================================================================================
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 SEPTEMBER 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 October 31, 2003, 319,890,650 ordinary shares, par value $0.01 per
share, were outstanding.
================================================================================
TRANSOCEAN INC.
INDEX TO FORM 10-Q
QUARTER ENDED SEPTEMBER 30, 2003
Page
----
PART I - FINANCIAL INFORMATION
----------------------------------
ITEM 1. Financial Statements (Unaudited)
Condensed Consolidated Statements of Operations
Three and Nine Months Ended September 30, 2003 and 2002 2
Condensed Consolidated Statements of Comprehensive Income (Loss)
Three and Nine Months Ended September 30, 2003 and 2002 3
Condensed Consolidated Balance Sheets
September 30, 2003 and December 31, 2002 4
Condensed Consolidated Statements of Cash Flows
Three and Nine Months Ended September 30, 2003 and 2002 5
Notes to Condensed Consolidated Financial Statements 6
ITEM 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations 22
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk 47
ITEM 4. Controls and Procedures 48
PART II - OTHER INFORMATION
-------------------------------
ITEM 1. Legal Proceedings 49
ITEM 6. Exhibits and Reports on Form 8-K 50
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 Nine Months Ended
September 30, September 30,
------------------- --------------------
2003 2002 2003 2002
------- ---------- --------- ---------
Operating Revenues
Contract drilling revenues $598.5 $ 695.2 $1,764.7 $2,009.3
Client reimbursable revenues 24.4 - 78.1 -
--------------------------------------------------------------------------------------------------------
622.9 695.2 1,842.8 2,009.3
--------------------------------------------------------------------------------------------------------
Costs and Expenses
Operating and maintenance 403.0 381.1 1,203.6 1,127.7
Depreciation 126.8 124.2 381.1 374.1
General and administrative 21.2 15.8 50.0 51.6
Impairment loss on long-lived assets - 40.9 16.8 42.0
Gain from sale of assets, net (0.9) (2.9) (2.9) (3.5)
--------------------------------------------------------------------------------------------------------
550.1 559.1 1,648.6 1,591.9
--------------------------------------------------------------------------------------------------------
Operating Income 72.8 136.1 194.2 417.4
Other Income (Expense), net
Equity in earnings of joint ventures 1.9 0.4 7.3 4.8
Interest income 3.0 6.1 15.7 16.0
Interest expense (49.0) (52.3) (154.4) (160.7)
Loss on retirement of debt - - (15.7) -
Impairment loss on note receivable from related party - - (21.3) -
Other, net (0.2) 1.3 (3.5) 0.2
--------------------------------------------------------------------------------------------------------
(44.3) (44.5) (171.9) (139.7)
--------------------------------------------------------------------------------------------------------
Income Before Income Taxes, Minority Interest and
Cumulative Effect of a Change in Accounting Principle 28.5 91.6 22.3 277.7
Income Tax Expense (Benefit) 17.3 (164.8) 8.3 (137.1)
Minority Interest 0.2 1.2 0.3 2.3
--------------------------------------------------------------------------------------------------------
Net Income Before Cumulative Effect of a Change in
Accounting Principle 11.0 255.2 13.7 412.5
Cumulative Effect of a Change in Accounting Principle - - - (1,363.7)
--------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 11.0 $ 255.2 $ 13.7 $ (951.2)
========================================================================================================
Basic Earnings (Loss) Per Share
Income Before Cumulative Effect of a Change in
Accounting Principle $ 0.03 $ 0.80 $ 0.04 $ 1.29
Loss on Cumulative Effect of a Change in Accounting
Principle - - - (4.27)
--------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 0.03 $ 0.80 $ 0.04 $ (2.98)
========================================================================================================
Diluted Earnings (Loss) Per Share
Income Before Cumulative Effect of a Change in Accounting
Principle $ 0.03 $ 0.79 $ 0.04 $ 1.28
Loss on Cumulative Effect of a Change in Accounting
Principle - - - (4.22)
--------------------------------------------------------------------------------------------------------
Net Income (Loss) $ 0.03 $ 0.79 $ 0.04 $ (2.94)
========================================================================================================
Weighted Average Shares Outstanding
Basic 319.9 319.2 319.8 319.1
Diluted 321.1 328.8 321.4 323.0
Dividends Paid per Share $ - $ - $ - $ 0.06
--------------------------------------------------------------------------------------------------------
See accompanying notes.
2
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(In millions)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ -----------------
2003 2002 2003 2002
-------- -------- ------- --------
Net Income (Loss) $ 11.0 $ 255.2 $ 13.7 $(951.2)
-------------------------------------------------------------------------------------------------------
Other comprehensive income (loss), net of tax
Amortization of gain on terminated interest rate swaps (0.1) (0.1) (0.2) (0.2)
Change in unrealized loss on securities available for sale (0.1) (0.2) 0.1 (0.1)
Change in share of unrealized loss in unconsolidated
joint venture's interest rate swaps (net of tax of $0.4
and $1.0 for the three and nine months ended
September 30, 2003, respectively) 0.7 (0.2) 1.8 1.9
Minimum pension liability adjustments (net of tax of
$0.4 for the nine months ended September 30, 2003) - - 0.8 -
-------------------------------------------------------------------------------------------------------
Other comprehensive income (loss) 0.5 (0.5) 2.5 1.6
-------------------------------------------------------------------------------------------------------
Total Comprehensive Income (Loss) $ 11.5 $ 254.7 $ 16.2 $(949.6)
=======================================================================================================
See accompanying notes.
3
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(In millions, except share data)
(Unaudited)
September 30, December 31,
2003 2002
-------------- --------------
(Unaudited)
ASSETS
Cash and Cash Equivalents $ 806.3 $ 1,214.2
Accounts Receivable, net of allowance for doubtful accounts of $25.9
and $20.8 at September 30, 2003 and December 31, 2002, respectively 486.6 499.3
Materials and Supplies, net of allowance for obsolescence of $18.6
at September 30, 2003 and December 31, 2002 156.4 155.8
Deferred Income Taxes 14.1 21.9
Other Current Assets 79.1 20.5
------------------------------------------------------------------------------------------------------
Total Current Assets 1,542.5 1,911.7
------------------------------------------------------------------------------------------------------
Property and Equipment 10,214.9 10,198.0
Less Accumulated Depreciation 2,535.4 2,168.2
------------------------------------------------------------------------------------------------------
Property and Equipment, net 7,679.5 8,029.8
------------------------------------------------------------------------------------------------------
Goodwill 2,223.4 2,218.2
Investments in and Advances to Joint Ventures 70.0 108.5
Deferred Income Taxes 26.2 26.2
Other Assets 176.1 370.7
------------------------------------------------------------------------------------------------------
Total Assets $ 11,717.7 $ 12,665.1
======================================================================================================
LIABILITIES AND SHAREHOLDERS' EQUITY
Accounts Payable $ 147.2 $ 134.1
Accrued Income Taxes 62.0 59.5
Debt Due Within One Year 282.1 1,048.1
Other Current Liabilities 293.7 262.2
------------------------------------------------------------------------------------------------------
Total Current Liabilities 785.0 1,503.9
------------------------------------------------------------------------------------------------------
Long-Term Debt 3,419.3 3,629.9
Deferred Income Taxes 55.4 107.2
Other Long-Term Liabilities 283.1 282.7
------------------------------------------------------------------------------------------------------
Total Long-Term Liabilities 3,757.8 4,019.8
------------------------------------------------------------------------------------------------------
Commitments and Contingencies
Preference Shares, $0.10 par value; 50,000,000 shares authorized,
none issued and outstanding - -
Ordinary Shares, $0.01 par value; 800,000,000 shares authorized,
319,890,650 and 319,219,072 shares issued and outstanding at
September 30, 2003 and December 31, 2002, respectively 3.2 3.2
Additional Paid-in Capital 10,640.4 10,623.1
Accumulated Other Comprehensive Loss (29.0) (31.5)
Retained Deficit (3,439.7) (3,453.4)
------------------------------------------------------------------------------------------------------
Total Shareholders' Equity 7,174.9 7,141.4
------------------------------------------------------------------------------------------------------
Total Liabilities and Shareholders' Equity $ 11,717.7 $ 12,665.1
======================================================================================================
See accompanying notes.
4
TRANSOCEAN INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
(Unaudited)
Three Months Ended Nine Months Ended
September 30, September 30,
-------------------- --------------------
2003 2002 2003 2002
--------- --------- --------- ---------
CASH FLOWS FROM OPERATING ACTIVITIES
Net Income (Loss) $ 11.0 $ 255.2 $ 13.7 $ (951.2)
Adjustments to reconcile net income (loss) to
net cash provided by operating activities
Depreciation 126.8 124.2 381.1 374.1
Impairment loss on goodwill - - - 1,363.7
Stock-based compensation expense 1.4 0.2 4.3 0.6
Deferred income taxes 19.1 (151.5) (40.4) (189.8)
Equity in earnings of joint ventures (1.9) (0.4) (7.3) (4.8)
Net (gain) loss from disposal of assets 4.4 (1.1) 12.2 1.2
Loss on retirement of debt - - 15.7 -
Impairment loss on long-lived assets - 40.9 16.8 42.0
Impairment loss on note receivable from related party - - 21.3 -
Amortization of debt-related discounts/premiums, fair
value adjustments and issue costs, net (8.2) 1.7 (16.1) 4.6
Deferred income, net (5.3) (3.3) (6.9) (9.3)
Deferred expenses, net (5.1) (14.7) (2.4) (7.7)
Other long-term liabilities 0.2 2.7 13.7 10.3
Other, net 12.1 (0.7) 12.1 1.0
Changes in operating assets and liabilities
Accounts receivable (44.0) 47.9 7.6 132.0
Accounts payable and other current liabilities 42.6 42.8 46.6 (41.9)
Income taxes receivable/payable, net (8.0) (38.2) 1.6 (15.9)
Other current assets 14.3 14.0 (9.0) (8.7)
--------------------------------------------------------------------------------------------------------
Net Cash Provided by Operating Activities 159.4 319.7 464.6 700.2
--------------------------------------------------------------------------------------------------------
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures (23.4) (33.4) (73.6) (114.6)
Note issued to related party, net of repayments 1.1 - (44.2) -
Proceeds from disposal of assets, net 0.9 8.6 4.1 73.6
Acquisition of 40 percent interest in Deepwater Drilling II
L.L.C., net of cash acquired - - 18.1 -
Joint ventures and other investments, net 0.6 4.6 2.8 4.6
--------------------------------------------------------------------------------------------------------
Net Cash Used in Investing Activities (20.8) (20.2) (92.8) (36.4)
--------------------------------------------------------------------------------------------------------
CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings under capital lease obligations 1.0 - 1.0 -
Repayments under commercial paper program - - - (326.4)
Repayments on other debt instruments (48.0) (34.7) (967.2) (154.3)
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 0.6 (0.1) 12.3 10.2
Dividends paid - - - (19.1)
Financing costs 0.1 - - (8.1)
Other, net - 1.2 (0.5) 2.3
--------------------------------------------------------------------------------------------------------
Net Cash Used in Financing Activities (46.3) (33.6) (779.7) (495.4)
--------------------------------------------------------------------------------------------------------
Net Increase (Decrease) in Cash and Cash Equivalents 92.3 265.9 (407.9) 168.4
--------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at Beginning of Period 714.0 755.9 1,214.2 853.4
--------------------------------------------------------------------------------------------------------
Cash and Cash Equivalents at End of Period $ 806.3 $1,021.8 $ 806.3 $1,021.8
========================================================================================================
See accompanying notes.
5
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
NOTE 1 PRINCIPLES OF CONSOLIDATION
Transocean Inc. (together with its subsidiaries and predecessors, unless
the context requires otherwise, the "Company") is a leading international
provider of offshore and inland marine contract drilling services for oil and
gas wells. As of September 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
nine months ended September 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 it believes are reasonable under the circumstances, the results of
which form the basis for making judgments about the carrying values of assets
and liabilities that are not readily apparent from other sources. Actual results
could differ from such estimates.
SUPPLEMENTARY CASH FLOW INFORMATION - Cash payments for interest and income
taxes, net, were $108.5 million and $56.5 million, respectively, for the nine
months ended September 30, 2003 and $116.3 million and $74.0 million,
respectively, for the nine months ended September 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,
6
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) non-cash 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 September 30, 2003.
The changes in the carrying amount of goodwill as of September 30, 2003 were as
follows (in millions):
Balance at Balance at
January 1, September 30,
2003 Other (a) 2003
----------- ---------- --------------
International and U.S. Floater Contract Drilling Services $ 2,218.2 $ 5.2 $ 2,223.4
_________________
(a) Primarily 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 (see Note 4).
7
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 September 30, 2003 and December 31, 2002 are as
follows (in millions):
Unrealized Other
Gain on Loss on Comprehensive Accumulated
Terminated Available- Loss Related to Minimum 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)
Change in other comprehensive
(income) loss, net of tax (0.2) 0.1 1.8 0.8 2.5
--------------- ------------ ----------------- ----------- ---------------
Balance at September 30, 2003 $ 3.4 $ (0.5) $ (0.2) $ (31.7) $ (29.0)
=============== ============ ================= =========== ===============
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
customers. 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.
8
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 Nine Months Ended
September 30, September 30,
------------------ -----------------
2003 2002 2003 2002
-------- -------- ------- --------
Net Income (Loss) as Reported $ 11.0 $ 255.2 $ 13.7 $(951.2)
-------- -------- ------- --------
Add back: Stock-based compensation expense included in
reported net income (loss), net of related tax effects 0.1 2.3 2.6 2.7
Deduct: Total stock-based compensation expense
determined under the fair value method for all awards,
net of related tax effects
Long-Term Incentive Plan (4.2) (7.5) (12.5) (17.6)
Employee Stock Purchase Plan 0.4 (0.5) (1.7) (1.7)
Pro Forma Net Income (Loss) $ 7.3 $ 249.5 $ 2.1 $(967.8)
======== ======== ======= ========
Basic Earnings (Loss) Per Share
As Reported $ 0.03 $ 0.80 $ 0.04 $ (2.98)
Pro Forma 0.02 0.78 0.01 (3.03)
Diluted Earnings (Loss) Per Share
As Reported $ 0.03 $ 0.79 $ 0.04 $ (2.94)
Pro Forma 0.02 0.76 0.01 (3.00)
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 variable interest entities in
which an enterprise absorbs a majority of the entity's expected losses, receives
a majority of the entity's expected residual returns, or both, as a result of
ownership, contractual or other financial interests in the entity. The
provisions of the Interpretation are effective immediately for those variable
interest entities created after January 31, 2003. The provisions, as amended,
are effective for the first interim or annual period ending after December 15,
2003 for those variable interest entities held prior to February 1, 2003. The
Company will adopt the Interpretation and consolidate its variable interest
entities as required on December 31, 2003. 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 a 25 percent ownership interest in Delta Towing Holdings,
LLC ("Delta Towing"), a joint venture established for the purpose of owning and
operating inland and shallow water marine support vessel equipment. At the time
Delta Towing 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 carrying value of the notes receivable included in investments in and
advances to joint ventures in the Company's condensed consolidated balance
sheets, net of allowance for credit losses and equity losses in the joint
venture, was $53.6 million at September 30, 2003. Delta Towing also issued a
$3.0 million note to the 75 percent joint venture partner. Because Delta
Towing's equity is not sufficient to absorb its expected losses and the Company
has the largest percentage of investment at risk through the notes receivable,
the Company would absorb the majority of the joint venture's expected losses;
therefore, the Company is deemed to be the primary beneficiary of Delta Towing
for accounting purposes. As such, the Company
9
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
will consolidate Delta Towing effective December 31, 2003. While the Company
expects the consolidation of Delta Towing to result in an increase in net assets
of approximately $1.0 million, based on balances at September 30, 2003, the
expected amounts may be adjusted upon consolidation at December 31, 2003 with
application of the provisions of the Interpretation.
The Company has a 50 percent ownership interest in Deepwater Drilling
L.L.C. ("DD LLC"). DD LLC was established for the purpose of constructing and
contracting the drillship Deepwater Pathfinder. The drillship was purchased by
a trust that was established to finance the purchase through debt and equity
financing and to lease the drillship back to DD LLC through a synthetic lease
financing arrangement with the drillship serving as collateral. The balance of
the trust's debt and equity financing was approximately $189.7 million at
September 30, 2003. The scheduled expiration of the lease is January 2004, at
which time DD LLC may purchase the drillship from the trust for approximately
$185 million. While the operations of DD LLC are funded by cash flows from
operating activities, the Company guarantees, under certain circumstances, the
debt and equity financing on the leased drillship equally with its joint venture
partner. The Company has determined through its application of the provisions of
the Interpretation for determining an entity's primary beneficiary that it is DD
LLC's primary beneficiary for accounting purposes and will consolidate the
entity effective December 31, 2003. While the Company expects the consolidation
of DD LLC to result in an increase in net assets of approximately $116 million,
based on balances at September 30, 2003, the expected amounts may be adjusted
upon consolidation at December 31, 2003 with application of the provisions of
the Interpretation.
The Company has investments in and advances to four additional joint
ventures. These remaining four joint ventures were primarily established for the
purpose of owning and operating certain drilling units and are funded primarily
by cash flows from operating activities. Based on the Company's initial
assessment, these entities would not be deemed variable interest entities under
the Interpretation. The Company expects to complete the analysis of these
entities during the fourth quarter of 2003. The Company currently accounts for
its investments in joint ventures 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.
The Company's wholly owned subsidiary, Deepwater Drilling II L.L.C. ("DDII
LLC") was originally established as a joint venture with a subsidiary of
ConocoPhillips for the purpose of constructing and contracting the drillship
Deepwater Frontier. The drillship was purchased by a trust that was established
to finance the purchase through debt and equity financing and to lease the
drillship back to DDII LLC through a synthetic lease financing arrangement with
the drillship serving as collateral. The balance of the trust's debt and equity
financing at September 30, 2003 was approximately $158.0 million, net of a note
receivable - related party (see Note 11). On May 29, 2003, the Company purchased
ConocoPhillips' 40 percent interest in DDII LLC. The Company currently accounts
for DDII LLC's lease of the drillship as an operating lease. As a result of the
Company's purchase of ConocoPhillips' 40 percent interest in DDII LLC, the
Company, under certain circumstances, fully guarantees the debt and equity
financing. Because the Company is at risk for the full amount of the debt and
equity financing, the Company is deemed to be the primary beneficiary of the
trust for accounting purposes and expects to consolidate the trust effective
December 31, 2003. While the Company expects the consolidation of the trust to
result in an increase in net assets of approximately $27 million, based on
balances at September 30, 2003, the expected amounts may be adjusted upon
consolidation at December 31, 2003 with application of the provisions of the
Interpretation. See Note 11.
In addition to the joint ventures and DDII LLC discussed above, the Company
is party to a sale/leaseback transaction for the semisubmersible drilling rig
M.G. Hulme, Jr. with an unrelated third party. Under the sale/leaseback
agreement, the Company has the option to purchase the semisubmersible drilling
rig at the end of the lease for a maximum amount of approximately $35.7 million.
The Company is currently evaluating whether the unrelated third party lessor is
a variable interest entity and, if so, which company would be deemed to be the
primary beneficiary. The Company currently accounts for the lease of this
semisubmersible drilling rig as an operating lease.
10
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
The Company is currently evaluating the cumulative effect of the accounting
change on its results of operations that will result from the implementation of
the Interpretation.
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 customers on a reimbursable basis are recognized as
operating and maintenance expense. In addition, the amounts billed to the
Company's customers 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. The statement
clarifies the accounting for certain financial instruments that, under previous
guidance, issuers could account for as equity. This statement requires an issuer
to measure and classify as liabilities, or assets in some circumstances, certain
classes of freestanding financial instruments that embody obligations for the
issuer. In addition to this requirement for the classification and measurement
of financial instruments in its scope, SFAS 150 also requires disclosures about
alternative ways of settling the instruments and the identity of the entity that
controls the settlement alternatives. 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 adopted this statement effective July 1, 2003. The adoption of
this statement did not 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.
11
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 3 - DEBT
Debt, net of unamortized discounts, premiums and fair value adjustments, is
comprised of the following (in millions):
September 30, December 31,
2003 2002
-------------- -------------
6.5% Senior Notes, due April 2003 $ - $ 239.7
9.125% Senior Notes, due December 2003 87.6 89.5
Amortizing Term Loan Agreement - Final Maturity December 2004 187.5 300.0
6.75% Senior Notes, due April 2005 (a) 363.4 371.8
7.31% Nautilus Class A1 Amortizing Notes - Final Maturity May 2005 74.2 104.7
9.41% Nautilus Class A2 Notes, due May 2005 - 51.7
6.95% Senior Notes, due April 2008 (a) 270.5 277.2
9.5% Senior Notes, due December 2008 (a) 360.0 371.8
6.625% Notes, due April 2011 (a) 800.0 803.7
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) 16.4 527.2
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) 94.8 94.6
7.5% Notes, due April 2031 597.4 597.4
Other 1.0 0.2
-------------- -------------
Total Debt 3,701.4 4,678.0
-------------- -------------
Less Debt Due Within One Year (b) 282.1 1,048.1
-------------- -------------
Total Long-Term Debt $ 3,419.3 $ 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 September 30, 2003, the remaining balance of
the debentures not put back to the Company in May 2003 was classified as
long-term debt.
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 September 30 (in millions):
2004 . . . $ 281.5
2005 . . . 419.0
2006 . . . 400.0
2007 . . . 100.0
2008 . . . 269.0
Thereafter 2,050.0
--------
Total. . $3,519.5
========
12
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
Commercial Paper Program - The Company has two revolving credit agreements,
described below, which provide liquidity for commercial paper borrowings. At
September 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 September 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 September 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 September 30, 2003,
$187.5 million was outstanding under this agreement.
Exchange Offer - In March 2002, the Company completed exchange offers and
consent solicitations for TODCO's 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Senior Notes ("the Exchange Offer"). As a result of the Exchange Offer,
approximately $234.5 million, $342.3 million, $247.8 million, $246.5 million,
$76.9 million and $289.8 million principal amount of TODCO's outstanding 6.5%,
6.75%, 6.95%, 7.375%, 9.125% and 9.5% Senior Notes, respectively, were exchanged
for the Company's newly issued 6.5%, 6.75%, 6.95%, 7.375%, 9.125% and 9.5%
Senior Notes having the same principal amount, interest rate, redemption terms
and payment and maturity dates. Because the holders of a majority in principal
amount of each of these series of notes consented to the proposed amendments to
the applicable indenture pursuant to which the notes were issued, some
covenants, restrictions and events of default were eliminated from the
indentures with respect to these series of notes. After the Exchange Offer,
approximately $5.0 million, $7.7 million, $2.2 million, $3.5 million, $10.2
million and $10.2 million principal amount of the outstanding 6.5% (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.
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
13
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
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
As a result of a change in anticipated 2003 earnings, the annual effective
tax rate is estimated to be approximately 43 percent during 2003 on earnings
before non-cash note receivable and other asset impairments, loss on debt
retirements and initial public offering related costs. Due to the increase in
the estimated annual effective tax rate from approximately 38 percent at June
30, 2003, earnings for the three months ended September 30, 2003 were reduced by
$2.6 million ($0.01 per diluted share) as a result of applying the adjusted
estimated annual effective tax rate to the six months ended June 30, 2003.
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.
In September 2002, the Company recorded a $176.2 million ($0.55 per diluted
share) foreign tax benefit attributable to the restructuring of certain non-U.S.
operations. As a result of the restructuring, previously unrecognized losses
were offset against deferred gains, resulting in a reduction of non-current
deferred taxes payable.
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 September 30, 2003, the Company had no material open foreign
exchange contracts.
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 during the second
quarter of 2003. In the third quarter of 2003, to limit its exposure,
14
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
the Company entered into an interim arrangement with one of its customers in
which the Company is to receive 55 percent of the billed receivables in U.S.
dollars with the remainder paid in local currency.
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 with an
expiration date of October 2003 that have aggregate market values netting to a
liability of $0.7 million at September 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, 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 customers.
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 before income taxes, minority interest and
cumulative effect of a change in accounting principle by segment were as follows
(in millions):
Three Months Ended Nine Months Ended
September 30, September 30,
------------------ --------------------
2003 2002 2003 2002
-------- -------- --------- ---------
Operating Revenues
International and U.S. Floater Contract
Drilling Services $ 564.4 $ 641.2 $1,675.6 $1,873.5
Gulf of Mexico Shallow and Inland Water 58.5 54.0 167.2 135.8
-------- -------- --------- ---------
Total Operating Revenues $ 622.9 $ 695.2 $1,842.8 $2,009.3
-------- -------- --------- ---------
Operating income (loss) before general and
administrative expense
International and U.S. Floater Contract
Drilling Services $ 118.9 $ 190.0 $ 347.1 $ 570.8
Gulf of Mexico Shallow and Inland Water (24.9) (38.1) (102.9) (101.8)
-------- -------- --------- ---------
94.0 151.9 244.2 469.0
-------- -------- --------- ---------
Unallocated general and administrative expense (21.2) (15.8) (50.0) (51.6)
Unallocated other income (expense), net (44.3) (44.5) (171.9) (139.7)
-------- -------- --------- ---------
Income before Income Taxes, Minority Interest
and Cumulative Effect of a Change in
Accounting Principle $ 28.5 $ 91.6 $ 22.3 $ 277.7
======== ======== ========= =========
Total assets by segment were as follows (in millions):
September 30, December 31,
2003 2002
-------------- -------------
International and U.S. Floater Contract Drilling Services $ 10,996.6 $ 11,804.1
Gulf of Mexico Shallow and Inland Water 721.1 861.0
-------------- -------------
Total Assets $ 11,717.7 $ 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 nine months ended September 30, 2003, the Company settled an
insurance claim and sold certain other assets for net proceeds of approximately
$4.1 million and recorded net gains of $1.9 million ($0.01 per diluted share),
net of tax of $0.2 million, in its International and U.S. Floater Contract
Drilling Services segment and $0.3 million, net of tax of $0.2 million, in its
Gulf of Mexico Shallow and Inland Water segment.
During the nine months ended September 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 nine months ended September 30, 2002, the Company settled an
insurance claim and sold certain other assets for net proceeds of approximately
$24.2 million and recorded net gains of $2.9 million ($0.01 per diluted
16
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
share), net of tax of $0.3 million, in its International and U.S. Floater
Contract Drilling Services segment and $0.4 million, net of tax of $0.3 million,
in its Gulf of Mexico Shallow and Inland Water segment.
Impairments - During the nine months ended September 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 approximate
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 nine months ended September 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 nine months ended September 30, 2002, the Company recorded
non-cash impairment charges of $13.1 million ($0.04 per diluted share), net of
tax of $7.1 million, and $9.9 million ($0.03 per diluted share), net of tax of
$5.3 million, in its International and U.S. Floater Contract Drilling Services
and Gulf of Mexico Shallow and Inland Water segments, respectively, relating to
the reclassification of assets held for sale to assets held and used. The
impairment of these assets resulted from management's assessment that they no
longer met the held for sale criteria under SFAS 144. In accordance with SFAS
144, the carrying value of these assets was adjusted to the lower of fair market
value or carrying value adjusted for depreciation from the date the assets were
classified as held for sale. The fair market values of these assets were based
on third party valuations.
During the nine months ended September 30, 2002, due to deterioration in
market conditions, the Company recorded non-cash impairment charges of $3.6
million ($0.01 per diluted share), net of tax of $1.9 million, and $0.7 million,
net of tax of $0.4 million, in the International and U.S. Floater Contract
Drilling Services and Gulf of Mexico Shallow and Inland Water segments,
respectively, related to assets held for sale. The impairments were determined
and measured based on an estimate of fair value derived from offers from
potential buyers.
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 (loss) per share is as follows (in
millions, except per share data):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- ----------------------
2003 2002 2003 2002
---------- ---------- --------- -----------
NUMERATOR FOR BASIC EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting
Principle $ 11.0 $ 255.2 $ 13.7 $ 412.5
Cumulative Effect of a Change in Accounting Principle - - - (1,363.7)
---------- ---------- --------- -----------
Net Income (Loss) for basic earnings per share $ 11.0 $ 255.2 $ 13.7 $ (951.2)
========== ========== ========= ===========
NUMERATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting
Principle $ 11.0 $ 255.2 $ 13.7 $ 412.5
Add back effect of dilutive zero coupon convertible debentures - 3.8 - -
---------- ---------- --------- -----------
Income Before Cumulative Effect of a Change in Accounting
Principle $ 11.0 $ 259.0 $ 13.7 $ 412.5
Cumulative Effect of a Change in Accounting Principle - - - (1,363.7)
---------- ---------- --------- -----------
Net Income (Loss) for diluted earnings per share $ 11.0 $ 259.0 $ 13.7 $ (951.2)
========== ========== ========= ===========
DENOMINATOR FOR DILUTED EARNINGS (LOSS) PER SHARE
Weighted-average shares outstanding for basic earnings per share 319.9 319.2 319.8 319.1
Effect of dilutive securities:
Employee stock options and unvested stock grants 0.9 1.5 1.1 2.3
Warrants to purchase ordinary shares 0.3 1.0 0.5 1.6
Zero coupon convertible debentures - 7.1 - -
---------- ---------- --------- -----------
Adjusted weighted-average shares and assumed
conversions for diluted earnings per share 321.1 328.8 321.4 323.0
========== ========== ========= ===========
BASIC EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting Principle $ 0.03 $ 0.80 $ 0.04 $ 1.29
Cumulative Effect of a Change in Accounting Principle - - - (4.27)
---------- ---------- --------- -----------
Net Income (Loss) $ 0.03 $ 0.80 $ 0.04 $ (2.98)
========== ========== ========= ===========
DILUTED EARNINGS (LOSS) PER SHARE
Income Before Cumulative Effect of a Change in Accounting
Principle $ 0.03 $ 0.79 $ 0.04 $ 1.28
Cumulative Effect of a Change in Accounting Principle - - - (4.22)
---------- ---------- --------- -----------
Net Income (Loss) $ 0.03 $ 0.79 $ 0.04 $ (2.94)
========== ========== ========= ===========
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 the three and
nine months ended September 30, 2003 and the nine months ended September 30,
2002.
18
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 10 - CONTINGENCIES
Legal Proceedings - In August 2003, a judgment of approximately $9.5
million was entered by the Labor Division of the Provincial Court of Luanda,
Angola, against the Company and a labor contractor for the Company, Hull Blyth,
in favor of certain former workers on several of the Company's drilling rigs.
The workers were employed by Hull Blyth to work on several drilling rigs while
the rigs were located in Angola. When the drilling contracts concluded and the
rigs left Angola, the workers' employment ended. The workers brought suit
claiming that they were not properly compensated when their employment ended. In
addition to the monetary judgment, the Labor Division ordered the workers to be
hired by the Company. The Company believes that this judgment is without
sufficient legal foundation and has appealed the matter to the Angola Supreme
Court. The Company further believes that Hull Blyth has an obligation to protect
the Company from any judgment. The Company does not believe that the ultimate
outcome of this matter will have a material adverse effect on the Company's
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 September 30, 2003 totaling $204.1 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 $169.8 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
and July 2003, Delta Towing failed to make additional scheduled quarterly
interest payments on the notes receivable of $1.6 million and $1.7 million,
respectively. During the nine months ended September 30, 2003, the Company
received partial interest payments of approximately $1.0 million and $1.1
million of payments applied to principal on the three-year revolving credit
facility. At September 30, 2003, the Company had interest receivable from Delta
Towing of $4.0 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 September 30, 2003, the carrying value of the notes receivable
included in investments in and advances to joint ventures in the Company's
condensed consolidated balance sheets, net of the related allowance for credit
losses and equity losses in the joint venture, was $53.6 million. In September
2003, the Company established a reserve of $1.6 million for interest income
earned during the third quarter on the notes receivable and will continue to
reserve future interest income earned until the scheduled quarterly interest
payments have been brought current. The Company will
19
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
apply future 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 drillship Deepwater Frontier. In May
2003, WestLB AG, one of the lenders in the synthetic lease financing facility,
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 of WestLB AG. The balance of the
note receivable was $44.2 million at September 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 $9.0 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 September 30, 2003, $2.5 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 September 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 September 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
TRANSOCEAN INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
(Unaudited)
NOTE 13 - RETIREMENT PLANS AND OTHER POST EMPLOYMENT BENEFITS
Nigerian Severance Plan - The Company maintains a severance plan (the
"Nigeria Plan"), which provides postretirement benefits to certain employees
under a labor contract with the Nigeria labor unions. Under the Nigeria Plan
provisions, employees receive postretirement benefits in the event of
retirement, termination for redundancy, or death. The Company made 83 employees
redundant effective May 2003. In accordance with the provisions of the Nigeria
Plan, the Company paid approximately $2.6 million in termination benefits in
August 2003. Additionally, as a result of these terminations, and in accordance
with the provisions of SFAS 88, Employers' Accounting for Settlements and
Curtailments of Defined Benefit Pension Plans and for Termination Benefits, a
plan curtailment gain of $0.8 million, net of a settlement loss of $0.3 million,
was recorded.
21
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 October 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, 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 customers.
As a result of the implementation of Emerging Issues Task Force ("EITF")
Issue No. 99-19, Reporting Revenue Gross as a Principal versus Net as an Agent,
costs we incur that are charged to our customers on a reimbursable basis are
being recognized as operating and maintenance expense beginning in 2003. In
addition, the amounts billed to our customers 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 ("IPO") 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
22
the entity that owns that business in preparation of the offering. We expect to
complete the IPO 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. However, we do not anticipate completion of the IPO prior to
2004. We do not expect to sell all of our interest in TODCO in the IPO. Until we
complete the IPO transaction, we will continue to operate and account for TODCO
as our Gulf of Mexico Shallow and Inland Water segment. Because the IPO had not
been completed by the end of the third quarter of 2003, we recognized $8.0
million of costs relating to the IPO in general and administrative expense for
the three months ended September 30, 2003, of which $6.4 million was deferred in
previous periods. Future IPO-related costs will be expensed as incurred.
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 labor unions in Nigeria on the semisubmersible rigs M.G.
Hulme, Jr. and Sedco 709 and the jackup rigs Trident VI and Trident VIII. All of
these rigs returned to operations in May and June 2003. We continue negotiations
to resolve various labor issues 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 resumed operations in
July 2003, but we are in discussion with our customer regarding the appropriate
dayrate treatment. Results for the three months ended September 30, 2003 were
negatively impacted by approximately $17 million due to an ongoing disagreement
with our customer concerning the applicable dayrate and other costs. See
"-Operating Results" and "-Outlook."
In June 2003, we incurred a loss as a result of a well blowout and fire
aboard our inland barge Rig 62. During the nine months ended September 30, 2003,
we incurred a $7.6 million loss relating to this incident. While our insurance
coverage has a $12.5 million aggregate deductible for this incident, we do not
expect any additional amounts that may be incurred related to this incident to
have a material adverse affect on our condensed consolidated financial
statements or results of operations. See "-Operating Results."
In September 2003, we recorded a loss of approximately $3.5 million on our
inland barge Rig 20 as a result of a fire. While our insurance coverage has a
$12.5 million aggregate deductible for this incident, we do not expect any
additional amounts that may be incurred related to this incident to have a
material adverse affect on our condensed consolidated financial statements or
results of operations. 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
23
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 receivables are concentrated in certain
oil-producing countries. We generally do not require collateral or other
security to support customer receivables. If the financial condition of our
customers 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 we believe 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, a decrease 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 unable
to realize all or part of our net deferred tax asset in the future, an increase
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.
24
Pension and Other Postretirement Benefits-Our defined benefit pension and
other postretirement benefit (retiree life insurance and medical benefits)
obligations and the related benefit costs are accounted for in accordance with
SFAS 87, Employers' Accounting for Pensions, and SFAS 106, Employers' Accounting
for Postretirement Benefits Other than Pensions. Pension and postretirement
costs and obligations are actuarially determined and are affected by assumptions
including expected return on plan assets, discount rates, compensation
increases, employee turnover rates and health care cost trend rates. We evaluate
our assumptions periodically and make adjustments to these assumptions and the
recorded liabilities as necessary.
Two of the most critical assumptions are the expected long-term rate of
return on plan assets and the assumed discount rate. We evaluate our assumptions
regarding the estimated long-term rate of return on plan assets based on
historical experience and future expectations on investment returns, which are
calculated by our third party investment advisor utilizing the asset allocation
classes held by the plan's portfolios. We utilize the Moody's Aa long-term
corporate bond yield as a basis for determining the discount rate for a majority
of our plans. Changes in these and other assumptions used in the actuarial
computations could impact our projected benefit obligations, pension
liabilities, pension expense and other comprehensive income. We base our
determination of pension expense on a market-related valuation of assets that
reduces year-to-year volatility. This market-related valuation recognizes
investment gains or losses over a five-year period from the year in which they
occur. Investment gains or losses for this purpose are the difference between
the expected return calculated using the market-related value of assets and the
actual return based on the market-related value of assets.
Contingent liabilities-We establish reserves for estimated loss
contingencies when we believe a loss is probable and the amount of the loss can
be reasonably estimated. Revisions to contingent liabilities are reflected in
income in the period in which different facts or information become known or
circumstances change that affect our previous assumptions with respect to the
likelihood or amount of loss. Reserves for contingent liabilities are based upon
our assumptions and estimates regarding the probable outcome of the matter.
Should the outcome differ from our assumptions and estimates, revisions to the
estimated reserves for contingent liabilities would be required.
OPERATING RESULTS
QUARTER ENDED SEPTEMBER 30, 2003 COMPARED TO QUARTER ENDED SEPTEMBER 30,
2002
Our revenues for the quarter ended September 30, 2003 decreased by $72.3
million and our operating and maintenance expense increased by $21.9 million
compared to the quarter ended September 30, 2002. Our overall average dayrate
and utilization decreased from $74,500 and 61 percent, respectively, for the
quarter ended September 30, 2002 to $67,000 and 59 percent, respectively, for
the quarter ended September 30, 2003. The decreases in our contract drilling
revenue, average dayrates and utilization 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 riser
separation incident on the drillship Discoverer Enterprise, the well control
incident on inland barge Rig 62, the electrical fire on the Peregrine I and the
fire on inland barge Rig 20. 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.
25
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT
Three Months Ended
September 30,
------------------
2003 2002 Change % Change
-------- -------- -------- ---------
(In millions, except day amounts
and percentages)
Operating days (a) 6,101 6,600 (499) (8)%
Utilization (a) (b) (d) 71% 79% N/A (10)%
Average dayrate (a) (c) (d) $89,000 $94,600 $(5,600) (6)%
Contract drilling revenues $ 544.4 $ 641.2 $ (96.8) (15)%
Client reimbursable revenues 20.0 - 20.0 N/M
-------- -------- -------- ---------
564.4 641.2 (76.8) (12)%
Operating and maintenance 342.4 325.7 16.7 5%
Depreciation 103.9 101.6 2.3 2%
Impairment loss on long-lived assets - 25.7 (25.7) N/M
Gain from sale of assets, net (0.8) (1.8) 1.0 (56)%
-------- -------- -------- ---------
Operating income before general and administrative
expense $ 118.9 $ 190.0 $ (71.1) (37)%
======== ======== ======== =========
_________________
"N/A" means not applicable
"N/M" means not meaningful
(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days
as a percentage of the total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue
earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and
utilization has changed to include all rigs based on contract drilling
revenues. Prior periods have been restated to reflect the change.
Due to a general deterioration in market conditions, average dayrates and
utilization declined resulting in a decrease in this segment's contract drilling
revenues of approximately $88.0 million, excluding the impact of the items
discussed separately below. Contract drilling revenues were also adversely
impacted in the third quarter of 2003 by approximately $8.4 million due to the
riser separation incident on the Discoverer Enterprise and the electrical fire
on the Peregrine I. Other factors contributing to the decrease in revenue in the
third quarter of 2003 were the absence of revenue earned from a leased rig
returned to its owner ($1.2 million) and the settlement of a contract dispute
($15.0 million), both of which occurred in the third quarter of 2002. These
decreases were partially offset by increases in contract drilling revenues from
the Deepwater Frontier ($15.6 million) in the third quarter of 2003, as a result
of the consolidation of DDII LLC late in the second quarter of 2003. See
"-Overview."
Operating revenues for the three months ended September 30, 2003 included
$20.0 million related to costs incurred and billed to customers on a
reimbursable basis. See "-Overview."
A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.
The increase in this segment's operating and maintenance expenses was
primarily due to approximately $22.0 million of costs associated with the riser
separation incident on the Discoverer Enterprise, the consolidation of DDII LLC,
which leases the Deepwater Frontier and the electrical fire on the Peregrine I.
In addition, expenses increased due to costs 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
26
and maintenance expenses of approximately $10.0 million resulting from a rig
returned to its owner during the third quarter of 2002, a decrease in allowance
for doubtful accounts related to the collection of a previously reserved
customer receivable and reduced expense relating to our insurance program.
Additional decreases resulted from $6.8 million of costs incurred in the three
months ended September 30, 2002 associated with restructuring charges and a
litigation provision with no comparable activity in the three months ended
September 30, 2003.
The increase in this segment's depreciation expense resulted primarily from
depreciation expense related to assets reclassified from held for sale to our
active fleet during and subsequent to the three months ended September 30, 2002
because they no longer met the criteria for assets held for sale under SFAS 144.
During the three months ended September 30, 2002, we recorded non-cash
impairment charges of $20.2 million in this segment, related to assets
reclassified from held for sale to our active fleet because they no longer met
the held for sale criteria under SFAS 144. During the nine months ended
September 30, 2002, we also recorded a non-cash impairment charge of $5.5
million related to an asset held for sale, 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. See Note 8
to our condensed consolidated financial statements.
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT
Three Months Ended
September 30,
------------------
2003 2002 Change % Change
-------- -------- -------- ---------
(In millions, except day amounts
and percentages)
Operating days (a) 2,808 2,497 311 12%
Utilization (a) (b) (d) 44% 38% N/A 16%
Average dayrate (a) (c) (d) $19,300 $21,600 $(2,300) (11)%
Contract drilling revenues $ 54.1 $ 54.0 $ 0.1 N/M
Client reimbursable revenues 4.4 - 4.4 N/M
-------- -------- -------- ---------
58.5 54.0 4.5 8%
Operating and maintenance 60.6 55.4 5.2 9%
Depreciation 22.9 22.6 0.3 1%
Impairment loss on long-lived assets - 15.2 (15.2) N/M
Gain from sale of assets, net (0.1) (1.1) 1.0 (91)%
-------- -------- -------- ---------
Operating loss before general and administrative
expense $ (24.9) $ (38.1) $ 13.2 35%
======== ======== ======== =========
_________________
"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.
Operating revenues for the three months ended September 30, 2003 included
$4.4 million related to costs incurred and billed to customers on a reimbursable
basis. See "-Overview."
27
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 approximately $4.0 million of costs associated with a fire
incident on inland barge Rig 20 and the well control incident on inland barge
Rig 62, as well as an increase in activity of approximately $2.0 million and the
consolidation of a joint venture that owns two land rigs during the third
quarter of 2002 ($0.7 million). In addition, expenses increased due to costs
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 were reduced expenses of $2.1 million
relating to our insurance program in the three months ended September 30, 2003
compared to the same period in 2002 and a decrease of $4.4 million resulting
from severance-related costs and other restructuring charges related to our
decision to close an administrative office and warehouse in Louisiana and
relocate most of the operations and administrative functions previously
conducted at that location, as well as compensation-related expenses resulting
from executive management changes in the three months ended September 30, 2002.
During the three months ended September 30, 2002, we recorded non-cash
impairment charges of $15.2 million in this segment related to assets
reclassified from held for sale to our active fleet because they no longer met
the held for sale criteria under SFAS 144. See Note 8 to our condensed
consolidated financial statements.
TOTAL COMPANY RESULTS OF OPERATIONS
Three Months Ended
September 30,
2003 2002 Change % Change
------- --------- -------- ---------
(In millions, except % change)
General and Administrative Expense $ 21.2 $ 15.8 $ 5.4 34%
Other (Income) Expense, net
Equity in earnings of joint ventures (1.9) (0.4) (1.5) N/M
Interest income (3.0) (6.1) 3.1 51%
Interest expense 49.0 52.3 (3.3) (6)%
Other, net 0.2 1.3 (1.1) (85)%
Income Tax Expense (Benefit) 17.3 (164.8) 182.1 N/M
_________________
"N/M" means not meaningful
The increase in general and administrative expense was primarily
attributable to $8.0 million in expenses relating to the planned IPO of the
company's Gulf of Mexico Shallow and Inland Water business segment for the three
months ended September 30, 2003, of which $6.4 million was deferred in previous
periods. Offsetting the increase was reduced expense of $2.0 million related to
employee benefits for the three months ended September 30, 2003 compared to the
same period in 2002.
The increase in equity in earnings of joint ventures was primarily related
to our 25 percent share of earnings from Delta Towing Holdings, LLC ("Delta
Towing"), in which we recorded a decreased loss in earnings for the three months
ended September 30, 2003 compared to the same period in 2002. Partially
offsetting the increase was a decrease in our 60 percent share of earnings of
DDII LLC, which leases the Deepwater Frontier. DDII LLC was consolidated as a
result of the buyout of ConocoPhillips' 40 percent interest in the joint venture
in May 2003, resulting in no equity in earnings of joint ventures being recorded
for the three months ended September 30, 2003 compared to earnings recorded
during the same period in 2002. The decrease in interest income was primarily
due to interest earned on lower average cash balances and to the establishment
of a reserve for interest income on Delta Towing during the three months ended
September 30, 2003 compared to the same period in 2002. The decrease in interest
expense was primarily due to debt repaid or retired during and subsequent to the
three months ended September 30, 2002, which resulted in an additional $10.6
million reduction in interest expense and 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"),
28
partially offset by the termination of our fixed to floating interest rate swaps
in the first quarter of 2003, which resulted in an increase of $13.4 million.
The decrease in other, net of $1.2 million resulted primarily from the
effect of foreign currency exchange rate changes on a UK pound denominated
escrow deposit in the three months ended September 30, 2003 with no comparable
activity in the corresponding period in 2002.
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. As a result of a change in anticipated 2003 earnings, our annual
effective tax rate is estimated to be approximately 43 percent during 2003 on
earnings before non-cash note receivable and other asset impairments, loss on
debt retirements and IPO-related costs. Due to the increase in the estimated
annual effective tax rate from approximately 38 percent at June 30, 2003,
earnings for the three months ended September 30, 2003 were reduced by $2.6
million as a result of applying the adjusted estimated annual effective tax rate
to the six months ended June 30, 2003. The three months ended September 30, 2002
included a non-U.S. tax benefit of $176.2 million attributable to the
restructuring of certain non-U.S. operations.
NINE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED TO NINE MONTHS ENDED
SEPTEMBER 30, 2002
Our revenues for the nine months ended September 30, 2003 decreased by
$166.5 million and our operating and maintenance expense increased by $75.9
million compared to the nine months ended September 30, 2002. In addition, our
overall average dayrate and utilization decreased from $74,900 and 59 percent,
respectively, for the nine months ended September 30, 2002 to $67,100 and 57
percent, respectively, for the nine months ended September 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, the electrical fire on the Peregrine I and the fire on inland barge Rig 20.
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
Nine Months Ended
September 30,
--------------------
2003 2002 Change % Change
--------- --------- -------- ---------
(In millions, except day amounts
and percentages)
Operating days (a) 17,870 19,971 (2,101) (11)%
Utilization (a) (b) (d) 69% 80% N/A (14)%
Average dayrate (a) (c) (d) $ 89,800 $ 92,700 $(2,900) (3)%
Contract drilling revenues $1,611.0 $1,873.5 $(262.5) (14)%
Client reimbursable revenues 64.6 - 64.6 N/M
--------- --------- -------- ---------
1,675.6 1,873.5 (197.9) (11)%
Operating and maintenance 1,013.8 974.5 39.3 4%
Depreciation 311.9 305.3 6.6 2%
Impairment loss on long-lived assets 5.2 25.7 (20.5) (80)%
Gain from sale of assets, net (2.4) (2.8) 0.4 (14)%
--------- --------- -------- ---------
Operating income before general and administrative
expense $ 347.1 $ 570.8 $(223.7) (39)%
========= ========= ======== =========
_________________
"N/A" means not applicable
29
"N/M" means not meaningful
(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days
as a percentage of the total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue
earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and
utilization has changed to include all rigs based on contract drilling
revenues. Prior periods have been restated to reflect the change.
Due to a general deterioration in market conditions, average dayrates and
utilization declined resulting in a decrease in this segment's contract drilling
revenues of approximately $233.0 million, excluding the impact of the items
discussed separately below. Contract drilling revenues were also adversely
impacted by approximately $31.0 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 ($8.0
million), the return of a leased rig to its owner ($4.0 million), the transfer
of a jackup rig from this segment to the Gulf of Mexico Shallow and Inland Water
segment ($1.7 million) and the settlement of a contract dispute ($15.0 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 ($10.0
million) and from the Deepwater Frontier ($19.8 million) as a result of the
consolidation of DDII LLC late in the second quarter of 2003. See "-Overview."
Operating revenues for the nine months ended September 30, 2003 included
$64.6 million related to costs incurred and billed to customers on a
reimbursable basis. See "-Overview."
A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.
The increase in this segment's operating and maintenance expense was
primarily due to approximately $38.0 million of costs associated with the riser
separation incident on the Discoverer Enterprise, the consolidation of DDII LLC,
which leases the Deepwater Frontier and costs related to the electrical fire on
the Peregrine I. We also incurred additional expense of $5.3 million 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. In
addition, expenses increased due to costs 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 lower
activity of approximately $12.0 million and $10.0 million relating to rigs sold
or returned to owner during and subsequent to the nine months ended September
30, 2002. Expenses were further reduced by $6.7 million relating to the
settlements of a dispute and an insurance claim as well as $6.0 million relating
to a reduction in our insurance program expense during the nine months ended
September 30, 2003. Additional decreases resulted from $6.8 million of costs
incurred in the nine months ended September 30, 2002 associated with
restructuring charges and a litigation provision with no comparable activity in
the nine months ended September 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 nine months
ended September 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 nine months ended September 30, 2002.
During the nine months ended September 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. During the nine months
30
ended September 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.
During the nine months ended September 30, 2002, we recorded non-cash impairment
charges of $20.2 million in this segment related to assets reclassified from
held for sale to our active fleet because they no longer met the held for sale
criteria under SFAS 144. During the nine months ended September 30, 2002, we
also recorded a non-cash impairment charge of $5.5 million related to an asset
held for sale, 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. See Note 8 to our condensed
consolidated financial statements.
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT
Nine Months Ended
September 30,
------------------
2003 2002 Change % Change
-------- -------- -------- ---------
(In millions, except day amounts
and percentages)
Operating days (a) 8,348 6,544 1,804 28%
Utilization (a) (b) (d) 41% 33% N/A 24%
Average dayrate (a) (c) (d) $18,400 $20,800 $(2,400) (12)%
Contract drilling revenues $ 153.7 $ 135.8 $ 17.9 13%
Client reimbursable revenues 13.5 - 13.5 N/M
-------- -------- -------- ---------
167.2 135.8 31.4 23%
Operating and maintenance 189.8 153.2 36.6 24%
Depreciation 69.2 68.8 0.4 1%
Impairment loss on long-lived assets 11.6 16.3 (4.7) (29)%
Gain from sale of assets, net (0.5) (0.7) 0.2 (29)%
-------- -------- -------- ---------
Operating loss before general and administrative
expense $(102.9) $(101.8) $ (1.1) (1)%
======== ======== ======== =========
_________________
"N/A" means not applicable
"N/M" means not meaningful
(a) Applicable to all rigs.
(b) Utilization is defined as the total actual number of revenue earning days
as a percentage of the total number of calendar days in the period.
(c) Average dayrate is defined as contract drilling revenue earned per revenue
earning day.
(d) Effective January 1, 2003, the calculation of average dayrates and
utilization was changed to include all rigs based on contract drilling
revenues. Prior periods have been restated to reflect the change.
Higher utilization resulted in an increase in this segment's contract
drilling revenue of $41.7 million, partially offset by decreased average
dayrates ($21.9 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 nine months ended September 30, 2002 ($2.0 million).
Operating revenues for the nine months ended September 30, 2003 included
$13.5 million related to costs incurred and billed to customers on a
reimbursable basis. See "-Overview."
A large portion of our operating and maintenance expense consists of
employee-related costs and is fixed or only semi-variable. Accordingly,
operating and maintenance expense does not vary in direct proportion to activity
or dayrates.
31
The increase in this segment's operating and maintenance expenses was due
primarily to an increase in activity of approximately $20.0 million and
approximately $11.0 million of costs associated with the well control incident
on inland barge Rig 62 and the fire incident on inland barge Rig 20, as well as
an insurance claim provision ($2.5 million) and the consolidation of a joint
venture that owns two land rigs during the third quarter of 2002 ($1.9 million).
In addition, expenses increased due to costs recognized as operating and
maintenance expense relating to client reimbursable expenses as a result of
implementing EITF 99-19 during the nine months ended September 30, 2003 (see
"-Overview"). These increases were partially offset by reduced expense of $3.1
million relating to our insurance program in the nine months ended September 30,
2003 compared to the same period in 2002, the release of a provision for
doubtful accounts ($1.8 million) during the first nine months of 2003 upon
collection of amounts previously reserved, lower expenses resulting from the
transfer of a jackup rig from this segment into the International and U.S.
Floater Contract Drilling Services segment ($1.8 million) during the second
quarter of 2002 and a decrease of $4.4 million resulting from severance-related
costs and other restructuring charges related to our decision to close an
administrative office and warehouse in Louisiana and relocate most of the
operations and administrative functions previously conducted at that location,
as well as compensation-related expenses resulting from executive management
changes in the nine months ended September 30, 2002.
During the nine months ended September 30, 2003, we recorded non-cash
impairment charges of $10.6 million in this segment, which resulted from our
decision to remove five jackup rigs from 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 nine months
ended September 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 nine months ended September 30, 2002, we
recorded non-cash impairment charges of $15.2 million in this segment related to
assets reclassified from held for sale to our active fleet because they no
longer met the held for sale criteria under SFAS 144. Also during the nine
months ended September 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. See Note 8 to our condensed consolidated financial statements.
TOTAL COMPANY RESULTS OF OPERATIONS
Nine Months Ended
September 30,
---------------------
2003 2002 Change % Change
--------- ---------- ---------- ---------
(In millions, except % change)
General and Administrative Expense $ 50.0 $ 51.6 $ (1.6) (3)%
Other (Income) Expense, net
Equity in earnings of joint ventures (7.3) (4.8) (2.5) 52%
Interest income (15.7) (16.0) 0.3 2%
Interest expense 154.4 160.7 (6.3) (4)%
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 3.5 (0.2) 3.7 N/M
Income Tax Expense (Benefit) 8.3 (137.1) 145.4 N/M
Cumulative Effect of a Change in Accounting Principle - 1,363.7 (1,363.7) N/M
_________________
"N/M" means not meaningful
32
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, reduced expense of $5.5 million related to
employee benefits in the nine months ended September 30, 2003 compared to the
same period in 2002. Offsetting these decreases was $8.0 million in expenses
relating to the planned IPO of the company's Gulf of Mexico Shallow and Inland
Water business segment for the nine months ended September 30, 2003, of which
$3.1 million was deferred in previous periods.
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 nine months of 2002 in which
the rig experienced shipyard downtime. Also contributing to the increase in
equity in earnings of joint ventures was our 50 percent share of earnings of
Deepwater Drilling L.L.C. ("DD LLC"), which owns the Deepwater Pathfinder. This
rig experienced increased utilization and average dayrates in the nine months
ended September 2003 compared to the same period in 2002. Also contributing to
the increase was our 25 percent share of earnings from Delta Towing in which we
recorded a decreased loss in earnings for the nine months ended September 30,
2003 compared to the same period in 2002, partially offset by our share of a
$2.5 million non-cash impairment charge on the carrying value of Delta Towing's
idle equipment.
The decrease in interest expense was attributable to reductions of interest
expense of $19.1 million associated with debt refinanced, repaid or retired
during and subsequent to the nine months ended September 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
$30.5 million, partially offset by a $16.5 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 nine months ended September 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 nine months ended September 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 effect of
foreign currency exchange rate changes on our monetary assets and liabilities
denominated in Venezuelan bolivars (see "-Item 3. Quantitative and Qualitative
Disclosures about Market Risk-Foreign Exchange Risk"), partially offset by a
$1.2 million gain resulting from the effect of foreign currency exchange rate
changes on a UK pound denominated escrow deposit for the nine months ended
September 30, 2003 compared to the same period in 2002.
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 nine months ended September 30, 2003 included a tax benefit of
$14.6 million attributable to the favorable resolution of a non-U.S. income tax
liability, partially offset by an increase in our estimated annual effective tax
rate to approximately 43 percent for 2003 on earnings before non-cash note
receivable and other asset impairments, loss on debt retirements and IPO-related
costs compared to our effective tax rate of approximately 14 percent for 2002.
The increase in our estimated effective tax rate resulted from a change in
anticipated 2003 earnings. The nine months ended September 30, 2002 included a
non-U.S. tax benefit of $175.7 million attributable to the restructuring of
certain non-U.S. operations.
During the nine months ended September 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.
33
FINANCIAL CONDITION
September 30, December 31, %
2003 2002 Change Change
-------------- --------------------------------
(In millions)
TOTAL ASSETS
International and U.S. Floater Contract Drilling Services $ 10,996.6 $ 11,804.1 $(807.5) (7)%
Gulf of Mexico Shallow and Inland Water 721.1 861.0 (139.9) (16)%
-------------- --------------------------------
$ 11,717.7 $ 12,665.1 $(947.4) (7)%
============== ================================
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 ($438.2 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 "-Derivative Instruments"). In addition, the sale of a
jackup rig ($12.5 million net book value), normal depreciation ($311.9 million)
and asset impairments ($5.2 million) during 2003 further reduced the assets in
this segment (see "-Operating Results"). Offsetting this decrease was an
increase in accounts receivable ($47.2 million) and notes receivable from
related party ($44.2 million). The decrease in the assets of the Gulf of Mexico
Shallow and Inland Water segment was primarily due to normal depreciation ($69.2
million), a decrease in accounts receivable ($62.2 million), asset impairments
($11.6 million) and the impairment of a related party note receivable ($21.3
million) during 2003 (see "-Operating Results").
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 September 30, 2003, $2.5 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 September 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 September 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.
34
OUTLOOK
Fleet utilization and average dayrates increased within our International
and U.S. Floater Contract Drilling Services and Gulf of Mexico Shallow and
Inland Water business segments during the third quarter of 2003 compared with
the second quarter of 2003.
Comparative average dayrates and utilization figures are set forth in the
table below.
Three Months Ended
-------------------------------------------
September 30, June 30, September 30,
2003 2003 2002
--------------- ---------- ---------------
AVERAGE DAYRATES (a)(b)(d)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation $ 176,600 $ 185,100 $ 190,100
Other Deepwater $ 112,500 $ 111,500 $ 115,200
Total Deepwater $ 145,500 $ 147,500 $ 148,000
Mid-Water $ 70,900 $ 73,600 $ 83,000
Jackups - Non-U.S. $ 54,400 $ 57,400 $ 60,400
Other Rigs $ 48,800 $ 41,500 $ 49,300
--------------- ---------- ---------------
Segment Total $ 89,000 $ 88,900 $ 94,600
--------------- ---------- ---------------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles $ 20,800 $ 18,200 $ 22,400
Inland Barges $ 16,900 $ 16,100 $ 20,700
Other Rigs $ 20,500 $ 18,600 $ 23,400
--------------- ---------- ---------------
Segment Total $ 19,300 $ 17,500 $ 21,600
--------------- ---------- ---------------
Total Mobile Offshore Drilling Fleet $ 67,000 $ 65,300 $ 74,500
=============== ========== ===============
UTILIZATION (a)(c)(d)
INTERNATIONAL AND U.S. FLOATER CONTRACT DRILLING SERVICES SEGMENT:
Deepwater
5th Generation 97% 88% 90%
Other Deepwater 73% 70% 85%
Total Deepwater 84% 78% 87%
Mid-Water 54% 55% 74%
Jackups - Non-U.S. 85% 86% 84%
Other Rigs 49% 41% 56%
--------------- ---------- ---------------
Segment Total 71% 68% 79%
--------------- ---------- ---------------
GULF OF MEXICO SHALLOW AND INLAND WATER SEGMENT:
Jackups and Submersibles 54% 44% 32%
Inland Barges 38% 39% 47%
Other Rigs 38% 44% 31%
--------------- ---------- ---------------
Segment Total 44% 42% 38%
--------------- ---------- ---------------
Total Mobile Offshore Drilling Fleet 59% 57% 61%
=============== ========== ===============
_________________
(a) Applicable to all rigs.
(b) Average dayrate is defined as contract drilling revenue earned per revenue earning day.
35
(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 maintained historically strong levels throughout the
third quarter, and we believe the trading markets and other indicators point
towards continued near-term strength in oil and gas prices. While future
commodity price expectations are a key driver for offshore drilling demand, the
availability of drilling prospects, relative production costs, the stage of
reservoir development and political/regulatory environments all impact our
customers' drilling programs. Strong commodity prices have not translated into
overall increased offshore drilling activity in the recent quarter, or in 2003
generally. On a global basis, we do not expect a material increase in drilling
demand over the next six to nine months.
Prospects for our International and U.S. Floater Contract Drilling Services
business segment are uncertain over the next six to nine months. Over this
period, market dayrates for the industry's most technically advanced deepwater
rigs will be difficult to predict and intermittent idle time could be
experienced as a number of these units, including four of our 5th Generation
deepwater rigs, conclude contracts. We continue to believe that over the long
term, deepwater exploration and development drilling opportunities in Angola,
Nigeria, India and other emerging locations represent a potentially significant
source of future rig demand.
A stable level of activity is expected to persist in most of the
international jackup market sectors. The modest overcapacity present in the West
Africa jackup market sector is expected to largely dissipate by mid-2004,
although dayrates associated with near-term contract signings in the region are
expected to decline from average levels experienced over the past 12 months.
India has remained a key destination for jackups, as evidenced by the number of
jackup rigs that have been and are expected to be added over the second half of
2003. The Far East jackup market sector activity has remained largely flat,
although dayrates have held up as rigs have moved outside the region.
The mid-water floater business remains extremely weak as this sector
continues to be significantly oversupplied globally. We expect overall North Sea
utilization to remain below 50% this winter, due in part to reduced drilling
programs by the major oil companies. In the U.S. Gulf of Mexico, mid-water rig
demand is currently further dampened by increased competition from underutilized
deepwater rigs, which have greater operating and technical capability. Absent a
significant pick-up in overall offshore demand, we expect the global mid-water
sector to continue to be oversupplied through 2004.
The Gulf of Mexico Shallow and Inland Water business segment continues to
benefit from a declining base of jackup rig supply in the Gulf of Mexico, which
has helped to lift utilization and dayrates in an otherwise flat rig demand
environment. Demand in the Gulf of Mexico inland barge fleet has trended lower,
while total supply is unchanged. However, deep gas drilling interest among
several exploration and production companies operating in the Gulf of Mexico is
expected to increase, offering the prospect for improving demand in 2004.
The offshore contract drilling market remains highly competitive and
cyclical, and it has been historically difficult to forecast future market
conditions. Extraneous risks include declines in oil and/or gas prices that
reduce demand and adversely affect utilization and day rates. Major operator and
national oil company capital budgets are key drivers of the overall business
climate, and these may change within a fiscal year depending on exploration
results and other factors. Additionally, increased competition for our
customers' drilling budgets could come from, among other areas, land-based
energy markets in Russia, other former Soviet Union states and the Middle East.
Effective December 31, 2003 we will adopt the provisions of the Financial
Accounting Standards Board's ("FASB") Interpretation ("FIN") 46, Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51. As a result of the adoption, we expect to consolidate certain joint
ventures. See "-New Accounting Pronouncements."
36
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 our tax returns for calendar 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 various non-U.S. assessments that
have been asserted and would expect to contest any future U.S. or non-U.S.
assessments. While the outcome of existing or future assessments cannot be
predicted, 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 a change in anticipated 2003
earnings, our annual effective tax rate is estimated to be approximately 43
percent for 2003 on earnings before non-cash note receivable and other asset
impairments, loss on debt retirements and IPO-related costs. Included in the tax
provision for the nine months ended September 30, 2003 was a tax benefit of
$14.6 million attributable to the favorable resolution of a non-U.S. income tax
liability.
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
are not required to make a 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. 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.
We maintain a severance plan (the "Nigeria Plan"), which provides
postretirement benefits to certain employees under a labor contract with the
Nigeria labor unions. Under the Nigeria Plan provisions, employees receive
postretirement benefits in the event of retirement, termination for redundancy,
or death. We made 83 employees redundant effective May 2003. In accordance with
the provisions of the Plan, we paid approximately $2.6 million in termination
benefits in August 2003. Additionally, as a result of these terminations, and in
accordance with the provisions of SFAS 88, Employers' Accounting for Settlements
and Curtailments of Defined Benefit Pension Plans and for Termination Benefits,
we recorded a plan curtailment gain of $0.8 million, net of a settlement loss of
$0.3 million.
We are engaged in negotiations with the Nigeria labor unions for a new
labor contract. We expect these negotiations to be resolved in the fourth
quarter of 2003 and to result in the settlement of the entire benefit obligation
and other negotiated costs, and an amendment to the Nigeria Plan. In accordance
with SFAS 87, Employers' Accounting for Pensions, the benefit costs accrued
through the date of the amendment will be amortized over future periods as a
reduction to future benefit costs. We expect the payment of approximately $21
million in settlement of the entire benefit obligation and other negotiated
costs to occur during the fourth quarter of 2003. As a result of the settlement
of the Nigeria Plan and the payment of the entire benefit obligation and other
negotiated costs, we expect to record additional expense up to approximately
$13.0 million in the fourth quarter of 2003.
In May 2003, we announced that a drilling riser had separated on our
deepwater drillship Discoverer Enterprise and that the rig had temporarily
suspended drilling operations for our customer. The rig resumed operations in
July 2003, but we are in discussion with our customer regarding the appropriate
dayrate treatment. Results for the three months ended September 30, 2003 were
negatively impacted by approximately $17 million due to an ongoing disagreement
with our customer concerning the applicable dayrate and other costs. This
disagreement has continued with respect to operations conducted in the fourth
quarter and will likely continue to adversely affect results for that quarter.
We are in discussions with ConocoPhillips concerning their 50 percent
interest in DD LLC, which leases the Deepwater Pathfinder under a synthetic
lease financing arrangement. No definitive agreement or terms have been reached,
and we or ConocoPhillips may decide to discontinue these discussions. If we do
acquire the 50 percent interest we do not already own, we would expect to use
cash on hand and borrowings under available revolving credit facilities for the
purchase. Even if we do not acquire ConocoPhillips' interest in the joint
venture, we expect to consolidate DD LLC effective December 31, 2003 (see "-New
Accounting Pronouncements").
As of September 30, 2003, we had goodwill of approximately $2.2 billion,
all of which is related to our International and U.S. Floater Contract Drilling
Services segment. In accordance with SFAS 142, we are in the process of
conducting our annual test of goodwill impairment as of October 1 of this year.
Our stock price has declined slightly from October 1, 2002 to October 1, 2003,
which is an indicator of a potential impairment of our goodwill. However,
37
the amount of the impairment, if any, will not be known until we complete our
annual test during the fourth quarter. Any such impairment would affect only our
International and U.S. Floater Contract Drilling Services segment and would have
no impact on our bank covenants.
As of October 28, 2003, approximately 67 percent and 36 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 20
percent for the remainder of 2003 and 5 percent are currently committed for the
year 2004.
LIQUIDITY AND CAPITAL RESOURCES
SOURCES AND USES OF CASH
Nine Months Ended
September 30,
-------------------------
2003 2002 Change
-------------- --------- ----------
(In millions)
NET CASH PROVIDED BY OPERATING ACTIVITIES
Net income (loss) $ 13.7 $ (951.2) $ 964.9
Depreciation 381.1 374.1 7.0
Other non-cash items 23.0 1,211.8 (1,188.8)
Changes in working capital items 46.8 65.5 (18.7)
-------------- --------- ----------
$ 464.6 $ 700.2 $ (235.6)
============== ========= ==========
Net cash provided by operating activities decreased during the nine months
ended September 30, 2003 as compared to the same period in the previous year.
The decrease was primarily related to a decrease in other non-cash items. Other
non-cash items during the nine months ended September 30, 2003 consisted
primarily of $15.7 million, $21.3 million and $16.8 million related to loss on
retirement of debt, an impairment of notes receivable - related party, and
impairment of long-lived assets, respectively, partially offset by $30.7 million
related to deferred and other items. This compared to other non-cash items
during the nine months ended September 30, 2002 of a goodwill impairment charge
of $1,363.7 million, a $175.7 million foreign tax benefit and a $42.0 million
impairment of long-lived assets partially offset by $18.3 million in deferred
and other items. Cash provided by changes in working capital items decreased
during the nine months ended September 30, 2003, as compared to the same period
in 2002 due to lower revenues resulting in a reduction in accounts receivable
coupled with an increase in net interest payable, which resulted from 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.
Nine Months Ended
September 30,
--------------------
2003 2002 Change
---------- -------- -------
(In millions)
NET CASH USED IN INVESTING ACTIVITIES
Capital expenditures $ (73.6) $(114.6) $ 41.0
Note issued to related party, net of repayments (44.2) - (44.2)
Proceeds from disposal of assets 4.1 73.6 (69.5)
Acquisition of 40% interest in DDII LLC, net of
cash aquired 18.1 - 18.1
Other, net 2.8 4.6 (1.8)
---------- -------- -------
$ (92.8) $ (36.4) $(56.4)
========== ======== =======
Net cash used in investing activities increased for the nine months ended
September 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 year capital expenditures (see "-Capital
Expenditures"). A note receivable of $46.1
38
million was issued to a related party and we acquired ConocoPhillips' 40 percent
interest in DDII LLC in May 2003 (see "-Overview").
Nine Months Ended
September 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 (967.2) (154.3) (812.9)
Other, net 14.0 (14.7) 28.7
------------ -------- --------
$ (779.7) $(495.4) $(284.3)
============ ======== ========
We repaid $326.4 million under our commercial paper program during the nine
months ended September 30, 2002 with no comparable activity for the same period
in 2003. During the nine months ended September 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 $390.0 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 $103.7 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 TODCO's 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 nine
months ended September 30, 2002. Payment of dividends was discontinued after the
second quarter of 2002.
CAPITAL EXPENDITURES
Capital expenditures totaled $73.6 million during the nine months ended
September 30, 2003. During 2003, we expect to spend approximately $120.0 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 expect to
incur capital expenditures of under approximately $100.0 million in 2004 on our
existing fleet, corporate infrastructure and major upgrades. We would expect any
additional asset acquisitions and improved market conditions to affect future
capital expenditures.
We intend to fund the cash requirements relating to our capital
expenditures through available cash balances, cash generated from operations and
asset sales. We also have available borrowings under our revolving credit
agreements and commercial paper program (see "-Sources of Liquidity") and may
engage in other commercial bank or capital market financings.
ACQUISITIONS AND DISPOSITIONS
From time to time, we review possible acquisitions or dispositions of
businesses and drilling units and may in the future make significant capital
commitments for such purposes. Any such acquisition could involve the payment by
us of a substantial amount of cash or the issuance of a substantial number of
additional ordinary shares or other securities. We would likely fund the cash
portion of any such acquisition through cash balances on hand, the incurrence of
additional debt, sales of assets, ordinary shares or other securities or a
combination thereof.
In 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 gain of $0.2 million, net of tax of
$0.1 million. The proceeds were received in December 2002.
During the nine months ended September 30, 2003, we settled an insurance
claim and sold certain other assets for net proceeds of approximately $4.1
million and recorded net gains of $1.9 million ($0.01 per diluted share), net of
39
tax of $0.2 million, in our International and U.S. Floater Contract Drilling
Services segment and $0.3 million, net of tax of $0.2 million, in our Gulf of
Mexico Shallow and Inland Water segment.
In November 2003, we purchased the remaining 25 percent minority interest
in the Caspian Sea Ventures International Limited ("CSVI") joint venture that we
did not already own. CSVI owns the jackup rig Trident 20.
We continue to proceed with our previously announced plans to pursue an IPO
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 IPO 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 third quarter of 2003 were our cash
flows from operations and existing cash balances. The primary uses of cash were
debt repayment and capital expenditures. At September 30, 2003, we had $806.3
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 and 2004, 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 IPO, as well as any proceeds from
asset sales (see "-Acquisitions and Dispositions"), to further reduce our debt
balances and for general corporate purposes.
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 September 30, 2003 and December 31, 2002, our total debt was
$3,701.4 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 nine months ended September 30, 2003,
we reduced net debt, defined as total debt less swap receivables and cash and
cash equivalents, by $387.4 million. The components of net debt at carrying
value were as follows (in millions):
September 30, December 31,
2003 2002
--------------- --------------
Total Debt $ 3,701.4 $ 4,678.0
--------------- --------------
Less: Cash and cash equivalents (806.3) (1,214.2)
Swap receivables - (181.3)
We believe net debt provides useful information regarding the level of our
indebtedness by reflecting the amount of indebtedness assuming cash and
investments are used to repay debt. Net debt 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 sectors 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.
40
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 September 30,
2003, none of the credit line capacity was utilized. We do not presently intend
to renew the $250 million, 364-day credit facility when it expires in December
2003. Instead, we intend to renew the five-year facility during either the
fourth quarter of 2003 or the first quarter of 2004 for an increased capacity of
up to $800 million.
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 September 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 (in millions).
For the twelve months ending September 30,
-----------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
-------- ------ ---------- ---------- -----------
CONTRACTUAL OBLIGATIONS
Debt $3,519.5 $281.5 $ 819.0 $ 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 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 September 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
41
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 and borrowings under available
revolving credit facilities to repay our portion of the debt and equity
financing with respect to 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.
For the twelve months ending September 30,
------------------------------------------------------------
Total 2004 2005-2006 2007-2008 Thereafter
-------------- ------ ---------- ---------- -----------
(In millions)
OTHER COMMERCIAL COMMITMENTS
Standby Letters of Credit $ 204.1 $180.3 $ 6.0 $ 17.8 $ -
Surety Bonds 169.8 66.6 103.2 - -
Purchase Option Guarantees - Related Party (a) 151.8 151.8 - - -
Purchase Option Guarantees - Joint Ventures (a) 92.6 92.6 - - -
Other Commitments 1.2 - 1.2 - -
-------------- ------ ---------- ---------- -----------
Total $ 619.5 $491.3 $ 110.4 $ 17.8 $ -
============== ====== ========== ========== ===========
____________________________
(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 with an
expiration date of October 2003 that had aggregate market values netting to a
liability of $0.7 million at September 30, 2003. Our 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 in our condensed consolidated balance sheet. These
swaps terminated on October 31, 2003.
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.
42
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 and July 2003, Delta
Towing also failed to make additional scheduled quarterly interest payments of
$1.6 million and $1.7 million, respectively. During the nine months ended
September 30, 2003, we received partial interest payments of approximately $1.0
million and $1.1 million of payments applied to principal on the three-year
revolving credit facility. At September 30, 2003, we had interest receivable
from Delta Towing of approximately $4.0 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 September 30, 2003, the carrying value of the notes receivable
included in investments in and advances to joint ventures in our condensed
consolidated balance sheets, net of the related allowance for credit losses and
equity losses in the joint venture, was $53.6 million. In September 2003, we
established a reserve of $1.6 million for interest income earned during the
third quarter on the notes receivable and will continue to reserve future
interest income earned until the scheduled quarterly interest payments have been
brought current. We 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 drillship Deepwater Frontier. In May
2003, WestLB AG, one of the lenders in the synthetic lease financing facility,
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 September 30, 2003, the balance of the note
receivable was $44.2 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 Interpretation No. 46, Consolidation
of Variable Interest Entities, an Interpretation of Accounting Research Bulletin
No. 51 (the "Interpretation"). The Interpretation requires the consolidation of
variable interest entities in which an enterprise absorbs a majority of the
entity's expected losses, receives a majority of the entity's expected residual
returns, or both, as a result of ownership, contractual or other financial
interests in the entity. The provisions of the Interpretation are effective
immediately for those variable interest entities created after January 31, 2003.
The provisions, as amended, are effective for the first interim or annual period
ending after December 15, 2003 for those variable interest entities held prior
to February 1, 2003. We will adopt the Interpretation and consolidate our
variable interest entities as required on December 31, 2003. Currently, we
generally consolidate an entity when we have a controlling interest through
ownership of a majority voting interest in the entity.
We have a 25 percent ownership interest in Delta Towing, a joint venture
established for the purpose of owning and operating inland and shallow water
marine support vessel equipment. At the time Delta Towing 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 carrying value of the notes receivable
included in investments in and advances to joint ventures in our condensed
consolidated balance sheets was $53.6 million, net of the related allowance for
credit losses and equity losses in the joint venture, at September 30, 2003.
Delta Towing also issued a $3.0 million note to the 75 percent joint
43
venture partner. Because we have the largest percentage of investment at risk
through the notes receivable and Delta Towing's equity is not sufficient to
absorb its expected losses, we would absorb the majority of the joint venture's
expected losses; therefore, we are deemed to be the primary beneficiary of Delta
Towing for accounting purposes. As such, we will consolidate Delta Towing
effective December 31, 2003. While we expect the consolidation of Delta Towing
to result in an increase in net assets of approximately $1.0 million based on
balances at September 30, 2003, the expected amounts may be adjusted upon
consolidation at December 31, 2003 with application of the provisions of the
Interpretation.
We have a 50 percent ownership interest in DD LLC. DD LLC was established
for the purpose of constructing and contracting the drillship Deepwater
Pathfinder. The drillship was purchased by a trust that was established to
finance the purchase through debt and equity financing and to lease the
drillship back to DD LLC through a synthetic lease financing arrangement with
the drillship serving as collateral. The balance of the trust's debt and equity
financing was approximately $189.7 million at September 30, 2003. The scheduled
expiration of the lease is January 2004, at which time DD LLC may purchase the
drillship from the trust for approximately $185 million. DD LLC currently
intends to exercise its purchase option early in December 2003. While the
operations of DD LLC are funded by cash flows from operating activities, we
guarantee, under certain circumstances, the debt and equity financing on the
leased drillship equally with our joint venture partner. We have determined
through application of the provisions of the Interpretation for determining the
primary beneficiary that we are deemed to be DD LLC's primary beneficiary for
accounting purposes and will consolidate the entity effective December 31, 2003.
While we expect the consolidation of DD LLC to result in an increase in net
assets of approximately $116 million based on balances at September 30, 2003,
the expected amounts may be adjusted upon consolidation at December 31, 2003
with application of the provisions of the Interpretation. As previously
discussed (see "-Outlook"), we are in negotiations with ConocoPhillips to
purchase their 50 percent interest in the joint venture. If we are successful in
buying ConocoPhillips' interest in DD LLC prior to December 31, 2003, the
provisions of the Interpretation would not apply as we would consolidate DD LLC
as a wholly-owned subsidiary. We would then expect consolidation of DD LLC to
result in an increase in net assets of approximately $208 million.
We have investments in and advances to four additional joint ventures.
These remaining four joint ventures were primarily established for the purpose
of owning and operating certain drilling units and are funded primarily by cash
flows from operating activities. Based on our initial assessment, these entities
would not be deemed variable interest entities under the Interpretation. We
expect to complete our analysis of these entities during the fourth quarter of
2003.We currently account for our investments in joint ventures 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.
Our wholly owned subsidiary, DDII LLC was originally established as a joint
venture with a subsidiary of ConocoPhillips for the purpose of constructing and
contracting the drillship Deepwater Frontier. The drillship was purchased by a
trust that was established to finance the purchase through debt and equity
financing and to lease the drillship back to DDII LLC through a synthetic lease
financing arrangement with the drillship serving as collateral. The balance of
the trust's debt and equity financing at September 30, 2003 was approximately
$158.0 million, net of a note receivable - related party (see "-Special Purpose
Entities, Sale/Leaseback Transaction and Related Party Transactions"). On May
29, 2003, we purchased ConocoPhillips' 40 percent interest in DDII LLC. We
currently account for DDII LLC's lease of the drillship as an operating lease.
As a result of our purchase of ConocoPhillips' 40 percent interest in DDII LLC,
we, under certain circumstances, fully guarantee the debt and equity financing.
Because we are at risk for the full amount of the debt and equity financing, we
are deemed to be the primary beneficiary of the trust for accounting purposes
and expect to consolidate the trust effective December 31, 2003. While we
expect the consolidation of the trust to result in an increase in net assets of
approximately $27 million based on balances at September 30, 2003, the expected
amounts may be adjusted upon consolidation at December 31, 2003 with application
of the provisions of the Interpretation.
In addition to the joint ventures and DDII LLC discussed above, we are
party to a sale/leaseback transaction for the semisubmersible drilling rig M.G.
Hulme, Jr. with an unrelated third party. Under the sale/leaseback agreement, we
have the option to purchase the semisubmersible drilling rig at the end of the
lease for a maximum amount of
44
approximately $35.7 million. We are currently evaluating whether the unrelated
third party lessor is a variable interest entity and, if so, who would be deemed
to be the primary beneficiary. We currently account for the lease of this
drilling rig as an operating lease.
We are currently evaluating the cumulative effect of the accounting change
on our results of operations that will result from the implementation of the
Interpretation.
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 customers on a reimbursable basis
are recognized as operating and maintenance expense. In addition, the amounts
billed to our customers 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. The statement
clarifies the accounting for certain financial instruments that, under previous
guidance, issuers could account for as equity. This statement requires an issuer
to measure and classify as liabilities, or assets in some circumstances, certain
classes of freestanding financial instruments that embody obligations for the
issuer. In addition to its requirement for the classification and measurement of
financial instruments in its scope, SFAS 150 also requires disclosures about
alternative ways of settling the instruments and the identity of the entity that
controls the settlement alternatives. 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 adopted this statement effective July 1, 2003. The adoption of this
statement did not 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, West Africa and
other emerging locations, oversupply in the global mid-water sector, expected
North Sea utilization, outlook for the deepwater sector, oversupply in the West
Africa jackup market 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, expected deep gas
drilling interest in the Gulf of Mexico, the expected charge relating to
termination of the Nigerian severance plan, expected resolution of negotiations
with the Nigeria labor unions regarding a new labor contract, the outcome and
effect of the U.S. Internal Revenue Service audit and the various tax
assessments, deferred costs, amortization expense, the planned IPO of our Gulf
of Mexico Shallow and Inland Water business (including the timing of the
offering, portion sold and expected use of proceeds), the U.S. gas drilling
market, planned asset sales, the Company's other expectations with regard to
market outlook, the effect of our disagreement relating to the Discoverer
Enterprise, the purchase of the DD LLC interest, an impairment to goodwill,
expected capital expenditures, expected funding of capital expenditures, results
and effects of legal proceedings, liabilities for tax issues, liquidity,
intention not to renew the Company's 364-day credit facility, expected renewal
of the Company's five-year credit facility, positive cash flow from operations,
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,
45
DD LLC and DDII LLC, adequacy of cash flow for 2003 obligations, effects of
accounting changes, impact of consolidation of variable interest entities, 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.
46
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 September 30 relating to debt obligations as
of September 30, 2003. Weighted-average variable rates are based on LIBOR rates
in effect at September 30, 2003, plus applicable margins.
At September 30, 2003 (in millions, except interest rate percentages):
Scheduled Maturity Date (a) (b) Fair Value
-------------------------------------------------------------------- ----------
2004 2005 2006 2007 2008 Thereafter Total 09/30/03
------- ------- ------- ------- ------- ------------ --------- ----------
Total debt
Fixed Rate $131.5 $381.5 $400.0 $100.0 $269.0 $ 2,050.0 $3,332.0 $ 3,753.7
Average interest rate 8.5% 6.8% 1.5% 7.5% 6.7% 7.5% 6.7%
Variable Rate $150.0 $ 37.5 - - - - $187.5 $ 187.5
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 September 30, 2003, we had approximately $187.5 million of variable rate
debt at face value (approximately five 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
$1.5 million in interest expense per year. Offsetting this, a large part of our
cash investments would earn commensurately higher rates of return. Using
September 30, 2003 cash investment levels, a one percent increase in interest
rates would result in approximately $8.1 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 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. We do not enter into derivative transactions for speculative
purposes. At September 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 loss of
$1.5 million, net of tax of $0.8 million, on the revaluation of the local
currency into functional U.S dollars during the second quarter of 2003. In the
third quarter of 2003, to limit our local currency exposure, we entered into an
interim arrangement with one of our customers in which we are to receive 55
percent of the billed receivables in U.S. dollars with the remainder paid in
local currency.
47
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 September 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 September 30, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.
48
PART II - OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
In August 2003, a judgment of approximately $9.5 million was entered by the
Labor Division of the Provincial Court of Luanda, Angola, against us and a labor
contractor for us, Hull Blyth, in favor of certain former workers on several of
our drilling rigs. The workers were employed by Hull Blyth to work on several
drilling rigs while the rigs were located in Angola. When the drilling contracts
concluded and the rigs left Angola, the workers' employment ended. The workers
brought suit claiming that they were not properly compensated when their
employment ended. In addition to the monetary judgment, the Labor Division
ordered the workers to be hired by us. We believe that this judgment is without
sufficient legal foundation and have appealed the matter to the Angola Supreme
Court. We further believe that Hull Blyth has an obligation to protect us from
any judgment. We do not believe that the ultimate outcome of this matter will
have a material adverse effect on our business or consolidated financial
position.
We have certain other actions or claims pending that have been previously
discussed and reported in our Annual Report on Form 10-K for the year ended
December 31, 2002 and our other reports filed with the Securities and Exchange
Commission. There have been no material developments in these previously
reported matters. We are involved in a number of other lawsuits, all of which
have arisen in the ordinary course of our business. We do not believe that
ultimate liability, if any, resulting from any such other pending litigation
will have a material adverse effect on our business or consolidated financial
position. There can be no assurance that our beliefs or expectations as to the
outcome or effect of any lawsuit or other litigation matter will prove correct
and the eventual outcome of these matters could materially differ from
management's current estimates.
49
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
(a) Exhibits
The following exhibits are filed in connection with this Report:
NUMBER DESCRIPTION
------ -----------
*3.1 Memorandum of Association of Transocean Inc., as amended (incorporated by
reference to Annex E to the Joint Proxy Statement/Prospectus dated October
30, 2000 included in a 424(b)(3) prospectus filed by the Company on
November 1, 2000)
*3.2 Articles of Association of Transocean Inc., as amended (incorporated by
reference to Annex F to the Joint Proxy Statement/Prospectus dated October
30, 2000 included in a 424(b)(3) prospectus filed by the Company on
November 1, 2000)
*3.3 Certificate of Incorporation on Change of Name to Transocean Inc.
(incorporated by reference to Exhibit 3.3 to the Company's Form 10-Q for
the quarter ended June 30, 2002)
+4.1 Amendment No. 1, dated December 27, 2001, to the Credit Agreement dated as
of December 29, 2000 among the Company, the Lenders party thereto,
Suntrust Bank, Administrative Agent, ABN AMRO Bank, N.V., as Syndication
Agent, Bank of America, N.V., as Documentation Agent, and Wells Fargo Bank
Texas, National Association, as Senior Managing Agent
+4.2 Amendment No. 2, dated December 26, 2002, to the Credit Agreement dated as
of December 29, 2000 among the Company, the Lenders party thereto,
Suntrust Bank, Administrative Agent, ABN AMRO Bank, N.V., as Syndication
Agent, Bank of America, N.V., as Documentation Agent, and Wells Fargo Bank
Texas, National Association, as Senior Managing Agent
+4.3 Amendment No. 1, dated December 27, 2001, to the Credit Agreement dated as
of December 16, 1999 among Transocean Offshore Inc., the Lenders party
thereto, and Suntrust Bank, Atlanta, as Agent
+4.4 Amendment No. 2, dated December 26, 2002, to the Credit Agreement dated as
of December 16, 1999 among Transocean Offshore Inc., the Lenders party
thereto, and Suntrust Bank, Atlanta, as Agent
+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 July 23, 2003
(information furnished not filed) announcing the issuance of expected second
quarter 2003 financial results, a Current Report on Form 8-K on July 29, 2003
(information furnished not filed) announcing the issuance of second quarter 2003
financial results and a Current Report on Form 8-K on August 11, 2003
(information furnished not filed) announcing financial information in connection
with presentations being made by officers of the Company.
50
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 November 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)
51