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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, DC 20549
FORM 10-Q
[X] Quarterly Report Pursuant to Section 13 or 15(d) of the Securities
Exchange Act of 1934 for the quarterly period ended September 30, 2004
[ ] 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: 000-22739
Cal Dive International, Inc.
(Exact Name of Registrant as Specified in its Charter)
Minnesota 95-3409686
(State or Other Jurisdiction of (IRS Employer Identification Number)
Incorporation or Organization)
400 N. Sam Houston Parkway E.
Suite 400
Houston, Texas 77060
(Address of Principal Executive Offices)
(281) 618-0400
(Registrant's telephone number,
including area code)
Indicate by check whether the registrant: (1) has filed all reports
required to be filed by Section 13(b) or 15(d) of the Securities Exchange Act
of 1934 during the preceding 12 months (or 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 whether the registrant is an accelerated filer (as defined in
Rule 12b-2 of the Exchange Act).
Yes [X] No [ ]
At November 4, 2004 there were 38,377,859 shares of common stock, no par
value, outstanding.
CAL DIVE INTERNATIONAL, INC.
INDEX
Part I. Financial Information Page
Item 1. Financial Statements Page
Condensed Consolidated Balance Sheets -
September 30, 2004 and December 31, 2003............................ 1
Condensed Consolidated Statements of Operations -
Three Months Ended September 30, 2004 and
September 30, 2003............................................. 2
Nine Months Ended September 30, 2004 and September 30, 2003......... 3
Condensed Consolidated Statements of Cash Flows -
Nine Months Ended September 30, 2004 and September 30, 2003......... 4
Notes to Condensed Consolidated Financial Statements....................... 5
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations............................14
Item 3. Quantitative and Qualitative Disclosure About Market Risk.......22
Item 4. Controls and Procedures.........................................23
Part II: Other Information
Item 1. Legal Proceedings...............................................23
Item 6. Exhibits........................................................24
Signatures.................................................................25
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN THOUSANDS)
SEPTEMBER 30, DECEMBER 31,
2004 2003
---- ----
(UNAUDITED)
ASSETS
Current assets:
Cash and cash equivalents................................................ $ 49,859 $ 6,378
Restricted cash.......................................................... - 2,433
Accounts receivable--
Trade, net of revenue allowance on gross amounts billed
of $7,789 and $8,518................................................. 81,729 78,733
Unbilled revenue...................................................... 17,216 17,874
Other current assets..................................................... 44,761 25,232
--------- ---------
Total current assets............................................. 193,565 130,650
--------- ---------
Property and equipment..................................................... 835,068 802,694
Less-- Accumulated depreciation.......................................... (249,680) (183,891)
--------- ---------
585,388 618,803
Other assets:
Investment in production facilities - Deepwater Gateway, L.L.C.......... 54,481 34,517
Goodwill, net............................................................ 82,682 81,877
Other assets, net........................................................ 28,057 16,995
--------- ---------
$ 944,173 $ 882,842
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable......................................................... $ 39,235 $ 50,897
Accrued liabilities...................................................... 65,884 36,850
Current maturities of long-term debt..................................... 8,765 16,199
--------- ---------
Total current liabilities........................................ 113,884 103,946
--------- ---------
Long-term debt............................................................. 140,919 206,632
Deferred income taxes...................................................... 115,120 89,274
Decommissioning liabilities................................................ 73,538 75,269
Other long-term liabilities................................................ 1,353 2,042
--------- ---------
Total liabilities................................................ 444,814 477,163
Convertible preferred stock................................................ 54,549 24,538
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 120,000 shares authorized, 51,946
and 51,460 shares issued.............................................. 210,494 199,999
Retained earnings........................................................ 233,365 178,718
Treasury stock, 13,602 shares, at cost................................... (3,741) (3,741)
Accumulated other comprehensive income................................... 4,692 6,165
--------- ---------
Total shareholders' equity....................................... 444,810 381,141
--------- ---------
$ 944,173 $ 882,842
========= =========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
1
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
THREE MONTHS ENDED
SEPTEMBER 30,
2004 2003
---------- ----------
Net revenues:
Marine contracting...................................... $ 71,988 $ 69,897
Oil and gas production.................................. 59,999 33,958
---------- ----------
131,987 103,855
Cost of sales:
Marine contracting...................................... 59,539 62,530
Oil and gas production.................................. 26,722 17,320
---------- ----------
Gross profit......................................... 45,726 24,005
Selling and administrative expenses....................... 10,926 8,620
---------- ----------
Income from operations.................................... 34,800 15,385
Equity in earnings of Deepwater Gateway, L.L.C.......... 3,062 -
Net interest expense and other.......................... 838 855
---------- ----------
Income before income taxes................................ 37,024 14,530
Provision for income taxes.............................. 13,237 5,231
---------- ----------
Net income................................................ 23,787 9,299
Preferred stock dividends and accretion................. 993 362
---------- ----------
Net income applicable to common shareholders.............. $ 22,794 $ 8,937
========== ==========
Earnings per common share:
Basic.................................................. $ 0.60 $ 0.24
Diluted................................................ $ 0.59 $ 0.24
========== ==========
Weighted average common shares outstanding:
Basic.................................................. 38,294 37,665
Diluted................................................ 39,418 37,776
The accompanying notes are an integral part of these condensed
consolidated financial statements.
2
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)
NINE MONTHS ENDED
SEPTEMBER 30,
2004 2003
---------- ----------
Net revenues:
Marine contracting............................................. $ 203,926 $ 193,108
Oil and gas production......................................... 176,477 101,486
---------- ----------
380,403 294,594
Cost of sales:
Marine contracting............................................. 179,708 176,319
Oil and gas production......................................... 81,812 50,877
---------- ----------
Gross profit................................................ 118,883 67,398
Selling and administrative expenses.............................. 34,746 26,201
---------- ----------
Income from operations........................................... 84,137 41,197
Equity in earnings (losses) of Deepwater Gateway, L.L.C. 4,372 (107)
Net interest expense and other................................. 3,635 2,927
---------- ----------
Income before income taxes and change in accounting principle....
84,874 38,163
Provision for income taxes..................................... 28,486 13,739
---------- ----------
Income before change in accounting principle..................... 56,388 24,424
Cumulative effect of change in accounting
principle, net............................................... - 530
Net Income....................................................... 56,388 24,954
Preferred stock dividends and accretion........................ 1,741 1,068
---------- ----------
Net income applicable to common shareholders..................... $ 54,647 $ 23,886
========== ==========
Earnings per common share Basic:
Earnings per share before change in
accounting principle..................................... $ 1.43 $ 0.62
Cumulative effect of change in accounting
principle.................................................. - 0.01
---------- ----------
Earnings per share........................................... $ 1.43 $ 0.63
========== ==========
Diluted:
Earnings per share before change in accounting principle...... $ 1.41 $ 0.62
Cumulative effect of change in accounting
principle................................................... - 0.01
---------- ----------
Earnings per share........................................... $ 1.41 $ 0.63
========== ==========
Weighted average common shares outstanding:
Basic.......................................................... 38,141 37,618
Diluted........................................................ 39,413 37,715
The accompanying notes are an integral part of these condensed
consolidated financial statements.
3
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN THOUSANDS)
(UNAUDITED)
NINE MONTHS ENDED SEPTEMBER 30,
2004 2003
---------- ----------
Cash flows from operating activities:
Net income...................................................... $ 56,388 $ 24,954
Adjustments to reconcile net income to net cash
provided by operating activities--
Cumulative effect of change in accounting principle.......... - (530)
Depreciation and amortization................................ 78,945 49,821
Deferred income taxes........................................ 28,485 13,739
Equity in (earnings) losses of Deepwater Gateway, L.L.C. (4,372) 107
Loss on sale of assets....................................... 100 45
Changes in operating assets and liabilities:
Accounts receivable, net................................... (2,117) (21,596)
Other current assets....................................... (19,628) 926
Accounts payable and accrued liabilities................... 13,705 1,574
Other noncurrent, net...................................... (21,711) (11,486)
---------- ----------
Net cash provided by operating activities............... 129,795 57,554
---------- ----------
Cash flows from investing activities:
Capital expenditures............................................ (25,998) (73,987)
Acquisition of businesses, net of cash acquired................ - (407)
Investment in Deepwater Gateway, L.L.C.......................... (15,592) (1,792)
Restricted cash................................................. (8,485) 74
Proceeds from (payments on) sales of property................... (100) 200
---------- ----------
Net cash used in investing activities................... (50,175) (75,912)
---------- ----------
Cash flows from financing activities:
Sale of convertible preferred stock, net of transaction costs. 29,340 24,100
Repayment of MARAD borrowings................................... (2,946) (2,767)
Repayments on line of credit, net............................... (30,189) (16,717)
Deferred financing costs........................................ (727) -
Borrowings on term loan......................................... - 5,707
Repayment of term loan borrowings............................... (35,000) -
Borrowing on capital leases..................................... - 12,000
Capital lease payments.......................................... (2,614) (1,303)
Preferred stock dividends paid.................................. (1,070) (731)
Redemption of stock in subsidiary............................... (2,462) (2,676)
Exercise of stock options, net.................................. 9,475 3,430
---------- ----------
Net cash (used in) provided by financing activities...... (36,193) 21,043
---------- ----------
Effect of exchange rate changes on cash and cash
equivalents..................................................... 54 27
Net increase in cash and cash equivalents......................... 43,481 2,712
Cash and cash equivalents:
Balance, beginning of period.................................... 6,378 -
---------- ----------
Balance, end of period.......................................... $ 49,859 $ 2,712
=========== ==========
The accompanying notes are an integral part of these condensed
consolidated financial statements.
4
CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
Note 1 - Basis of Presentation
The accompanying condensed consolidated financial statements include
the accounts of Cal Dive International, Inc., (collectively, "Cal Dive", "CDI"
or the "Company") and its majority-owned subsidiaries. The Company accounts for
its 50% interest in Deepwater Gateway, L.L.C. using the equity method of
accounting as the Company does not have voting or operational control of this
entity. All material intercompany accounts and transactions have been
eliminated. These condensed consolidated financial statements are unaudited,
have been prepared pursuant to instructions for the Quarterly Report on Form
10-Q required to be filed with the Securities and Exchange Commission and do
not include all information and footnotes normally included in annual financial
statements prepared in accordance with generally accepted accounting
principles.
Management has reflected all adjustments (which were normal recurring
adjustments) that it believes are necessary for a fair presentation of the
condensed consolidated balance sheets, results of operations and cash flows, as
applicable. Operating results for the period ended September 30, 2004 are not
necessarily indicative of the results that may be expected for the year ending
December 31, 2004. The Company's balance sheet as of December 31, 2003 included
herein has been derived from the audited balance sheet as of December 31, 2003
included in the Company's 2003 Annual Report on Form 10-K. These condensed
consolidated financial statements should be read in conjunction with the annual
consolidated financial statements and notes thereto included in the Company's
2003 Annual Report on Form 10-K.
Certain reclassifications were made to previously reported amounts in
the condensed consolidated financial statements and notes thereto to make them
consistent with the current presentation format.
Note 2 - Statement of Cash Flow Information
The Company defines cash and cash equivalents as cash and all highly
liquid financial instruments with original maturities of less than three
months. The Company had $2.4 million of restricted cash as of December 31,
2003, of which $2.3 million represented amounts securing a performance bond
which was released in March 2004. As of September 30, 2004, the Company had
$10.9 million of restricted cash included in other assets, net, of which $10.8
million related to Energy Resource Technology, Inc. ("ERT") escrow funds for
decommissioning liabilities associated with the South Marsh Island 130 ("SMI
130") field acquisitions in 2002. Under the purchase agreement, ERT is
obligated to escrow 50% of production up to the first $20 million of escrow and
37.5% of production on the remaining balance up to $33 million in total escrow.
Once the escrow reaches $10 million, ERT may use the restricted cash for
decommissioning the related fields.
During the three and nine months ended September 30, 2004, the Company
made cash payments for interest charges, net of capitalized interest, of $1.4
million and $3.2 million, respectively. During the three and nine months ended
September 30, 2003, the Company made cash payments for interest charges, net of
capitalized interest, of $1.1 million and $2.5 million, respectively.
Note 3 - Offshore Properties
The Company follows the successful efforts method of accounting for
its interests in oil and gas properties. Under the successful efforts method,
the costs of successful wells and leases containing productive reserves are
capitalized. Costs incurred to drill and equip development wells, including
5
unsuccessful development wells, are capitalized. Costs incurred relating to
unsuccessful exploratory wells are expensed in the period the drilling is
determined to be unsuccessful.
Note 4 - Major Customers and Concentration of Credit Risk
In March 2004, the Company elected not to renew its alliance with
Horizon Offshore, Inc. As part of the settlement of outstanding trade accounts
receivable with Horizon, the Company obtained exclusive use of a Horizon
spoolbase facility for a period of five years. Utilization of the spoolbase
facility was valued at approximately $2.0 million with the Company offsetting a
corresponding amount of trade accounts receivable in exchange for the
utilization agreement. The value of the spoolbase facility is being amortized
over the five year term of the agreement. Trade receivables from Horizon at
September 30, 2004 and December 31, 2003 were approximately $3.7 million and
$11.0 million, respectively.
Note 5 - Comprehensive Income
The components of total comprehensive income for the three and nine
months ended September 30, 2004 and 2003 are as follows (in thousands):
Three Months Ended Nine Months Ended
September 30, September 30,
---------------------- --------------------------
2004 2003 2004 2003
--------- --------- --------- ----------
Net Income.............................................. $ 23,787 $ 9,299 $ 56,388 $ 24,954
Foreign currency translation adjustment, net............ 546 (690) 1,754 657
Unrealized gain (loss) on commodity hedges, net......... (2,775) 3,990 (3,227) 2,194
--------- --------- --------- ----------
Total comprehensive income.............................. $ 21,558 $ 12,599 $ 54,915 $ 27,805
========= ========= ========= ==========
The components of accumulated other comprehensive income are as follows
(in thousands):
September 30, Dec. 31,
2004 2003
--------- ---------
Cumulative foreign currency translation adjustment, net............................. $ 9,346 $ 7,592
Unrealized loss on commodity hedges, net............................................ (4,654) (1,427)
--------- --------
Accumulated other comprehensive income ............................................. $ 4,692 $ 6,165
========= ========
Note 6 - Derivatives
The Company's price risk management activities involve the use of
derivative financial instruments to hedge the impact of market price risk
exposures primarily related to the Company's oil and gas production. All
derivatives are reflected in the Company's balance sheet at fair value.
During 2003 and the first nine months of 2004, the Company entered
into various cash flow hedging swap and costless collar contracts to stabilize
cash flows relating to a portion of the Company's expected oil and gas
production. All of these qualified for hedge accounting and none extended
beyond a year and a half. The aggregate fair value of the hedge instruments was
a net liability of $7.1 million as of September 30, 2004. The Company recorded
approximately $3.2 million of unrealized losses, net of taxes of $1.7 million,
during the first nine months of 2004 in other comprehensive income, a component
of shareholders' equity, as these hedges were highly effective. During the
third quarter and first nine months of 2004, the Company reclassified
approximately $2.9 million and $6.8 million, respectively, of
6
losses from other comprehensive income to Oil and Gas Production revenues upon
the sale of the related oil and gas production.
As of September 30, 2004, the Company had the following volumes under
derivative contracts related to its oil and gas producing activities:
AVERAGE MONTHLY WEIGHTED AVERAGE
PRODUCTION PERIOD INSTRUMENT TYPE VOLUMES PRICE
----------------- --------------- --------------- ----------------
Crude Oil:
October - December 2004 Swap 75 MBbl $ 31.53
January - June 2005 Swap 20 MBbl $ 35.80
January - September 2005 Collar 40 MBbl $37.00 - $47.48
Natural Gas:
October - December 2004 Collar 600,000 MMBtu $5.33 - $7.43
January - June 2005 Collar 300,000 MMBtu $5.67 - $8.15
Note 7 - Foreign Currency
The functional currency for the Company's foreign subsidiary Well Ops
(U.K.) Limited is the applicable local currency (British Pound). Results of
operations for this subsidiary are translated into U.S. dollars using average
exchange rates during the period. Assets and liabilities of this foreign
subsidiary are translated into U.S. dollars using the exchange rate in effect
at the balance sheet date and the resulting translation adjustment, which was a
gain of $546,000 and $1.8 million, net of taxes of $294,000 and $944,000,
respectively, in the third quarter and first nine months of 2004, respectively,
is included in accumulated other comprehensive income, a component of
shareholders' equity. All foreign currency transaction gains and losses are
recognized currently in the statements of operations. These amounts for the
third quarter and nine months ended September 30, 2004 were not material to the
Company's results of operations or cash flows.
Canyon Offshore, Inc. ("Canyon"), the Company's ROV subsidiary, has
operations in the United Kingdom and Southeast Asia sectors. Canyon conducts
the majority of its operations in these regions in U.S. dollars which it
considers the functional currency. When currencies other than the U.S. dollar
are to be paid or received, the resulting transaction gain or loss is
recognized in the statements of operations. These amounts for the third quarter
and nine months ended September 30, 2004 were not material to the Company's
results of operations or cash flows.
Note 8 - Earnings Per Share
Basic earnings per share ("EPS") is computed by dividing the net
income available to common shareholders by the weighted-average shares of
outstanding common stock. The calculation of diluted EPS is similar to basic
EPS except the denominator includes dilutive common stock equivalents and the
income included in the numerator excludes the effects of the impact of dilutive
common stock equivalents, if any. The computation of basic and diluted per
share amounts for the Company were as follows (in thousands, except per share
amounts):
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
------- ------- ------- -------
Income before change in accounting principle.......... $23,787 $ 9,299 $56,388 $24,424
Preferred stock dividends and accretion............... (993) (362) (1,741) (1,068)
------- ------- ------- -------
7
Net income applicable to common shareholders before
change in accounting principle........................ $22,794 $ 8,937 $54,647 $23,356
======= ======= ======= =======
Weighted-average common shares outstanding:
Basic....................................... 38,294 37,665 38,141 37,618
Effect of dilutive stock options............ 291 111 250 97
Effect of convertible preferred stock....... 833 - 1,022 -
------- ------- ------- -------
Diluted..................................... 39,418 37,776 39,413 37,715
======= ======= ======= =======
Basic Earnings Per Share:
Income before change in accounting
principle ........................... $ 0.62 $ 0.25 $ 1.48 $ 0.65
Preferred stock dividends and accretion. (0.02) (0.01) (0.05) (0.03)
------- ------- ------- -------
$ 0.60 $ 0.24 $ 1.43 $ 0.62
======= ======= ======= =======
Diluted Earnings Per Share:
Income before change in accounting
principle ............................ $ 0.60 $ 0.25 $ 1.42 $ 0.65
Preferred stock dividends and accretion. (0.01) (0.01) (0.01) (0.03)
------- ------- ------- -------
$ 0.59 $ 0.24 $ 1.41 $ 0.62
======= ======= ======= =======
Stock options to purchase approximately 1.1 million shares for each of
the three and nine months ended September 30, 2003, respectively, were not
dilutive and, therefore, were not included in the computations of diluted
income per common share amounts. In addition, approximately 982,000 shares and
350,000 shares attributable to the convertible preferred stock were excluded in
the three and nine months ended September 30, 2004, respectively, calculation
of diluted EPS, as the effect was antidilutive. Further, approximately 1.1
million shares attributable to the convertible preferred stock were excluded in
the three and nine months ended September 30, 2003, respectively, calculation
of diluted EPS, as the effect was antidilutive. Net income for the diluted
earnings per share calculation for the three and nine months ended September
30, 2004 was adjusted to add back the preferred stock dividends and accretion
on the 833,000 shares and the 1.0 million shares, respectively.
Note 9 - Stock Based Compensation Plans
The Company uses the intrinsic value method of accounting to account
for its stock-based compensation programs. Accordingly, no compensation expense
is recognized when the exercise price of an employee stock option is equal to
the common share market price on the grant date. The following table reflects
the Company's pro forma results if the fair value method had been used for the
accounting for these plans (in thousands, except per share amounts):
8
Three Months Ended Nine Months Ended
Net income applicable to common shareholders September 30, September 30,
before change in accounting principle: 2004 2003 2004 2003
------- ------- ------- -------
As Reported................................. $22,794 $ 8,937 $54,647 $23,356
Stock-based employee compensation
cost, net of tax.......................... (640) (802) (1,726) (2,692)
------- ------- ------- -------
Pro Forma................................... $22,154 $ 8,135 $52,921 $20,664
======= ======= ======= =======
Earnings per common share before
change in accounting principle:
Basic, as reported...................... $ 0.60 $ 0.24 $ 1.43 $ 0.62
Stock-based employee compensations
cost, net of tax...................... (0.02) (0.02) (0.04) (0.07)
------- ------- ------- -------
Basic, pro forma....................... $ 0.58 $ 0.22 $ 1.39 $ 0.55
======= ======= ======= =======
Diluted, as reported................... $ 0.59 $ 0.24 $ 1.41 $ 0.62
Stock-based employee
compensation cost, net of tax........ (0.02) (0.02) (0.04) (0.07)
------- ------- ------- -------
Diluted, pro forma..................... $ 0.57 $ 0.22 $ 1.37 $ 0.55
======= ======= ======= =======
For the purposes of pro forma disclosures, the fair value of each
option grant is estimated on the date of grant using the Black-Scholes option
pricing model with the following weighted average assumptions used: expected
dividend yields of 0 percent; expected lives ranging from three to ten years;
risk-free interest rate assumed to be approximately 4.0 percent and 3.8 percent
in 2004 and 2003, respectively; and expected volatility to be approximately 56
percent and 59 percent, respectively, in 2004 and 2003. The fair value of
shares issued under the Employee Stock Purchase Plan was based on the 15
percent discount received by the employees. The weighted average per share fair
value of the options granted during the first nine months of 2004 and 2003 was
$17.59 and $12.63, respectively. The estimated fair value of the options is
amortized to pro forma expense over the vesting period.
Note 10 - Business Segment Information (in thousands)
September 30, 2004 December 31, 2003
------------------ -----------------
Identifiable Assets --
Marine contracting......................... $ 672,925 $ 623,095
Oil and gas production..................... 271,248 259,747
--------- ---------
Total.................................. $ 944,173 $ 882,842
========= =========
Three Months Ended Nine Months Ended
September 30, September 30,
2004 2003 2004 2003
------- ------- ------- -------
Income from operations -
Marine contracting.................... $ 5,946 $ 1,859 $ 2,413 $ 101
Oil and gas production................ 28,854 13,526 81,724 41,096
------- ------- ------- -------
Total............................. $34,800 $15,385 $84,137 $41,197
======= ======= ======= =======
During the three and nine months ended September 30, 2004, the Company
derived $13.8 million and $48.6 million, respectively, of its revenues from the
U.K. sector utilizing $119.8 million of its total assets in this region. During
the three and nine months ended September 30, 2003, the Company derived $15.9
million and $37.7 million, respectively, from the U.K. sector utilizing $112.2
million of its total assets in this region. Additionally, $67,000 and $2.3
million, of revenues were derived from the Latin America sector during the
three and nine months ended September 30, 2004, respectively, and $7.1 million
and $40.2 million during the three and nine months ended September 30, 2003,
respectively. The majority of the remaining revenues were generated in the U.S.
Gulf of Mexico.
9
Note 11 - Long-Term Debt
At September 30, 2004, $136.4 million was outstanding on our long-term
financing for construction of the Q4000. This U.S. Government guaranteed
financing is pursuant to Title XI of the Merchant Marine Act of 1936 which is
administered by the Maritime Administration ("MARAD Debt"). The MARAD Debt is
payable in equal semi-annual installments which began in August 2002 and
matures 25 years from such date. The MARAD Debt is collateralized by the Q4000,
with CDI guaranteeing 50% of the debt, and bears interest at a rate which
currently floats at a rate approximating AAA Commercial Paper yields plus 20
basis points (approximately 1.4% as of September 30, 2004). For a period up to
ten years from delivery of the vessel in April 2002, CDI has the ability to
lock in a fixed rate. In accordance with the MARAD Debt agreements, CDI is
required to comply with certain covenants and restrictions, including the
maintenance of minimum net worth, working capital and debt-to-equity
requirements. As of September 30, 2004, the Company was in compliance with
these covenants.
The Company had a $70 million revolving credit facility originally due
in February 2005. This facility was collateralized by accounts receivable and
certain of the Company's Marine Contracting vessels. This facility was
cancelled and terminated in August 2004 and replaced by the new $150 million
revolving credit facility described below.
In August 2004, the Company entered into a four-year, $150 million
revolving credit facility with a syndicate of banks, with Bank of America, N.A.
as administrative agent and lead arranger. The amount available under the
facility may be increased to $250 million at any time upon the agreement of the
Company and existing or additional lenders. The new credit facility is secured
by the stock in certain Company subsidiaries and contains a negative pledge on
assets. The new facility bears interest at LIBOR plus 75 - 175 basis points
depending on Company leverage and contains financial covenants relative to the
Company's level of debt to EBITDA, as defined in the credit facility, fixed
charge coverage and book value of assets coverage. As of September 30, 2004,
the Company was in compliance with these covenants and there was no outstanding
balance under this facility.
The Company had a $35 million term loan facility which was obtained to
assist CDI in funding its portion of the construction costs of the spar for the
Gunnison field. The loan was repaid in full in August 2004 and the loan
agreement was subsequently cancelled and terminated.
In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary - "COL")
(with a parent guarantee from Cal Dive) completed a capital lease with a bank
refinancing the construction costs of a newbuild 750 horsepower trenching unit
and a ROV. COL received proceeds of $12 million for the assets and agreed to
pay the bank sixty monthly installment payments of $217,174 (resulting in an
implicit interest rate of 3.29%). No gain or loss resulted from this
transaction. COL has an option to purchase the assets at the end of the lease
term for $1. The proceeds were used to reduce the Company's revolving credit
facility, which had initially funded the construction costs of the assets. This
transaction was accounted for as a capital lease with the present value of the
lease obligation (and corresponding asset) being reflected on the Company's
consolidated balance sheet beginning in the third quarter of 2003.
Scheduled maturities of Long-term Debt outstanding as of September 30,
2004 were as follows (in thousands):
Capital
MARAD Lease &
Debt Revolver Other Total
------------ ------------ ----------- -----------
Less than one year $ 3,144 $ -- $ 5,621 $ 8,765
One to two years 3,352 -- 3,001 6,353
Two to Three years 3,573 -- 2,511 6,084
Three to four years 3,809 -- 2,140 5,949
Four to five years 4,061 -- -- 4,061
Over five years 118,472 -- -- 118,472
-------- ------ -------- ----------
Long-term debt 136,411 -- 13,273 149,684
Current maturities (3,144) -- (5,621) (8,765)
-------- ------ -------- ----------
Long-term debt, less
current maturities $133,267 $ -- $ 7,652 $140,919
-------- ------ -------- ----------
10
The Company had unsecured letters of credit outstanding at September
30, 2004 totalling approximately $3.4 million. These letters of credit
primarily guarantee various contract bidding and insurance activities.
In June 2004, the Deepwater Gateway, L.L.C. construction loan,
excluded from the Company's long-term debt, was converted to a term loan. The
term loan is collateralized by substantially all of Deepwater Gateway, L.L.C.'s
assets and is non-recourse to the Company except for the balloon payment due at
the end of the term. In the event of default, the Company would be required to
pay up to $22.5 million; however, the Company has not recorded any liability
for this guarantee as management believes that it is unlikely the Company will
be required to pay the $22.5 million.
The Company capitalized interest totaling $0 and $243,000 during the
three and nine months ended September 30, 2004 respectively. The Company
capitalized interest totaling $857,000 and $2.7 million during the three and
nine months ended September 30, 2003, respectively. The Company incurred
interest expense of $694,000 and $3.2 million during the three and nine months
ended September 30, 2004, respectively, and $639,000 and $2.2 million during
the three and nine months ended September 30, 2003, respectively.
Note 12 - Income Taxes
The Internal Revenue Service ("IRS") concluded its examination of the
2001 pre-acquisition income tax return for Canyon in the second quarter of
2004. The resolution of this audit did not have a material impact on the
condensed consolidated financial statements of the Company.
The examination of the Company's 2001 and 2002 income tax returns by
the IRS was concluded in the first quarter of 2004. As a result, the Company
recorded an income tax benefit of $1.7 million during the first quarter of 2004
primarily related to research and development credits offset by $430,000 of
interest expense related to timing differences with respect to research and
development deductions.
The Company considers the undistributed earnings of its non-U.S.
subsidiaries to be permanently reinvested. The Company has not provided
deferred U.S. income tax on those earnings, as it is not practicable to
estimate the amount of additional tax that might be payable should these
earnings be remitted or deemed remitted as dividends, or if the Company should
sell its stock in the subsidiaries.
Note 13 - Commitments and Contingencies
The Company is involved in various routine legal proceedings,
primarily involving claims for personal injury under the General Maritime Laws
of the United States and the Jones Act as a result of alleged negligence. In
addition, the Company from time to time incurs other claims, such as contract
disputes, in the normal course of business. In that regard, in 1998, one of the
Company's subsidiaries entered into a subcontract with Seacore Marine
Contractors Limited ("Seacore") to provide the Sea Sorceress to a Coflexip
subsidiary in Canada ("Coflexip"). Due to difficulties with respect to the sea
and soil conditions, the contract was terminated and an arbitration to recover
damages was commenced. A preliminary liability finding has been made by the
arbitrator against Seacore and in favor of the Coflexip subsidiary. The Company
was not a party to this arbitration proceeding. Seacore and Coflexip settled
this matter prior to the conclusion of the arbitration proceeding with Seacore
paying Coflexip $6.95 million CDN. Seacore has initiated an arbitration
proceeding against Cal Dive Offshore Ltd. ("CDO"), a subsidiary of Cal Dive,
seeking contribution of one-half of this amount. One of the grounds in the
11
preliminary findings by the arbitrator is applicable to CDO, and CDO holds
substantial counterclaims against Seacore.
During 2002, the Company engaged in a large construction project
offshore Trinidad and in late September of that year, supports engineered by a
subcontractor failed resulting in over a month of downtime for two of CDI's
vessels. Management believes under the terms of the contract the Company is
entitled to indemnification for the contractual stand-by rate for the vessels
during their downtime. The customer has disputed these invoices along with
certain other change orders. In May 2004, the Company and its customer settled
certain elements of the dispute. Of the amounts billed by CDI for this project,
$6.8 million had not been collected as of September 30, 2004. The Company has
initiated arbitration proceedings on the remaining disputed invoices in
accordance with the terms of the contract.
As of September 30, 2004, the Company had committed to purchase an
operations facility in Aberdeen, Scotland, to serve as the Company's U.K.
headquarters. The purchase closed in October 2004 for approximately U.S. $6.4
million.
As an extension of ERT's well exploitation and PUD strategies, ERT
agreed to participate in the drilling of an exploratory well that targets
reserves in deeper sands, within the same trapping fault system, of a currently
producing well with estimated drilling costs of approximately $15 million, of
which $1.7 million had been incurred through September 30, 2004. If the
drilling is successful, ERT's share of the development cost is estimated to be
an additional $15 million. CDI's Marine Contracting assets would participate in
this development.
Although the above discussed matters have the potential of significant
additional liability, the Company believes the outcome of all such matters and
proceedings will not have a material adverse effect on its consolidated
financial position, results of operations or cash flows.
Note 14 - Canyon Offshore
In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and
telecommunications industries. In connection with the acquisition, the Company
committed to purchase the redeemable stock in Canyon at a price to be
determined by Canyon's performance during the years 2002 through 2004 from
continuing employees at a minimum purchase price of $13.53 per share (or $7.5
million). The Company also agreed to make future payments relating to the tax
impact on the date of redemption, whether employment continued or not. As they
are employees, any share price paid in excess of the $13.53 per share will be
recorded as compensation expense. These remaining shares have been classified
as long-term debt in the accompanying balance sheet and will be adjusted to
their estimated redemption value at each reporting period based on Canyon's
performance. In April 2004 and 2003, the Company purchased approximately
one-third and one-third, respectively, of the redeemable shares at the minimum
purchase price of $13.53 per share. Consideration included approximately
$344,000 and $400,000, respectively, of contingent consideration relating to
tax gross-up payments paid to the Canyon employees in accordance with the
purchase agreement. These gross-up amounts were recorded as goodwill in the
period paid (i.e., the second quarters of 2004 and 2003).
Note 15 - Convertible Preferred Stock
On January 8, 2003, CDI completed the private placement of $25 million
of a newly designated class of cumulative convertible preferred stock (Series
A-1 Cumulative Convertible Preferred Stock, par value $0.01 per share) that is
convertible into 833,334 shares of Cal Dive common stock at $30 per share. The
preferred stock was issued to a private investment firm. Subsequently in June
2004, the preferred stockholder exercised its existing right and purchased $30
million in additional cumulative convertible preferred stock (Series A-2
Cumulative Convertible Preferred Stock, par value $0.01 per
12
share). In accordance with the January 8, 2003 agreement, the $30 million in
additional preferred stock is convertible into 982,029 shares of Cal Dive
common stock at $30.549 per share.
The preferred stock has a minimum annual dividend rate of 4%, subject
to adjustment, payable quarterly in cash or common shares at Cal Dive's option.
CDI paid these dividends in 2004 and 2003 on the last day of the respective
quarter in cash. After the second anniversary of the original issuance, the
holder may redeem the value of its original and additional investment in the
preferred shares to be settled in common stock at the then prevailing market
price or cash at the discretion of the Company. In the event the Company is
unable to deliver registered common shares, CDI could be required to redeem in
cash. Under certain conditions (the Company's stock price falling below $7.35
per share and the occurrence of a restatement in the Company's earnings), the
holder could redeem its investment prior to the second anniversary of the
original issuance.
The proceeds received from the sales of this stock, net of transaction
costs, have been classified outside of shareholders' equity on the balance
sheet below total liabilities. The transaction costs have been deferred, and
are being accreted through the statement of operations through January 2005.
Prior to the conversion, common shares issuable will be assessed for inclusion
in the weighted average shares outstanding for the Company's diluted earnings
per share using the if converted method based on the Company's common share
price at the beginning of the applicable period for the original $25 million
issuance and on the date of issuance (June 25, 2004) for the additional $30
million.
Note 16 - Related Party Transactions
In April 2000, ERT acquired a 20% working interest in Gunnison, a
Deepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Financing for
the exploratory costs of approximately $20 million was provided by an
investment partnership (OKCD Investments, Ltd. or "OKCD"), the investors of
which include current and former CDI senior management, in exchange for a
revenue interest that is an overriding royalty interest of 25% of CDI's 20%
working interest. Production began in December 2003. Payments to OKCD from ERT
totaled $5.5 million and $13.2 million in the three and nine months ended
September 30, 2004, respectively.
13
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS
This Quarterly Report on Form 10-Q includes certain statements that
may be deemed "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Forward-looking statements and
assumptions in this Form 10-Q that are not statements of historical fact
involve risks and assumptions that could cause actual results to vary
materially from those predicted, including among other things, unexpected
delays and operational issues associated with turnkey projects, the price of
crude oil and natural gas, offshore weather conditions, change in site
conditions, and capital expenditures by customers. The Company strongly
encourages readers to note that some or all of the assumptions upon which such
forward looking statements are based are beyond the Company's ability to
control or estimate precisely, and may in some cases be subject to rapid and
material change. For a complete discussion of risk factors, we direct your
attention to our Annual Report on Form 10-K for the year ended December 31,
2003, filed with the Securities and Exchange Commission.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
Our discussion and analysis of our financial condition and results of
operations are based upon our consolidated financial statements. We prepare
these financial statements in conformity with accounting principles generally
accepted in the United States. As such, we are required to make certain
estimates, judgments and assumptions that affect the reported amounts of assets
and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the periods presented. We base our
estimates on historical experience, available information and various other
assumptions we believe to be reasonable under the circumstances. These
estimates may change as new events occur, as more experience is acquired, as
additional information is obtained and as our operating environment changes. We
follow the successful efforts method of accounting for our interests in oil and
gas properties. Under the successful efforts method, the costs of successful
wells and leases containing productive reserves are capitalized. Costs incurred
to drill and equip development wells, including unsuccessful development wells,
are capitalized. Costs incurred relating to unsuccessful exploratory wells are
expensed in the period the drilling is determined to be unsuccessful. There
have been no additional material changes or developments in authoritative
accounting pronouncements or in our evaluation of the accounting estimates and
the underlying assumptions or methodologies that we believe to be Critical
Accounting Policies and Estimates as disclosed in our Form 10-K for the year
ended December 31, 2003.
RESULTS OF OPERATIONS
Comparison of Three Months Ended September 30, 2004 and 2003
Revenues. During the three months ended September 30, 2004, the
Company's revenues increased 27% to $132.0 million compared to $103.9 million
for the three months ended September 30, 2003. Of the overall $28.1 million
increase, $26.0 million was generated by the Oil and Gas Production segment due
to increased oil and gas production and higher commodity prices.
Oil and Gas Production revenue for the three months ended September
30, 2004 increased $26.0 million, or 77%, to $60.0 million from $34.0 million
during the comparable prior year period. Production increased 39% (10 Bcfe for
the three months ended September 30, 2004 compared to 7.2 Bcfe in the third
quarter of 2003) primarily as a result of our successful well exploitation
program, bringing a subsea PUD development at High Island 544 online late in
2003, and Gunnison wells coming online throughout 2004 (2.3 BCFe in third
quarter 2004 compared with 0 BCFe in third quarter 2003). The average realized
natural gas price of $5.82 per Mcf, net of hedges in place, during the third
quarter of 2004 was 23% higher than the $4.61 per Mcf realized in the
comparable prior year quarter while average
14
realized oil prices, net of hedges in place, increased 39% to $38.12 per barrel
compared to $27.41 per barrel realized during the third quarter of 2003.
Gross Profit. Gross profit of $45.7 million for the third quarter of
2004 represented a 90% increase compared to the $24.0 million recorded in the
comparable prior year period with the Oil and Gas Production segment
contributing 77% of the increase. Marine Contracting gross profit increased
$5.1 million to $12.4 million, for the three months ended September 30, 2004,
from $7.4 million in the prior year period. The majority of the increase was
attributable to improved contract pricing for the Company's Well Ops division.
Oil and Gas Production gross profit increased $16.6 million, doubling from the
year ago quarter due to the aforementioned 39% increase in production and
higher commodity prices.
Gross margins of 35% in the third quarter of 2004 were 12 points
better than the 23% in the prior year period. Marine Contracting margins
increased 6 points to 17% for the three months ended September 30, 2004, from
11% in the comparable prior year quarter, due to the factors noted above. In
addition, margins in the Oil and Gas Production segment increased 6 points to
55% for the three months ended September 30, 2004, from 49% in the year ago
quarter, due primarily to the higher oil and gas prices.
Selling & Administrative Expenses. Selling and administrative expenses
of $10.9 million for the three months ended September 30, 2004 were $2.3
million higher than the $8.6 million incurred in the third quarter of 2003 due
to the 2004 Marine Contracting compensation program, which is based on certain
individual performance criteria and the Company's profitability, and the ERT
incentive compensation program, which is tied directly to the Oil and Gas
Production segment profitability that was significantly higher in the third
quarter of 2004 compared to the third quarter of 2003. Selling and
administrative expenses at 8% of revenues for the third quarter of 2004 matched
that of the prior year period.
Equity in Earnings of Deepwater Gateway, L.L.C. Equity in earnings of
the Company's 50% investment in Deepwater Gateway, L.L.C. increased to $3.1
million in the third quarter of 2004 compared with $0 in the comparable prior
year period. The increase was attributable to the demand fees which commenced
following the March 2004 mechanical completion of the Marco Polo tension leg
platform, owned by Deepwater Gateway, L.L.C., as well as production tariff
charges which commenced in the third quarter of 2004.
Other (Income) Expense. The Company reported other expense of $838,000
for the three months ended September 30, 2004 compared to other expense of
$855,000 for the three months ended September 30, 2003. Net interest expense of
$694,000 in the third quarter of 2004 was comparable to the $639,000 incurred
in the three months ended September 30, 2003. However, the Company had $0 of
capitalized interest in the third quarter of 2004 compared with $857,000 in the
third quarter of 2003, which related to the Company's investment in Gunnison
and construction of the Marco Polo tension leg platform. The overall net
decrease in interest (including the effect of capitalized interest) was
primarily due to lower outstanding levels of debt.
Income Taxes. Income taxes increased to $13.2 million for the three
months ended September 30, 2004 compared to $5.2 million in the comparable
prior year period due to increased profitability. The effective tax rate of 36%
in the third quarter of 2004 was comparable to the effective tax rate of 36% in
the prior year period.
Net Income. Net income of $22.8 million for the three months ended
September 30, 2004 was $13.9 million greater than the comparable period in 2003
as a result of factors described above.
Comparison of Nine Months Ended September 30, 2004 and 2003
Revenues. During the nine months ended September 30, 2004, the
Company's revenues increased 29% to $380.4 million compared to $294.6 million
for the nine months ended September 30,
15
2003. Of the overall $85.8 million increase, $75.0 million was generated by the
Oil and Gas Production segment due to increased oil and gas production and
higher commodity prices. Marine Contracting revenues increased $10.8 million
from $193.1 million for the first nine months of 2003 to $203.9 million for the
first nine months of 2004 due primarily to increased utilization and improved
contract pricing for the Company's Well Ops division.
Oil and Gas Production revenue for the nine months ended September 30,
2004 increased $75.0 million, or 74%, to $176.5 million from $101.5 million
during the comparable prior year period. Production increased 45% (30.0 Bcfe
for the nine months ended September 30, 2004 compared to 20.7 Bcfe in the first
nine months of 2003) primarily as a result of our successful well exploitation
program, bringing a subsea PUD development online late in 2003, and Gunnison
wells coming online throughout 2004. The average realized natural gas price of
$5.83 per Mcf, net of hedges in place, during the first nine months of 2004 was
18% higher than the $4.94 per Mcf realized in the comparable prior year period
while average realized oil prices, net of hedges in place, increased 22% to
$33.62 per barrel compared to $27.58 per barrel realized during the first nine
months of 2003.
Gross Profit. Gross profit of $118.9 million for the first nine months
of 2004 represented a 76% increase compared to the $67.4 million recorded in
the comparable prior year period with the Oil and Gas Production segment
contributing 86% of the increase. Marine Contracting gross profit increased to
$24.2 million, for the nine months ended September 30, 2004, from $16.8 million
in the prior year period. The increase was primarily attributable to improved
contract pricing for the Company's Well Ops division. Oil and Gas Production
gross profit increased $44.1 million, or 87%, due to the aforementioned higher
levels of production and commodity price increases.
Gross margins of 31% in the first nine months of 2004 were 8 points
better than the 23% in the first nine months of 2003. Marine Contracting
margins increased 3 points to 12% for the nine months ended September 30, 2004,
from 9% in the comparable prior year period, due to the factors noted above. In
addition, margins in the Oil and Gas Production segment increased 4 points to
54% for the nine months ended September 30, 2004, from 50% in the first nine
months of 2003, due primarily to the higher oil and gas prices.
Selling & Administrative Expenses. Selling and administrative expenses
of $34.7 million for the nine months ended September 30, 2004 were $8.5 million
higher than the $26.2 million incurred in the first nine months of 2003 due
primarily to an increase in the 2004 Marine Contracting compensation program
which is based on certain individual performance criteria and the Company's
profitability, and the ERT incentive compensation program, which is tied
directly to the Oil and Gas Production segment profitability that was
significantly higher in the first nine months of 2004 compared to the first
nine months of 2003. Selling and administrative expenses at 9% of revenues for
the first nine months of 2004 matched that of the prior year period.
Equity in Earnings of Deepwater Gateway, L.L.C. Equity in earnings of
the Company's 50% investment in Deepwater Gateway, L.L.C. increased to $4.4
million in the first nine months of 2004 compared with a loss of $107,000 in
the first nine months of 2003. The increase was attributable to the demand fees
which commenced following the March 2004 mechanical completion of the Marco
Polo tension leg platform, owned by Deepwater Gateway, L.L.C., as well as
production tariff charges which commenced in the third quarter of 2004.
Other (Income) Expense. The Company reported other expense of $3.6
million for the nine months ended September 30, 2004 compared to other expense
of $2.9 million for the nine months ended September 30, 2003. Net interest
expense of $3.2 million in the first nine months of 2004 was higher than the
$2.2 million incurred in the nine months ended September 30, 2003, due
primarily to $243,000 of capitalized interest in the first nine months of 2004,
compared with $2.7 million in the first nine months of 2003, which related to
the Company's investment in Gunnison and construction of the Marco Polo tension
leg platform. Including capitalized interest, total interest decreased due to
lower outstanding levels of debt.
16
Income Taxes. Income taxes increased to $28.5 million for the nine
months ended September 30, 2004 compared to $13.7 million in the comparable
prior year period due to increased profitability. The effective tax rate of 34%
in the first nine months of 2004 is lower than the 36% effective tax rate for
the first nine months of 2003 primarily due to the benefit recognized by the
Company for its research and development credits in the first quarter of 2004,
as a result of the conclusion of the Internal Revenue Service examination of
the Company's income tax returns for 2001 and 2002.
Net Income. Net income of $54.6 million for the nine months ended
September 30, 2004 was $30.8 million greater than the comparable period in 2003
as a result of factors described above.
17
LIQUIDITY AND CAPITAL RESOURCES
In August 2000, we closed the long-term MARAD financing for
construction of the Q4000. This U.S. Government guaranteed financing is
pursuant to Title XI of the Merchant Marine Act of 1936 which is administered
by the Maritime Administration. We refer to this debt as MARAD Debt. In January
2002, we acquired Canyon Offshore, Inc.; in July 2002, we acquired the Well
Operations Business Unit of Technip-Coflexip and, in August 2002, ERT made two
significant property acquisitions. These acquisitions significantly increased
our debt to total book capitalization ratio from 31% at December 31, 2001 to
40% at December 31, 2002. Cash flow from operations, along with the private
placement of convertible preferred stock in January 2003 and June 2004, have
enabled us to reduce this ratio to 23% as of September 30, 2004, as well as to
build $49.9 million of unrestricted cash as of September 30, 2004.
Derivative Activities. The Company's price risk management activities
involve the use of derivative financial instruments to hedge the impact of
market price risk exposures primarily related to the Company's oil and gas
production. All derivatives are reflected in the Company's balance sheet at
fair value.
During 2003 and the first nine months of 2004, the Company entered
into various cash flow hedging swap and costless collar contracts to stabilize
cash flows relating to a portion of the Company's expected oil and gas
production. All of these qualified for hedge accounting and none extended
beyond a year and a half. The aggregate fair value of the hedge instruments was
a net liability of $7.1 million as of September 30, 2004. The Company recorded
approximately $3.2 million of unrealized losses, net of taxes of $1.7 million,
in other comprehensive income, a component of shareholders' equity, as these
hedges were highly effective. During the third quarter and first nine months of
2004, the Company reclassified approximately $2.9 million and $6.8 million,
respectively, of losses from other comprehensive income to Oil and Gas
Production revenues upon the sale of the related oil and gas production.
Operating Activities. Net cash provided by operating activities was
$129.8 million during the nine months ended September 30, 2004, more than two
times the $57.6 million generated during the first nine months of 2003 due
primarily to an increase in profitability ($31.4 million), a $29.1 million
increase in depreciation and amortization resulting from the aforementioned
increase in production levels (including the Gunnison wells that began
producing in December 2003), and higher trade payables and accrued liabilities
balances of $12.1 million due primarily to higher accruals for ERT royalties as
a result of increased production and higher accruals for ERT and Marine
Contracting incentive compensation. Cash flow from operations was negatively
impacted by timing of customer collections on trade accounts receivable ($19.5
million) and an increase in other current assets ($20.6 million) primarily for
prepaid insurance.
In March 2004, the Company elected not to renew its alliance with
Horizon Offshore, Inc. As part of the settlement of outstanding trade accounts
receivable with Horizon, the Company obtained exclusive use of a Horizon
spoolbase facility for a period of five years. Utilization of the spoolbase
facility was valued at approximately $2.0 million with the Company offsetting a
corresponding amount of trade accounts receivable in exchange for the
utilization agreement. The value of the spoolbase facility is being amortized
over the five year term of the agreement. Trade receivables from Horizon at
September 30, 2004 and December 31, 2003 were approximately $3.7 million and
$11.0 million, respectively.
Investing Activities. We incurred $26.0 million of capital
expenditures during the first nine months of 2004 compared to $74.0 million
during the comparable prior year period. Included in the capital expenditures
during the first nine months of 2004 was $5.5 million for the purchase of an
intervention riser system, $5.7 million for ERT well exploitation programs and
$12.4 million for further Gunnison field development. Included in the capital
expenditures during the first nine months of 2003 was $17.5 million for the
Canyon Master Service Agreement with Technip/Coflexip, which included the
construction of a trencher and three ROVs, $22.4 million related to ERT's well
exploitation program and $26.0 million related to Gunnison development costs,
including the spar.
18
In March 2003, ERT acquired additional interests, ranging from 45% to
84%, in four fields acquired in 2002, enabling ERT to take over as operator of
one field. ERT paid $858,000 in cash and assumed Exxon/Mobil's pro-rata share
of the abandonment obligation for the acquired interests.
In January 2002, CDI purchased Canyon, a supplier of remotely operated
vehicles (ROVs) and robotics to the offshore construction and
telecommunications industries. In connection with the acquisition, the Company
committed to purchase the redeemable stock in Canyon at a price to be
determined by Canyon's performance during the years 2002 through 2004 from
continuing employees at a minimum purchase price of $13.53 per share (or $7.5
million). The Company also agreed to make future payments relating to the tax
impact on the date of redemption, whether employment continued or not. As they
are employees, any share price paid in excess of the $13.53 per share will be
recorded as compensation expense. These remaining shares have been classified
as long-term debt in the accompanying balance sheet and will be adjusted to
their estimated redemption value at each reporting period based on Canyon's
performance. In April 2004 and 2003, the Company purchased approximately
one-third and one-third, respectively, of the redeemable shares at the minimum
purchase price of $13.53 per share. Consideration included approximately
$344,000 and $400,000, respectively, of contingent consideration relating to
tax gross-up payments paid to the Canyon employees in accordance with the
purchase agreement. These gross-up amounts were recorded as goodwill in the
period paid (i.e., the second quarters of 2004 and 2003).
In June 2002, CDI, along with GulfTerra Energy Partners L.P.
("GulfTerra"), formed Deepwater Gateway, L.L.C. (a 50/50 venture accounted for
by CDI under the equity method of accounting) to design, construct, install,
own and operate a tension leg platform ("TLP") production hub primarily for
Anadarko Petroleum Corporation's Marco Polo field discovery in the Deepwater
Gulf of Mexico. Our share of the construction costs was approximately $120
million, all of which had been incurred as of September 30, 2004. In August
2002, the Company along with GulfTerra, completed a non-recourse project
financing for this venture, terms of which include a minimum equity investment
in Deepwater Gateway, L.L.C. of $33 million, all of which had been paid as of
September 30, 2004, and is recorded as Investment in Production Facilities in
the accompanying consolidated balance sheet. In June 2004, the Deepwater
Gateway, L.L.C. construction loan, excluded from the Company's long-term debt,
was converted to a term loan. The term loan is collateralized by substantially
all of Deepwater Gateway, L.L.C's assets and is non-recourse to the Company
except for the balloon payment due at the end of the term. In the event of
default, the Company would be required to pay up to $22.5 million; however, the
Company has not recorded any liability for this guarantee as management
believes that it is unlikely the Company will be required to pay the $22.5
million.
In April 2000, ERT acquired a 20% working interest in Gunnison, a
Deepwater Gulf of Mexico prospect of Kerr-McGee Oil & Gas Corp. Financing for
the exploratory costs of approximately $20 million was provided by an
investment partnership (OKCD Investments, Ltd. or "OKCD"), the investors of
which include current and former CDI senior management, in exchange for a
revenue interest that is an overriding royalty interest of 25% of CDI's 20%
working interest. Production began in December 2003. Payments to OKCD from ERT
totaled $5.5 million and $13.2 million in the three and nine months ended
September 30, 2004, respectively.
As of September 30, 2004, the Company had $10.9 million of restricted
cash, included in other assets, net in the accompanying consolidated balance
sheet, of which $10.8 million related to ERT's escrow funds for decommissioning
liabilities associated with the South Marsh Island 130 ("SMI 130") field
acquisitions in 2002. Under the purchase agreement, ERT is obligated to escrow
50% of production up to the first $20 million of escrow and 37.5% of production
on the remaining balance up to $33 million in total escrow. Once the escrow
reaches $10 million, ERT may use the restricted cash for decommissioning the
related fields.
As of September 30, 2004, the Company had committed to purchase an
operations facility in Aberdeen, Scotland, to serve as the Company's U.K.
headquarters. The purchase closed in October 2004 for approximately U.S. $6.4
million.
19
Financing Activities. We have financed seasonal operating requirements
and capital expenditures with internally generated funds, borrowings under
credit facilities, the sale of equity and project financings. Our largest debt
financing has been the MARAD debt. No draws were made on this facility in 2004
and 2003. The MARAD debt is payable in equal semi-annual installments which
began in August 2002 and matures 25 years from such date. We made two payments
each during the nine months ended September 30, 2004 and 2003 totaling $2.9
million and $2.8 million, respectively. The MARAD Debt is collateralized by the
Q4000, with Cal Dive guaranteeing 50% of the debt, and bears an interest rate
which currently floats at a rate approximating AAA Commercial Paper yields plus
20 basis points (approximately 1.4% as of September 30, 2004). For a period up
to ten years from delivery of the vessel in April 2002, the Company has the
ability to lock in a fixed rate. In accordance with the MARAD Debt agreements,
we are required to comply with certain covenants and restrictions, including
the maintenance of minimum net worth, working capital and debt-to-equity
requirements. As of September 30, 2004, we were in compliance with these
covenants.
The Company had a $70 million revolving credit facility originally due
in February 2005. This facility was collateralized by accounts receivable and
certain of the Company's Marine Contracting vessels. This facility was
cancelled and terminated in August 2004 and replaced by the new $150 million
revolving credit facility described below.
In August 2004, the Company entered into a four year, $150 million
revolving credit facility with a syndicate of banks, with Bank of America, N.A.
as administrative agent and lead arranger. The amount available under the
facility may be increased to $250 million at any time upon the agreement of the
Company and existing or additional lenders. The new credit facility is secured
by the stock in certain Company subsidiaries and contains a negative pledge on
assets. The new facility bears interest at LIBOR plus 75 - 175 basis points
depending on Company leverage and contains financial covenants relative to the
Company's level of debt to EBITDA, as defined in the credit facility, fixed
charge coverage and book value of assets coverage. As of September 30, 2004,
the Company was in compliance with these covenants and there was no outstanding
balance under this facility.
The Company had a $35 million term loan facility which was obtained to
assist CDI in funding its portion of the construction costs of the spar for the
Gunnison field. The loan was repaid in full in August 2004 and the loan
agreement was subsequently cancelled and terminated.
In January 2003, CDI completed the private placement of $25 million of
preferred stock which is convertible into 833,334 shares of CDI common stock at
$30 per share. The preferred stock was issued to a private investment firm.
Subsequently in June 2004, the preferred stockholder exercised its existing
right and purchased $30 million in additional cumulative convertible preferred
stock. In accordance with the January 8, 2003 agreement, the $30 million in
additional preferred stock is convertible into 982,029 shares of Cal Dive
common stock at $30.549 per share. The preferred stock has a minimum annual
dividend rate of 4%, or LIBOR plus 150 basis points if greater, payable
quarterly in cash or common shares at Cal Dive's option. CDI paid these
dividends in 2004 and 2003 on the last day of the respective quarter in cash.
After the second anniversary of the original issuance the holder may redeem the
value of its original and additional investments in the preferred shares to be
settled in common stock at the then prevailing market price or cash at the
discretion of the Company. Under certain conditions, the holder could redeem
its investment prior to the second anniversary of the original issuance. Prior
to the conversion, common shares issuable will be assessed for inclusion in the
weighted average shares outstanding for the Company's diluted earnings per
share under the if converted method based on the Company's common share price
at the beginning of the applicable period for the original $25 million issuance
and the date of issuance (June 25, 2004) for the additional $30 million.
In August 2003, Canyon Offshore, Ltd. (a U.K. subsidiary - "COL")
(with a parent guarantee from Cal Dive) completed a capital lease with a bank
refinancing the construction costs of a newbuild 750 horsepower trenching unit
and a ROV. COL received proceeds of $12 million for the assets and agreed to
pay the bank sixty monthly installment payments of $217,174 (resulting in an
implicit interest rate of 3.29%). No gain or loss resulted from this
transaction. COL has an option to purchase the assets at the
20
end of the lease term for $1. The proceeds were used to reduce the Company's
revolving credit facility, which had initially funded the construction costs of
the assets. This transaction was accounted for as a capital lease with the
present value of the lease obligation (and corresponding asset) being reflected
on the Company's consolidated balance sheet beginning in the third quarter of
2003.
During the first nine months of 2004 and 2003, we made payments of
$2.6 million and $1.3 million respectively, on capital leases relating to
Canyon. The only other financing activity during the nine months ended
September 30, 2004 and 2003 involved the exercise of employee stock options
($9.5 million and $3.4 million, respectively).
The following table summarizes our contractual cash obligations as of
September 30, 2004 and the scheduled years in which the obligations are
contractually due (in thousands):
Less Than 1
Total (A) Year 1-3 Years 3-5 Years After 5 Years
- ------------------------------------- ---------- --------- --------- --------- -------------
MARAD debt $ 136,411 $ 3,144 $ 6,925 $ 7,870 $ 118,472
- ------------------------------------- ---------- --------- --------- --------- ----------
Revolving debt - - - - -
- ------------------------------------- ---------- --------- --------- --------- ----------
Capital leases and other 13,273 5,621 5,512 2,140 -
- ------------------------------------- ---------- --------- --------- --------- ----------
Field development costs 6,000 6,000 - - -
- ------------------------------------- ---------- --------- --------- --------- ----------
Drilling costs (B) 15,000 15,000 - - -
- ------------------------------------- ---------- --------- --------- --------- ----------
Operating leases 14,517 5,703 2,209 1,825 4,780
- ------------------------------------- ---------- --------- --------- --------- ----------
Property and equipment 6,411 6,411 - - -
- ------------------------------------- ---------- --------- --------- --------- ----------
Total cash obligations $191,612 $41,879 $14,646 $11,835 $123,252
- ------------------------------------- ---------- --------- --------- --------- ----------
(A) Excludes CDI guarantee of payment due in 2009 on term loan (estimated to be
$22.5 million) and unsecured letters of credit outstanding at September 30,
2004 totalling $3.4 million. These letters of credit primarily guarantee
various contract bidding and insurance activities.
(B) As an extension of ERT's well exploitation and PUD strategies, ERT agreed
to participate in the drilling of an exploratory well that targets reserves in
deeper sands, within the same trapping fault system, of a currently producing
well. If the drilling is successful, ERT's share of the development cost is
estimated to be an additional $15 million. CDI's Marine Contracting assets
would participate in this development. Drilling for oil and gas involves
numerous risks, including the risk that the Company will not encounter
commercially productive oil or gas reservoirs. If certain exploration efforts
are unsuccessful in establishing proved reserves and exploration activities
cease, the amounts accumulated as unproved property costs would be charged
against earnings as impairments.
In addition, in connection with our business strategy, we regularly
evaluate acquisition opportunities (including additional vessels as well as
interest in offshore natural gas and oil properties). We believe internally
generated cash flow, borrowings under existing credit facilities and use of
project financings along with other debt and equity alternatives will provide
the necessary capital to meet these obligations and achieve our planned growth.
21
ITEM 3. Quantitative and qualitative disclosure about market risk
The Company is currently exposed to market risk in three major areas:
interest rates, commodity prices and foreign currency exchange rates.
Interest Rate Risk
Because the majority of the Company's debt at September 30, 2004 was
based on floating rates, changes in interest would, assuming all other things
equal, have a minimal impact on the fair market value of the debt instruments,
but every 100 basis points move in interest rates would result in $1.5 million
of annualized interest expense or savings, as the case may be, to the Company.
Commodity Price Risk
The Company has utilized derivative financial instruments with respect
to a portion of 2004 and 2003 oil and gas production to achieve a more
predictable cash flow by reducing its exposure to price fluctuations. The
Company does not enter into derivative or other financial instruments for
trading purposes.
As of September 30, 2004, the Company has the following volumes under
derivative contracts related to its oil and gas producing activities:
INSTRUMENT AVERAGE MONTHLY WEIGHTED
PRODUCTION PERIOD TYPE VOLUMES AVERAGE PRICE
---------- --------------- -------------
Crude Oil:
October - December 2004 Swap 75 MBbl $ 31.53
January - June 2005 Swap 20 MBbl $ 35.80
January - September 2005 Collar 40 MBbl $37.00 - $47.48
Natural Gas:
October - December 2004 Collar 600,000 MMBtu $ 5.33 - $ 7.43
January - June 2005 Collar 300,000 MMBtu $ 5.67 - $ 8.15
Changes in NYMEX oil and gas strip prices would, assuming all other
things being equal, cause the fair value of these instruments to increase or
decrease inversely to the change in NYMEX prices.
Foreign Currency Exchange Rates
Because we operate in various oil and gas exploration and production
regions in the world, we conduct a portion of our business in currencies other
than the U.S. dollar (primarily with respect to Well Ops (U.K.) Limited). The
functional currency for Well Ops (U.K.) Limited is the applicable local
currency (British Pound). Although the revenues are denominated in the local
currency, the effects of foreign currency fluctuations are partly mitigated
because local expenses of such foreign operations also generally are
denominated in the same currency. The impact of exchange rate fluctuations
during the three and nine months ended September 30, 2004 and 2003,
respectively, did not have a material effect on reported amounts of revenues or
net income.
Assets and liabilities of Well Ops (U.K.) Limited are translated using
the exchange rates in effect at the balance sheet date, resulting in
translation adjustments that are reflected in accumulated other comprehensive
income (loss) in the shareholders' equity section of our balance sheet.
Approximately 14% of our assets are impacted by changes in foreign currencies
in relation to the U.S. dollar. We recorded gains of $546,000 and $1.8 million,
net of taxes, to our equity account in the three and nine months ended
September 30, 2004, and (losses) gains of $(690,000) and $657,000, net of
taxes, to our equity account in the three and nine months ended September 30,
2003.
22
Canyon Offshore, the Company's ROV subsidiary, has operations in the
United Kingdom and Southeast Asia sectors. Canyon conducts the majority of its
operations in these regions in U.S. dollars which it considers the functional
currency. When currencies other than the U.S. dollar are to be paid or
received, the resulting transaction gain or loss is recognized in the
statements of operations. These amounts for the three and nine months ended
September 30, 2004 and 2003, respectively, were not material to the Company's
results of operations or cash flows.
ITEM 4. CONTROLS AND PROCEDURES
The Company's management, with the participation of the Company's
principal executive officer (CEO) and principal financial officer (CFO),
evaluated the effectiveness of the Company's disclosure controls and procedures
(as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Securities
Exchange Act of 1934, as amended (the "Exchange Act")) as of the end of the
fiscal quarter ended September 30, 2004. Based on this evaluation, the CEO and
CFO have concluded that the Company's disclosure controls and procedures were
effective as of the end of the fiscal quarter ended September 30, 2004 to
ensure that information that is required to be disclosed by the Company in the
reports it files or submits under the Exchange Act is recorded, processed,
summarized and reported, within the time periods specified in the SEC's rules
and forms. There were no changes in the Company's internal control over
financial reporting that occurred during the fiscal quarter ended September 30,
2004 that have materially affected, or are reasonable likely to materially
affect, the Company's internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item I, Note 13 to the Condensed Consolidated Financial
Statements, which is incorporated herein by reference.
23
ITEM 6. EXHIBITS
(a) Exhibits -
Exhibit 4.1 - Credit Agreement dated as of August 16, 2004,
among Cal Dive International, Inc., as the Borrower, Bank of
America, N.A., as Administrative Agent and L/C Issuer,
Southwest Bank of Texas, N.A., as Syndication Agent, Whitney
National Bank, as Documentation Agent, and the other lenders
thereto.
Exhibit 15.1 - Independent Registered Public Accounting
Firm's Acknowledgement Letter
Exhibit 31.1 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by Owen Kratz, Chief
Executive Officer
Exhibit 31.2 - Certification Pursuant to Rule 13a-14(a) under
the Securities Exchange Act of 1934 by A. Wade Pursell, Chief
Financial Officer
Exhibit 32.1 - Section 1350 Certification by Owen Kratz,
Chief Executive Officer
Exhibit 32.2 - Section 1350 Certification by A. Wade Pursell,
Chief Financial Officer
Exhibit 99.1 - Report of Independent Registered Public
Accounting Firm
24
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned, thereunto duly authorized.
CAL DIVE INTERNATIONAL, INC.
Date: November 4, 2004 By: /s/ Owen Kratz
----------------------------------------
Owen Kratz, Chairman
and Chief Executive Officer
Date: November 4, 2004 By: /s/ A. Wade Pursell
----------------------------------------
A. Wade Pursell, Senior Vice
President and Chief Financial Officer
25
EXHIBIT INDEX
EXHIBIT NO. DESCRIPTION
- ----------- -----------
4.1 - Credit Agreement dated as of August 16, 2004, among Cal Dive
International, Inc., as the Borrower, Bank of America, N.A.,
as Administrative Agent and L/C Issuer, Southwest Bank of
Texas, N.A., as Syndication Agent, Whitney National Bank, as
Documentation Agent, and the other lenders thereto.
15.1 - Independent Registered Public Accounting Firm's
Acknowledgement Letter
31.1 - Certification Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934 by Owen Kratz, Chief Executive Officer
31.2 - Certification Pursuant to Rule 13a-14(a) under the Securities
Exchange Act of 1934 by A. Wade Pursell, Chief Financial
Officer
32.1 - Section 1350 Certification by Owen Kratz, Chief Executive
Officer
32.2 - Section 1350 Certification by A. Wade Pursell, Chief
Financial Officer
99.1 - Report of Independent Registered Public Accounting Firm