effect of the U.S. Internal
Revenue Service audit and the various tax assessments, deferred costs,
amortization expense, 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
7.5% Notes, 1.5% Convertible Debentures or Zero Coupon Convertible Debentures to
require the Company to repurchase their securities, repayment of debt and equity
financings with respect to DD LLC and DDII LLC, receipt of principal and
interest on debt owed to the Company by Delta Towing, effects of the
consolidation of Delta Towing and DDII LLC, 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 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.
43
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 June 30 relating to debt obligations as of
June 30, 2003. Weighted-average variable rates are based on LIBOR rates at June
30, 2003, plus applicable margins.
At June 30, 2003 (in millions, except interest rate percentages):
Scheduled Maturity Date (a) (b) Fair Value
----------------------------------------------------------------------- -----------
2004 2005 2006 2007 2008 Thereafter Total 06/30/03
------- --------- ------- -------- ------- ------------ --------- -----------
Total debt
Fixed Rate $131.2 $ 392.3 $400.0 $ 100.0 $269.0 $ 2,050.0 $3,342.5 $ 3,868.5
Average interest rate 8.5% 6.8% 1.5% 7.5% 6.7% 7.5% 6.7%
Variable Rate $150.0 $ 75.0 - - - - $ 225.0 $ 225.0
Average interest rate 1.7% 1.7% - - - - 1.7%
__________________________
(a) Maturity dates of the face value of our debt assumes the put options on 1.5% Convertible Debentures,
7.45% Notes and the Zero Coupon Convertible Debentures will be exercised in May 2006, April 2007 and
May 2008, respectively.
(b) Expected maturity amounts are based on the face value of debt.
At June 30, 2003, we had approximately $225.0 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 $1.2 million in
interest expense per year. Offsetting this, a large part of our cash investments
would earn commensurately higher rates of return. Using June 30, 2003 cash
investment levels, a one percent increase in interest rates would result in
approximately $7.1 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 typically
have minimal impact on overall results. In situations where payments of local
currency do not equal local currency requirements, foreign exchange derivative
instruments, specifically foreign exchange forward contracts or spot purchases,
may be used. We do not enter into derivative transactions for speculative
purposes. At June 30, 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. As a result, we recognized a $1.5
million after-tax loss on the revaluation of the local currency into functional
U.S dollars for the six months ended June 30, 2003.
44
ITEM 4. CONTROLS AND PROCEDURES
In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our Chief Executive
Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of June 30, 2003 to provide reasonable assurance
that information required to be disclosed in our reports filed or submitted
under the Exchange Act is recorded, processed, summarized and reported within
the time periods specified in the Securities and Exchange Commission's rules and
forms.
There has been no change in our internal controls over financial reporting
that occurred during the three months ended June 30, 2003 that has materially
affected, or is reasonably likely to materially affect, our internal controls
over financial reporting.
45
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In March 1997, an action was filed by Mobil Exploration and Producing U.S.
Inc. and affiliates, St. Mary Land & Exploration Company and affiliates and
Samuel Geary and Associates Inc. against one of our subsidiaries, Cliffs
Drilling, our 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 in excess of $50 million in connection with the
drilling of a turnkey well in 1995 and 1996. The case was tried before a jury in
January and February 2000, and the jury returned a verdict of approximately $30
million in favor of the plaintiffs for excess drilling costs, loss of insurance
proceeds, loss of hydrocarbons, expenses and interest. We and the Underwriters
appealed such judgment, and the Louisiana Court of Appeals reduced the amount
for which we may be responsible to less than $10 million. The plaintiffs
requested that the Supreme Court of Louisiana consider the matter and reinstate
the original verdict. We and the Underwriters also appealed to the Supreme Court
of Louisiana requesting that the Court reduce the verdict or, in the case of the
Underwriters, eliminate any liability for the verdict. Prior to the Supreme
Court of Louisiana ruling on these petitions, we settled with the St. Mary group
of plaintiffs and the State of Louisiana. Subsequently, the Supreme Court of
Louisiana denied the applications of all remaining plaintiffs. We settled with
all remaining plaintiffs in the second quarter of 2003. We believe that any
amounts, apart from a small deductible, paid in the settlement are covered by
relevant primary and excess liability insurance policies. However, the insurers
and the Underwriters have denied all coverage. We have instituted litigation
against those insurers and Underwriters to enforce our rights under the relevant
policies. One group of issuers has asserted a counterclaim against us claiming
that they issued the policy as a result of misrepresentation. The settlements
did not have a material adverse effect on our business or consolidated financial
position. We do not expect the ultimate outcome of the case to 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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
At the Annual General Meeting of Transocean Inc. held on May 8, 2003,
272,757,297 shares were represented in person or by proxy out of 319,767,820
shares entitled to vote as of the record date, constituting a quorum.
The matters submitted to a vote of shareholders were (i) the election of
Class I Directors as set forth in the Company's Proxy Statement relating to the
meeting; (ii) the amendment of the Company's Long-Term Incentive Plan to allow
grants or incentive stock options for an additional ten year period to May 1,
2013 and to allow a continuing right to grant stock options and share
appreciation rights to our outside directors; (iii) the amendment of the
Company's Employee Stock Purchase Plan to increase the number of ordinary shares
reserved for issuance under the plan from 1,500,000 to 2,500,000; and (iv) the
approval of appointment of Ernst & Young LLP as independent auditors for 2003.
With respect to the re-election of directors, the following number of votes were
cast as to the Class I Director nominees: Victor E. Grijalva, 240,921,742 votes
for and 31,835,555 votes withheld; Arthur Lindenauer, 260,182,393 votes for and
12,574,904 withheld; Richard A. Pattarozzi, 260,792,569 votes for and 11,964,728
votes withheld; Kristian Siem, 258,264,644 votes for and 14,492,653 withheld;
and J. Michael Talbert, 259,108,809 votes for and 13,648,488 votes withheld.
With respect to the amendment of the Company's Long-Term Incentive Plan,
242,440,573 votes were cast for the proposal and 26,645,604 votes were cast
against the proposal. There were 2,668,773 abstentions and 1,002,347 broker
non-votes in the vote on the proposal. With respect to the amendment of the
Company's Employee Stock Purchase Plan, 264,793,085 votes were cast for the
proposal and 4,412,002 votes were cast against the proposal. There were
2,549,863 abstentions and 1,002,347 broker non-votes in the vote on the
46
proposal. With respect to the Company's appointment of independent auditors,
there were 239,819,902 votes for and 11,517,370 votes withheld on the proposal.
There were 21,420,025 abstentions and no broker non-votes on the proposal.
47
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)
+10.1 Amended and Restated Long-Term Incentive Plan of Transocean Inc.,
effective May 8, 2003
*10.2 Amended and Restated Employee Stock Purchase Plan of Transocean Inc.,
effective May 8, 2003 (incorporated by reference to Exhibit 10.1 to
the Registration Statement on Form S-8 (Registration No. 333-106026)
filed by the Company on June 11, 2003)
+31.1 CEO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
+31.2 CFO Certification Pursuant to Section 302 of the Sarbanes-Oxley Act
of 2002
+32.1 CEO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
+32.2 CFO Certification Pursuant to Section 906 of the Sarbanes-Oxley Act
of 2002
_________________________
* Incorporated by reference as indicated.
+ Filed herewith.
(b) Reports on Form 8-K
The Company filed a Current Report on Form 8-K on May 6, 2003 (information
furnished not filed) announcing the issuance of first quarter 2003 financial
results and a Current Report on Form 8-K on May 28, 2003 (information furnished
not filed) announcing financial information pertaining to operating and
maintenance expense and cash operating costs for the first quarter of 2003 and
the fourth quarter of 2002.
48
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 August 12, 2003.
TRANSOCEAN INC.
By: /s/ Gregory L. Cauthen
--------------------------
Gregory L. Cauthen
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
By: /s/ Brenda S. Masters
-------------------------
Brenda S. Masters
Vice President and Controller
(Principal Accounting Officer)
49