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