10-Q 1 h01360e10vq.txt CAL DIVE INTERNATIONAL, INC.- SEPTEMBER 30, 2002 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, 2002 ( ) 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: 0-22739 ------------------------------- 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 [ ] At November 13, 2002 there were 37,326,368 shares of common stock, no par value outstanding. CAL DIVE INTERNATIONAL, INC. INDEX
Page Part I. Financial Information Item 1. Financial Statements Consolidated Balance Sheets -- September 30, 2002 and December 31, 2001............................. 1 Consolidated Statements of Operations -- Three Months Ended September 30, 2002 and September 30, 2001............................................... 2 Nine Months Ended September 30, 2002 and September 30, 2001............................................... 3 Consolidated Statements of Cash Flows -- Nine Months Ended September 30, 2002 and September 30, 2001............................................... 4 Notes to Consolidated Financial Statements................................. 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.............................. 11 Item 3. Quantitative and Qualitative Disclosure about Market Risk........ 18 Item 4. Controls and Procedures.......................................... 19 Part II: Other Information Item 6. Exhibits and Reports on Form 8-K................................. 21 Signatures................................................................. 23
PART I. FINANCIAL STATEMENTS ITEM 1. FINANCIAL STATEMENTS CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
September 30, December 31, 2002 2001 ------------- ------------ (unaudited) ASSETS CURRENT ASSETS: Cash and cash equivalents $ 0 $ 34,837 Restricted cash 2,287 2,286 Accounts receivable -- Trade, net of revenue allowance on gross amounts billed of $4,090 and $4,262 52,969 45,527 Unbilled 15,605 10,659 Other current assets 23,516 20,055 --------- --------- Total current assets 94,377 113,364 --------- --------- PROPERTY AND EQUIPMENT 693,859 423,742 Less - Accumulated depreciation (115,877) (92,430) --------- --------- 577,982 331,312 --------- --------- OTHER ASSETS: Goodwill 86,985 14,973 Investment in Deepwater Gateway LLC 25,444 0 Other assets, net 18,090 13,473 --------- --------- $ 802,878 $ 473,122 ========= ========= LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES: Accounts payable $ 56,690 $ 42,252 Accrued liabilities 21,740 21,011 Income taxes payable 0 0 Current maturities of long-term debt 4,044 1,500 --------- --------- Total current liabilities 82,474 64,763 --------- --------- LONG-TERM DEBT 221,243 98,048 DEFERRED INCOME TAXES 63,352 54,631 DECOMMISSIONING LIABILITIES 93,387 29,331 REDEEMABLE STOCK IN SUBSIDIARY 7,528 0 COMMITMENTS AND CONTINGENCIES SHAREHOLDERS' EQUITY: Common stock, no par, 120,000 shares authorized, 50,876 and 46,239 shares issued and outstanding 192,590 99,105 Retained earnings 146,737 133,570 Other comprehensive loss (682) 0 Treasury stock, 13,602 and 13,783 shares, at cost (3,751) (6,326) --------- --------- Total shareholders' equity 334,894 226,349 --------- --------- $ 802,878 $ 473,122 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. - 1 - CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA)
Three Months Ended September 30, ------------------------ 2002 2001 -------- -------- (unaudited) NET REVENUES: Subsea and salvage $ 68,102 $ 39,356 Oil and gas production 15,913 12,214 -------- -------- 84,015 51,570 COST OF SALES: Subsea and salvage 63,322 30,025 Oil and gas production 9,120 8,338 -------- -------- Gross profit 11,573 13,207 SELLING AND ADMINISTRATIVE EXPENSES 6,372 4,969 -------- -------- INCOME FROM OPERATIONS 5,201 8,238 OTHER (INCOME) EXPENSE: Interest (income) expense, net 424 (157) Other (income), net 235 327 -------- -------- INCOME BEFORE INCOME TAXES 4,542 8,068 Provision for income taxes 1,590 2,824 -------- -------- NET INCOME $ 2,952 $ 5,244 ======== ======== EARNINGS PER COMMON SHARE: Basic $ 0.08 $ 0.16 Diluted $ 0.08 $ 0.16 ======== ======== WEIGHTED AVERAGE COMMON SHARES OUTSTANDING Basic 37,268 32,551 Diluted 37,432 33,006 ======== ========
The accompanying notes are an integral part of these consolidated financial statements. - 2 - CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS (IN THOUSANDS, EXCEPT PER SHARE DATA)
Nine Months Ended September 30, --------------------------- 2002 2001 --------- --------- (unaudited) NET REVENUES: Subsea and salvage $ 172,132 $ 103,215 Oil and gas production 38,116 55,623 --------- --------- 210,248 158,838 COST OF SALES: Subsea and salvage 149,838 78,849 Oil and gas production 20,534 27,610 --------- --------- Gross profit 39,876 52,379 SELLING AND ADMINISTRATIVE EXPENSES 18,869 15,439 --------- --------- INCOME FROM OPERATIONS 21,007 36,940 OTHER (INCOME) EXPENSE: Interest (income) expense, net 1,224 (72) Other (income), net (474) 975 --------- --------- INCOME BEFORE INCOME TAXES 20,257 36,037 Provision for income taxes 7,090 12,613 Minority interest 0 (140) --------- --------- NET INCOME $ 13,167 $ 23,564 ========= ========= EARNINGS PER COMMON SHARE: Basic $ 0.38 $ 0.73 Diluted $ 0.37 $ 0.71 ========= ========= WEIGHTED AVERAGE COMMON SHARES OUTSTANDING: Basic 34,888 32,443 Diluted 35,231 33,083 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. - 3 - CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (IN THOUSANDS)
Nine Months Ended September 30, --------------------------- 2002 2001 --------- --------- (unaudited) CASH FLOWS FROM OPERATING ACTIVITIES: Net income $ 13,167 $ 23,564 Adjustments to reconcile net income to net cash provided by operating activities -- Depreciation and amortization 28,343 27,321 Deferred income taxes 8,721 10,008 Gain on sale of property (14) (1,201) Changes in operating assets and liabilities: Accounts receivable, net 4,454 (7,137) Other current assets (2,282) 60 Accounts payable and accrued liabilities (3,126) 4,321 Income taxes payable/receivable 0 11,197 Other non-current, net (7,840) (6,036) --------- --------- Net cash provided by operating activities 41,423 62,097 --------- --------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures (140,325) (115,713) Acquisition of businesses, net of cash acquired (118,326) 0 Investment in Deepwater Gateway LLC (25,444) 0 Restricted cash 0 1,917 Proceeds from sale of properties 23 1,500 --------- --------- Net cash used in investing activities (284,072) (112,296) --------- --------- CASH FLOWS FROM FINANCING ACTIVITIES: Sale of common stock, net of transaction costs 87,223 0 MARAD borrowings 43,898 0 Repayment of MARAD borrowings (1,318) 0 Borrowings on line of credit 52,045 38,529 Borrowings on term loan 26,857 0 Repayment of capital leases (4,715) 0 Exercise of stock options 3,822 3,686 --------- --------- Net cash provided by financing activities 207,812 42,215 --------- --------- NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS (34,837) (7,984) CASH AND CASH EQUIVALENTS: Balance, beginning of period 34,837 44,838 --------- --------- Balance, end of period $ 0 $ 36,854 ========= ========= SUPPLEMENTAL DISCLOSURE OF NON-CASH CASH FLOW INFORMATION: Decommissioning liabilities assumed in offshore property acquisitions $ 66,086 $ 1,732 CDI common stock issued in purchase of Canyon Offshore, Inc. $ 4,163 $ 0 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. - 4 - CAL DIVE INTERNATIONAL, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED) Note 1 - Basis of Presentation and Significant Accounting Policies The accompanying financial statements include the accounts of Cal Dive International, Inc. (Cal Dive, CDI or the Company) and its wholly owned subsidiaries, Energy Resource Technology, Inc. (ERT), Canyon Offshore, Inc. and Well Ops (U.K.) Ltd. All significant intercompany accounts and transactions have been eliminated. These 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 financial statements prepared in accordance with generally accepted accounting principles. Management has reflected all adjustments (which were normal recurring adjustments) which it believes are necessary for a fair presentation of the consolidated balance sheets, results of operations, and cash flows, as applicable. Operating results for the period ended September 30, 2002, are not necessarily indicative of the results that may be expected for the year ending December 31, 2002. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company's 2001 Annual Report on Form 10-K. Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes to make them consistent with the current presentation format. Note 2 - Recent Accounting Pronouncements In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS No. 142, Goodwill and Intangible Assets, which supersedes APB Opinion No. 17, Intangible Assets. SFAS 142 eliminates the current requirement to amortize goodwill and indefinite-lived intangible assets, addresses the amortization of intangible assets with a defined life and addresses the impairment testing and recognition for goodwill and intangible assets. SFAS 142, which is effective for 2002, applies to goodwill and intangible assets arising from transactions completed before and after the Statement's effective date. The Company adopted this standard effective January 1, 2002, the effect of which was immaterial to CDI's financial position and results of operations. In July 2001, the FASB released SFAS No. 143, Accounting for Asset Retirement Obligations, which is required to be adopted by the Company no later than January 1, 2003. SFAS 143 addresses the financial accounting and reporting obligations and retirement costs related to the retirement of tangible long-lived assets. The Company is currently reviewing provisions of SFAS 143 to determine the standard's impact on the financial statements upon adoption. Among other things, SFAS 143 will require oil and gas companies to reflect decommissioning liabilities on the face of the balance sheet at fair market value on a discounted basis. Historically, ERT has reflected this liability on the balance sheet on an undiscounted basis. In August 2001, the FASB issued SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which was effective for the Company beginning January 1, 2002. SFAS No. 144 supersedes SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, and the accounting and reporting provisions relating to the disposal of a segment of a business of APB Opinion No. 30. The Company adopted this standard effective January 1, 2002, the effect of which was immaterial to CDI's financial position and results of operations. 5 In July 2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, which is effective for fiscal periods after December 31, 2002. SFAS No. 146 requires companies to recognize costs associated with restructurings, discontinued operations, plant closings, or other exit or disposal activities, when incurred as opposed to when the entity commits to an exit plan under Emerging Issues Task Force No. 94-3, Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity (including Certain Costs Incurred in a Restructuring). The provisions of this statement are effective for exit or disposal activities that are initiated after December 31, 2002. The Company plans to adopt the standard as of the effective date and will implement its provisions on a prospective basis. Note 3 - Comprehensive Income The components of total comprehensive income for the nine months ended September 30, 2002 are as follows (in thousands):
2002 --------- Net Income $ 13,167 Cumulative translation adjustment 549 Unrealized loss on commodity hedge (1,230) -------- Total comprehensive income $ 12,486 ========
The components of accumulated other comprehensive income as of September 30, 2002 are as follows (in thousands):
2002 -------- Cumulative translation adjustment $ 549 Unrealized loss on commodity hedge (1,230) ------- Accumulated other comprehensive loss ($ 681) =======
Note 4 - 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 our oil and gas production. Under SFAS No. 133, all derivatives are reflected in our balance sheet at their fair market value. Under SFAS No. 133 there are two types of hedging activities: hedges of cash flow exposure and hedges of fair value exposure. The Company engages primarily in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. The ineffective portion of a cash flow hedge's change in value is recognized immediately in earnings in oil and gas production revenues. 6 As required by SFAS No. 133, we formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge. The market value of hedging instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative. During the third quarter of 2002, the Company entered into various cash flow hedging swap contracts to fix cash flows relating to a portion of the Company's oil and gas production. All of these qualified for hedge accounting and none extended beyond a year and a half. The aggregate fair market value of the swaps was a liability of $2.0 million as of September 30, 2002. The Company recognized a reduction in revenues of $140,000 as related to the ineffective portion of the hedging instruments and recorded the effective portion of $1.2 million of loss, net of taxes, in other comprehensive loss within shareholders' equity. As of September 30, 2002, the Company has the following volumes under derivative contracts related to its oil and gas producing activities:
Production Period Instrument Average Monthly Weighted Average Type Volumes Price --------------------------------- ------------- --------------------- ------------------- Crude Oil: October - December 2003 Swap 47 MBbl $26.50 October - December 2002 Swap 31 MBbl $26.49 October - December 2002 Swap 9 MBbl $26.70 Natural Gas: October - December 2002 Swap 347,000 MMBtu $4.04 November - December 2002 Swap 420,000 MMBtu $3.56 October 2002 Swap 360,000 MMBtu $2.98
Subsequent to September 30, 2002, the Company entered into natural gas swaps for the period January through December 2003. The contracts cover 800,000 MMBtu per month at $4.21 for January through March 2003, and 400,000 MMBtu per month at $4.015 for April through December 2003. In March 2002 and April 2002, the Company entered into swap contracts which were not designated as hedging instruments. These instruments settled during the third quarter of 2002, the results of which were not material to the statement of operations. In June 2002, CDI signed an agreement with Coflexip to acquire the Subsea Well Operations Business Unit for 44.8 million British pounds (which at the time equaled $67.5 million) which subsequently closed in July. CDI entered into a foreign currency forward contract to lock in the British pound to U.S. dollar exchange rate. Under SFAS No. 133, we accounted for this transaction with changes in its fair value reported in earnings. Accordingly, a $1.1 million gain was recorded in other income for the quarter ended June 30, 2002 as a result of the change in 7 market value of the contract as of June 30, 2002. This contract settled in July 2002 for $1.1 million. Note 5 - Business Segment Information (in thousands)
September 30, 2002 December 31, 2001 ------------------ ----------------- (unaudited) Identifiable Assets -- Subsea and salvage $620,157 $436,085 Oil and gas production 182,721 37,037 -------- -------- Total $802,878 $473,122 -------- --------
With respect to the third quarter of 2002, Well Ops (U.K.) Ltd. (which is included in the Subsea and salvage segment) generated revenues and gross profit of $15.9 million and $4.3 million, respectively, which were derived from the North Sea. Note 6 - Long-Term Financings In August 2000, the Company closed a $138.5 million 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"). In January 2002, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. To date the Company has drawn $143.5 million on this facility, which approximates the maximum of qualified expenditures. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and maturing 25 years from such date. It 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 2% as of September 30, 2002). For a period up to ten years from delivery of the vessel in April 2002, CDI has options 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 December 31, 2001 and September 30, 2002, the Company was in compliance with these covenants. The Company has a revolving credit facility which was increased from $40 million to $70 million during 2002 and the term extended for three years. The Company drew upon this facility only 134 days during the past four years with maximum borrowing of $11.9 million. The Company had no outstanding balance under this facility as of December 31, 2001. This facility is collateralized by accounts receivable and most of the remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points depending on CDI leverage ratios (approximately 4% as of September 30, 2002) and, among other restrictions, includes three financial covenants (cash flow leverage, minimum interest coverage and fixed charge coverage). As of September 30, 2002, the Company had drawn $52.0 million under this revolving credit facility and was in compliance with these covenants with the exception of the cash flow leverage covenant, for which the Company obtained a waiver. Management believes the Company will be in compliance with these covenants at December 31, 2002 and throughout 2003. In November 2001, ERT (with a corporate guarantee by CDI) entered into a five-year lease transaction with an entity owned by a third party to fund CDI's portion of the construction costs ($67 million) of the spar for the Gunnison field. As of December 31, 2001 and June 30, 2002, the entity had drawn down $5.6 million and $22.8 million, respectively, on this facility. Accrued interest cost on the outstanding balance is capitalized to the cost of the facility during construction and is payable monthly thereafter. In August 2002, CDI acquired 100% of the equity of the entity and converted the notes into a term loan. The total commitment of the loan was reduced to $35 million and will be payable in quarterly installments of $1.75 million for three years after delivery of the spar with the remaining $15.75 million due at the end of the three years. The 8 facility bears interest at LIBOR plus 225-300 basis points depending on CDI leverage ratios (approximately 4.3% as of September 30, 2002) and includes, among other restrictions, three financial covenants (cash flow leverage, minimum interest coverage and debt to total book capitalization). The Company was in compliance with these covenants as of September 30, 2002 with the exception of the cash flow leverage covenant, for which the Company obtained a waiver. Management believes the Company will be in compliance with these covenants at December 31, 2002 and throughout 2003. The debt ($26.9 million at September 30, 2002) and related asset have been reflected on CDI's balance sheet beginning in the third quarter of 2002. The purchase price was allocated entirely to construction in progress. During the nine months ended September 30, 2002 and 2001, the Company made cash payments for interest charges, net of capitalized interest, of $1.4 million and $1.6 million, respectively. Note 7 - 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 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. During the third quarter of 2002, the Company engaged in a large construction project at the Bombax field in Trinidad. In late September, supports engineered by a subcontractor failed resulting in over a month of downtime for the Q4000. Management believes that under the terms of the contract the Company is entitled to the contractual stand-by rate for the Q4000 during its downtime. Although we have not reached agreement on these issues with the customer, we continue to maintain constructive dialogue in order to resolve this matter amicably. Although such matters have the potential of significant liability, the Company believes that 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. In 1998, one of the Company's subsidiaries entered into a subcontract with Seacore Marine Contractors Limited to provide the Sea Sorceress to a Coflexip subsidiary in Canada. Due to difficulties with respect to the sea states 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. Cal Dive was not a party to this arbitration proceeding. Only one of the grounds is potentially applicable to our subsidiary. In the event that Seacore chooses to seek contribution from our subsidiary which could entail another arbitration, it is anticipated that the Company's exposure if any, should be less than $500,000. In another lengthy commercial dispute, EEX Corporation sued Cal Dive and others alleging breach of fiduciary duty by a former EEX employee and damages resulting from certain construction and property acquisition agreements. Cal Dive has responded alleging EEX Corporation breached various provisions of the same contracts and is defending the litigation vigorously. The Company has commenced the variety of activities necessary in connection with the trial date, which has been set for February 2003. Although such litigation has the potential of significant liability, the Company believes that the outcome of all such proceedings is not likely to have a material adverse effect on its consolidated financial position, results of operations or cash flows. Note 8 - Acquisition of Businesses Canyon Offshore In January 2002, CDI purchased Canyon, a supplier of remotely operated vehicles (ROVs) and robotics to the offshore construction and telecommunications industries. CDI purchased approximately 85% of Canyon's stock for cash of $52.9 million, the assumption of $9.0 million of Canyon debt (offset by $3.1 million of cash acquired) and 181,000 shares of our 9 common stock (143,000 shares of which we purchased as treasury shares during the fourth quarter of 2001). Cal Dive committed to purchase the remaining 15% for cash 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. As they are employees, amounts paid, if any, in excess of the $13.53 per share will be recorded as compensation expense. These remaining shares have been classified as redeemable stock in subsidiary in the accompanying balance sheet and will be adjusted to their estimated redemption value at each reporting period based on Canyon's performance. The acquisition was accounted for as a purchase with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill, which totaled approximately $45.1 million. The allocation of the purchase price to the fair market value of the net assets acquired in the Canyon acquisition are based on preliminary estimates of fair market values and may be revised when additional information concerning asset and liability valuation is obtained; however, management does not anticipate the adjustments, if any, will have a material impact on the Company's results of operations or financial position. The results of Canyon are included in the accompanying statements of operations since the date of the purchase, January 2, 2002. Well Ops (UK) Ltd. In July 2002, CDI purchased the Subsea Well Operations Business Unit of CSO Ltd., a wholly owned subsidiary of Technip-Coflexip, for $68.6 million. Well Ops (UK) Ltd. performs life of field well operations and marine construction tasks primarily in the North Sea. The acquisition was accounted for as a business purchase with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill, which totaled approximately $28.6 million. The allocation of the purchase price to the fair market value of the net assets acquired in this acquisition are based on preliminary estimates of fair market values and may be revised when additional information concerning asset and liability valuation is obtained; however, management does not anticipate the adjustments, if any, will have a material impact on the Company's results of operations or financial position. The financial statements of this foreign subsidiary are measured using the local currency as the functional currency. Assets and liabilities of this subsidiary are translated at exchange rates as of the balance sheet date. Revenues and expenses are translated at average rates of exchange in effect during the period. The resulting cumulative translation adjustments of $549,000, net of taxes, have been recorded as other comprehensive income, which is a separate component of stockholder's equity. Foreign currency transaction gains and losses are included in consolidated net income. Note 9 - Offshore Property Acquisitions In August 2002 ERT, a wholly owned subsidiary of Cal Dive International, Inc. acquired the 74.8% working interest of Shell Exploration & Production Company in the South Marsh Island 130 (SMI 130) field (Shell acquisition). ERT paid $10.3 million in cash and assumed Shell's pro-rata share of the related decommissioning liability. SMI 130 consists of two blocks, located in approximately 215 feet of water, with approximately 155 wells on five 8-pile platforms. Unaudited pro forma combined operating results of CDI and the Shell acquisition for the nine months ended September 30,2002 and 2001, respectively are summarized as follows (in thousands, except per share data):
2002 2001 ---------- ---------- Net revenues............................. $ 228,729 $ 186,019 Income before taxes...................... 24,906 44,935 Net income............................... 16,189 29,348
10 EARNINGS PER SHARE: Basic............................... $0.46 $0.90 Diluted............................. $0.46 $0.89
In August 2002, ERT also completed the purchase of seven Gulf of Mexico fields from Amerada Hess including its 25% ownership position in SMI 130 for $9.3 million in cash and assumption of Amerada Hess's pro-rata share of the related decommissioning liability. As a result, ERT took over as operator with an effective 100% working interest in that field. In June 2002, ERT acquired a package of offshore properties from Williams exploration and production. ERT paid $5.5 million and assumed the pro-rata share of the abandonment obligation for the acquired interests. The blocks purchased represent an average 30% net working interest in 26 Gulf of Mexico leases. In April 2002, ERT acquired a 100% interest in East Cameron Block 374, including existing wells, equipment and improvements. The property, located in 425 feet of water, was jointly owned by Murphy Exploration & Production Company and Callon Petroleum Operating Company. Terms included a cash payment to reimburse the owners for the inception-to-date cost of the subsea wellhead and umbilical, and an overriding royalty interest in future production. Cal Dive completed the temporarily abandoned number one well and performed a subsea tie-back to a host platform. The cost of completion and tie-back was approximately $7 million, with first production occurring in August 2002. Note 10 - Equity Offering In May 2002 CDI sold 3.4 million shares of primary common stock for $23.16 per share, along with 517,000 additional shares to cover over-allotments. Net proceeds to the Company of approximately $87.2 million were used for the Coflexip Well Operations acquisition (see Note 8), ERT acquisitions and to retire debt under the Company's revolving line of credit. Note 11 - Marco Polo Project In June 2002 CDI, along with El Paso Energy Partners, formed Deepwater Gateway L.L.C. (a 50/50 venture) 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. CDI's share of the construction costs is estimated to be approximately $110 million. In August 2002 the Company, along with El Paso, completed a non-recourse project financing for this venture, terms of which include a minimum CDI equity investment of $33 million, $25.4 million of which had been paid as of September 30, 2002. This is recorded as Investment in Deepwater Gateway L.L.C. in the accompanying consolidated balance sheet. Terms of the financing also require CDI to guarantee a balloon payment at the end of the financing term (estimated to be $22.5 million). 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 or incorporates by reference certain statements that may be deemed "forward looking statements" under applicable law. 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 11 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. RESULTS OF OPERATIONS Comparison of Three Months Ended September 30, 2002 and 2001 Revenues. During the three months ended September 30, 2002, the Company's revenues increased 63% to $84.0 million compared to $51.6 million for the three months ended September 30, 2001. Of the overall $32.4 million increase, $28.7 million was generated by the Subsea and Salvage segment as revenues in the third quarter of 2002 increased to $68.1 million from $39.4 in the comparable prior year period. This increase was primarily due to our acquisitions of Canyon ($8.3 million) and Well Ops UK Limited ($15.9 million). In addition, the Q4000 and the Intrepid were in service in the third quarter of 2002, which contributed an additional $12.7 million as compared to the quarter ended September 30, 2001. These increases were offset by a 30% decline in our base fleet revenues due primarily to significant tropical disturbances in the Gulf in September 2002 and downtime on the Uncle John for main engine replacement and new thruster installations. Oil and gas production revenue for the three months ended September 30, 2002 increased $3.7 million, or 30%, to $15.9 million from $12.2 million during the comparable prior year period. The increase was due to higher average realized commodity prices and an increase in production. For the quarter ended September 30, 2002, average realized natural gas prices increased 16% to $3.28 per mcf from $2.82 during the third quarter of 2001, and realized oil prices increased to $27.42 per barrel from $25.60 per barrel during the comparable prior year quarter. Production of 4.4 Bcfe in the third quarter of 2002 increased over the comparable prior year quarter production of 3.3 Bcfe due to significant acquisitions in September 2002 (Shell and Amerada Hess -- see discussion below) and successful deployment of our PUD strategy at EC 374. Gross Profit. Gross profit of $11.6 million for the third quarter of 2002 represents a 12% decrease compared to the $13.2 million recorded in the comparable prior year period despite increases in revenue in both segments. Subsea and Salvage gross profit decreased $4.6 million, or 49%, to $4.8 million for the three months ended September 30, 2002 from $9.3 million in the comparable prior year period. Most of this gross profit was provided by the newly acquired Well Ops (UK) Ltd. subsidiary. Vessels operating in the Gulf of Mexico only broke even due to weather downtime and Uncle John repairs. Slightly offsetting this decline was a $2.9 million, or 75%, increase in oil and gas production gross profit due to the increases in the average realized commodity prices and production noted above. Gross margins fell to 14% in the third quarter of 2002 from 26% in the comparable prior year period due mainly to the loss of 17 margin points in the Subsea and Salvage segment. Gross margins in this segment fell from 24% in the third quarter of 2001 to only 7% in the current year quarter due primarily to the combination of tropical weather, vessels out of service, and low margin on a large project in Trinidad (Bombax) due in part to revenues for downtime on the Q4000 and Eclipse resulting from failure of improperly engineered third party supports. In late September, supports engineered by a subcontractor failed resulting in over a month of downtime for the Q4000. Management believes that under the terms of the contract the Company is entitled to the contractual stand-by rate for the Q4000 during its downtime. Although we have not reached agreement on these issues with the customer, we continue to maintain constructive dialogue in order to resolve this matter amicably. Oil and gas production gross margins increased to 43% in the third quarter of 2002 from 32% in the year ago quarter due to the aforementioned increases in average realized commodity prices. 12 Selling & Administrative Expenses. Selling and administrative expenses of $6.4 million in the third quarter of 2002 are $1.4 million higher than the $5.0 million incurred in the third quarter of 2001 due to the addition of Canyon ($900,000) and the Well Ops (UK) Ltd. division ($300,000). Other (Income) Expense. The Company reported net interest expense and other of $659,000 for the three months ended September 30, 2002 compared to $170,000 for the three months ended September 30, 2001. The increase between periods is due primarily to the increase in our debt, as well as reduced capitalized interest expense as the Q4000 and Intrepid were in service in the third quarter of 2002. Income Taxes. Income taxes decreased to $1.6 million for the three months ended September 30, 2002 compared to $2.8 million in the comparable prior year period due to decreased profitability. Net Income. Net income of $3.0 million for the three months ended September 30, 2002 was $2.3 million, or 44%, less than the comparable period in 2001 as a result of factors described above. Comparison of Nine Months Ended September 30, 2002 and 2001 Revenues. During the nine months ended September 30, 2002, the Company's revenues increased $51.4 million, or 32%, to $210.2 million compared to $158.8 million for the nine months ended September 30, 2001 with the Subsea and Salvage segment contributing an additional $68.9 million, which was partially offset by a decline in the oil and gas production segment of $17.5 million. Our acquisitions of Canyon and Well Ops UK Ltd added $29.3 million and $15.9 million, respectively, with the remaining increase due to the addition of three deepwater construction vessels. Oil and gas production revenue for the nine months ended September 30, 2002 decreased 31% to $38.1 million from $55.6 million during the comparable prior year period due to a 28% decline in our average realized commodity prices to $3.43 per Mcfe ($3.08 per Mcf of natural gas and $24.56 per barrel of oil) in the first nine months of 2002 from $4.78 per Mcfe ($4.90 per Mcf of natural gas and $26.37 per barrel of oil) in the comparable prior year period. Production also decreased slightly (6%) to 10.4 Bcfe in the first nine months of 2002 from 11.1 Bcfe in the first nine months of 2001. Gross Profit. Gross profit of $39.9 million for the first nine months of 2002 was $12.5 million, or 24%, lower than the $52.4 million gross profit recorded in the comparable prior year period due mainly to the revenue decrease in oil and gas production mentioned above. Oil and gas production gross profit decreased $10.4 million from $28.0 million in the first nine months of 2001 to $17.6 million for the nine months ended September 30, 2002, due to the aforementioned decreases in average realized commodity prices and production. Subsea and Salvage gross profit declined $2.1 million to $22.3 million in the first nine months of 2002 from $24.4 million in the prior year period. While the acquisitions of Canyon and Well Ops UK Ltd added additional gross profit of $4.6 million and $4.3 million, respectively, our DP vessels only generated $6.1 million of gross profit, just half of the $11.2 million in the comparable prior year period. Gross margins decreased from 33% for the nine months ended September 30, 2001 to 19% for the first nine months of 2002. Subsea and Salvage margins decreased to 13% for the nine months ended September 30, 2002 from 24% in the comparable prior year period due mainly to the softened demand in the construction and ROV support markets and low margins on the Nansen/Boomvang project, which included a high level of pass-through revenues, as well as a significant level of tropical weather in the Gulf in September 2002. Oil and gas production gross margins declined slightly from 50% in the first nine months of 2001 to 46% for the nine months ended September 30, 2002 due to the aforementioned decrease in average realized commodity prices. 13 Selling & Administrative Expenses. Selling and administrative expenses were $18.9 million in the first nine months of 2002, which is $3.5 million more than the $15.4 million incurred in the first nine months of 2001 due almost exclusively to the acquisitions of Canyon and Well Ops UK Ltd. We gained one operating margin point as overhead dropped to 9% of revenues in the nine month period ended September 30, 2000 from 10% in the comparable prior year period. Other (Income) Expense. The Company reported net interest expense and other of $750,000 for the nine months ended September 30, 2002 in contrast to $903,000 for the comparable period in the prior year. The increase in debt from our capital program resulted in an additional $1.3 million in interest expense in the first nine months of 2002 compared to the first nine months of 2001. However, the $1.1 million gain on our foreign currency hedge relating to the Well Ops acquisition included in other income for the nine months ended September 30, 2002 more than offset this increase in interest expense. Income Taxes. Income taxes decreased to $7.1 million for the nine months ended September 30, 2002, compared to $12.6 million in the comparable prior year period due to decreased profitability. Net Income. Net income of $13.2 million for the nine months ended September 30, 2002 was $10.4 million, or 44%, less than the comparable period in 2001 as a result of factors described above. LIQUIDITY AND CAPITAL RESOURCES During the three years following our initial public offering in 1997, internally generated cash flow funded approximately $164 million of capital expenditures and enabled us to remain essentially debt-free. During the third quarter of 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, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. Through September 30, 2002, we have drawn $143.4 million on this facility. Significant internally generated cash flow during 2001, coupled with the collection of a $10 million tax refund, enabled us to acquire the Mystic Viking, the Eclipse and Professional Divers of New Orleans, while maintaining cash balances of $37.1 million as of December 31, 2001. In January 2002, we acquired Canyon Offshore, Inc., in July 2002 we acquired the Subsea Well Operations Business Unit from Technip-Coflexip and in August 2002, ERT made a significant property acquisition. (See further discussion below.) As of October 31, 2002, we had $142.1 million of debt outstanding under the MARAD facility and $60.5 million of debt outstanding under our $70 million revolving credit facility. In addition, as of October 31, 2002, $28.2 million had been drawn on the project financing facility covering our share of costs for the construction of the spar production facility at Gunnison. 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 our oil and gas production. Under SFAS No. 133, all derivatives are reflected in our balance sheet at their fair market value. Under SFAS No. 133 there are two types of hedging activities: hedges of cash flow exposure and hedges of fair value exposure. The Company engages primarily in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income until the hedged transactions occur and are recognized in earnings. The ineffective 14 portion of a cash flow hedge's change in value is recognized immediately in earnings in oil and gas production revenues. As required by SFAS No. 133, we formally document all relationships between hedging instruments and hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting prospectively if we determine that a derivative is no longer highly effective as a hedge. The market value of hedging instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative. During the third quarter of 2002, the Company entered into various cash flow hedging swap contracts to fix cash flows relating to a portion of the Company's oil and gas production. All of these qualified for hedge accounting and none extended beyond a year and a half. The aggregate fair market value of the swaps was a liability of $2.0 million as of September 30, 2002. The Company recognized a reduction in revenues of $140,000 as related to the ineffective portion of the hedging instruments and recorded the effective portion of $1.2 million of loss, net of taxes, in other comprehensive loss within shareholders' equity. In March 2002 and April 2002, the Company entered into swap contracts which were not designated as hedging instruments. These instruments settled during the third quarter of 2002, the results of which were not material to the statement of operations. In June 2002, CDI signed the agreement with Coflexip to acquire the Subsea Well Operations Business Unit for 44.8 million British pounds (which at the time equaled $67.5 million) which subsequently closed in July. CDI entered into a foreign currency forward contract to lock in the British pound to U.S. dollar exchange rate. Under SFAS No. 133, we accounted for this transaction with changes in its fair value reported in earnings. Accordingly, a $1.1 million gain was recorded in other income for the quarter ended June 30, 2002 as a result of the change in market value of the contract as of June 30, 2002. This contract settled in July 2002 for $1.1 million. Operating Activities. Net cash provided by operating activities was $41.4 million during the nine months ended September 30, 2002, as compared to $62.1 million during the first nine months of 2001. This decrease was due mainly to decreased profitability and to last year's collection of a $10 million tax refund from the Internal Revenue Service relating to the deduction of Q4000 construction costs as research and development expenditures for federal tax purposes. Investing Activities. Capital expenditures have consisted principally of strategic asset acquisitions related to the purchase of DP vessels; construction of the Q4000 and conversion of the Intrepid; acquisition of Aquatica, Professional Divers, Canyon and Well Ops (UK) Ltd.; improvements to existing vessels and the acquisition of offshore natural gas and oil properties. As a result of our anticipation of an acceleration in Deepwater demand over the next several years, we incurred $284.1 million of capital expenditures (including the acquisitions of Canyon and Well Ops (UK) Ltd. and investment in Deepwater Gateway L.L.C.) during the first nine months of 2002, and $151.3 million during 2001. 15 We incurred $140.3 million of capital expenditures during the first nine months of 2002 compared to $115.7 million during the comparable prior year period. Included in the capital expenditures during the first nine months of 2002 was $25.2 million for the construction of the Q4000 and $31.8 million relating to the Intrepid DP conversion and Eclipse upgrade. Included in the $115.7 million of capital expenditures in the first nine months of 2001 is $40.0 million for the construction of the Q4000 and $23.0 million relating to the Intrepid DP conversion project. In addition, in May 2001, Cal Dive acquired a DP marine construction vessel, the Mystic Viking. The remaining capital expenditures relate primarily to well exploitation work of ERT. On August 30, 2002, ERT acquired the 74.8% working interest of Shell Exploration & Production Company in the South March Island 130 (SMI 130) field. ERT paid $10.3 million in cash and assumed Shell's pro-rata share of the related decommissioning liability. ERT also completed the purchase of interests in seven Gulf of Mexico fields from Amerada Hess including its 25% ownership position in SMI 130 for $9.3 million in cash and assumption of Amerada Hess' pro-rata share of the related decommissioning liability. As a result, ERT will take over as operator with an effective 100% working interest in that field. In July 2002, CDI purchased the Subsea Well Operations Business Unit of CSO Ltd., a wholly owned subsidiary of Technip-Coflexip, for $68.6 million using existing cash balances and our revolving credit facility. The acquisition was accounted for as a purchase with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess being recorded as goodwill, which totaled approximately $28.6 million. The allocation of the purchase price to the fair market value of the net assets acquired in this acquisition are based on preliminary estimates of fair market values and may be revised when additional information concerning asset and liability valuation is obtained; however, management does not anticipate the adjustments, if any, will have a material impact on the Company's results of operations or financial position. In January 2002, we acquired Canyon Offshore, a supplier of ROVs and robotics to the offshore construction and telecommunications industries, in exchange for cash of $52.9 million, the assumption of $9.0 million of Canyon debt (offset by $3.1 million of cash acquired) and 181,000 shares of our common stock, 143,000 shares of which we purchased as treasury shares during the fourth quarter of 2001 for $2.6 million. We will purchase the remaining 15% 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. As they are employees, amounts paid, if any, in excess of the $13.53 per share will be recorded as compensation expense. The acquisition was accounted for as a purchase with the acquisition price being allocated to the assets acquired and liabilities assumed based upon their estimated fair values, with the excess of $45.1 million being recorded as goodwill. The allocation of the purchase price to the fair market value of the net assets acquired in this acquisition are based on preliminary estimates of fair market values and may be revised when additional information concerning asset and liability valuation is obtained; however, management does not anticipate the adjustments, if any, will have a material impact on the Company's results of operations or financial position. In April 2002, ERT acquired a 100% interest in East Cameron Block 374, including existing wells, equipment and improvements. The property, located in 425 feet of water, was jointly owned by Murphy Exploration & Production Company and Callon Petroleum Operating Company. Terms include a cash payment to reimburse the owners for the inception-to-date cost of the subsea wellhead and umbilical, and an overriding royalty interest in future production. Cal Dive completed the temporarily abandoned number one well and performed a subsea tie-back to host platform. The cost of completion and tie-back was approximately $7 million with first production occurring in August 2002. In June 2002, ERT acquired a package of offshore properties from Williams Exploration and Production. ERT paid $5.5 million and assumed the pro-rata share of the abandonment 16 obligation for the acquired interests. The blocks purchased represent an average 30% net working interest in 26 Gulf of Mexico leases. In June 2002 CDI, along with El Paso Energy Partners, formed Deepwater Gateway L.L.C. (a 50/50 venture) 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 is estimated to be approximately $110 million. In August 2002, the Company along with El Paso, completed a non-recourse project financing for this venture, terms of which would include a minimum equity investment for CDI of $33 million, $25.4 million of which had been paid as of September 30, 2002 and is recorded as Investment in Deepwater Gateway L.L.C. in the accompanying consolidated balance sheet. Terms of the financing also require CDI to guarantee a balloon payment at the end of the financing term (estimated to be $22.5 million). In April 2000, ERT acquired a 20% working interest in Gunnison, a deepwater Gulf of Mexico project of Kerr-McGee Oil & Gas Corporation. Consistent with our philosophy of avoiding exploratory risk, financing for the exploratory costs, initially estimated at $15 million, was provided by an investment partnership, the investors of which are Cal Dive senior management, in exchange for a 25% revenue override of our 20% working interest. We provide no guarantees to the investment partnership. At that time, the Board of Directors established three criteria to determine a commercial discovery and the commitment of Cal Dive funds: 75 million barrels (gross) of reserves, total development costs of $500 million consistent with such a reserve level, and a Cal Dive estimated shareholder return of no less than 12%. Kerr-McGee, the operator, drilled several exploration wells and sidetracks in 3,200 feet of water at Garden Banks 667, 668 and 669 (the Gunnison project) and encountered significant potential reserves resulting in the three criteria being achieved during 2001. The exploratory phase was expanded to ensure field delineation resulting in the investment partnership, which assumed the exploratory risk, funding $20 million of exploratory drilling costs, considerably above the initial $15 million estimate. With a commercial discovery being approved for development, Cal Dive is funding its 20% share of ongoing development and production costs (estimated in a range of $100 million to $110 million), $58.2 million of which had been incurred by September 30, 2002, with $26.9 of that for construction of the spar production facility. Financing Activities. We have financed seasonal operating requirements and capital expenditures with internally generated funds, borrowings under credit facilities, the sale of common stock and project financings. In August 2000, we closed a $138.5 million long-term financing for construction of the Q4000. In January 2002, the Maritime Administration agreed to expand the facility to $160 million to include the modifications to the vessel which had been approved during 2001. During 2001, we borrowed $59.5 million on this facility and during the first nine months of 2002 drew another $43.9 million bringing the total to $143.5 million at September 30, 2002. The MARAD debt will be payable in equal semi-annual installments beginning in August 2002 and maturing 25 years from such date. It 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 2% as of September 30, 2002). For a period up to four years from delivery of the vessel in April the Company has options 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 and debt-to-equity requirements. As of December 31, 2001 and September 30, 2002, we were in compliance with these covenants. The Company has a revolving credit facility which was increased from $40 million to $70 million during 2002 and the term extended for three years. The Company drew upon this facility only 134 days during the past four years with maximum borrowing of $11.9 million. The Company had no outstanding balance under this facility as of December 31, 2001. This facility is collateralized by accounts receivable and most of the remaining vessel fleet, bears interest at LIBOR plus 125-250 basis points depending on CDI leverage ratios and, among other 17 restrictions, includes three financial covenants (cash flow leverage, minimum interest coverage and fixed charge coverage). As of September 30, 2002, the Company had drawn $52.0 million under this revolving credit facility and was in compliance with, or obtained waivers for, these covenants with the exception of the cash flow leverage covenant, for which the Company obtained a waiver. Management believes the Company will be in compliance with these covenants at December 31, 2002 and throughout 2003. In November 2001, ERT (with a corporate guarantee by CDI) entered into a five-year lease transaction with an entity owned by a third party to fund CDI's portion of the construction costs ($67 million) of the spar for the Gunnison field. As of December 31, 2001 and June 30, 2002, the entity had drawn down $5.6 million and $22.8 million, respectively, on this facility. Accrued interest cost on the outstanding balance is capitalized to the cost of the facility during construction and is payable monthly thereafter. In August 2002, CDI acquired 100% of the equity of the entity and converted the notes into a term loan. The total commitment of the loan was reduced to $35 million and will be payable in quarterly installments of $1.75 million for three years after delivery of the spar with the remaining $15.75 million due at the end of the three years. The facility bears interest at LIBOR plus 225-300 basis points depending on CDI leverage ratios and includes, among other restrictions, three financial covenants (cash flow leverage, minimum interest coverage and debt to total book capitalization). The Company was in compliance with these covenants as of September 30, 2002 with the exception of the cash flow leverage covenant, for which the Company obtained a waiver. Management believes the Company will be in compliance with these covenants at December 31, 2002 and throughout 2003. The debt ($26.9 million at September 30, 2002) and related asset have been reflected on CDI's balance sheet beginning in the third quarter of 2002. The purchase price was allocated entirely to construction in progress. In May 2002 CDI sold 3.4 million shares of primary common stock for $23.16 per share, along with 517,000 additional shares to cover over-allotments. Net proceeds to the Company of approximately $87.2 million were used for the Coflexip Well Operation acquisition, ERT acquisitions and to retire debt under the Company's revolving credit facility. During the first nine months of 2002, we made payments of $4.7 million on capital leases assumed in the Canyon acquisition. The only other financing activity during the nine months ended September 30, 2002 and 2001 involved the exercise of employee stock options. The following table summarizes our contractual cash obligations as of September 30, 2002 and the scheduled years in which the obligation are contractually due:
Total Less Than 1 2-3 Years 4-5 Years Thereafter (in thousands) Year ---------- ------------ ----------- ---------- --------- MARAD debt $142,128 $ 2,500 $ 6,000 $ 7,000 $126,628 Gunnison Term Debt 26,857 -- 6,835 $ 20,022 -- Revolving debt 52,045 -- 52,045 -- -- Gunnison development 52,000 41,000 11,000 -- Investments in Deepwater Gateway L.L.C (A) 7,600 7,600 -- -- -- Operating leases 21,200 9,408 10,888 462 442 Redeemable stock in subsidiary 7,528 2,509 5,019 -- -- Canyon capital leases and other 4,257 1,579 2,174 504 -- Total cash obligations $313,615 $ 64,596 $ 93,961 $ 27,988 $127,070
(A) Excludes CDI guarantee of balloon payment on non-recourse project financing (estimated to be $22.5 million). In addition, in connection with our business strategy, we evaluate acquisition opportunities (including additional vessels as well as interest in offshore natural gas and oil 18 properties). We believe that 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. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK The Company is currently exposed to market risk in two major areas: commodity prices and foreign currency. Because all of the Company's debt at September 30, 2002 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. Commodity Price Risk The Company has utilized derivative financial instruments with respect to a portion of 2002 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, 2002, the Company has the following volumes under derivative contracts related to its oil and gas producing activities:
Production Period Instrument Average Monthly Weighted Average Type Volumes Price ---------------------------------------- ------------- --------------------- ------------------- Crude Oil: October - December 2003 Swap 47 MBbl $26.50 October - December 2002 Swap 31 MBbl $26.49 October - December 2002 Swap 9 MBbl $26.70 Natural Gas: October - December 2002 Swap 347,000 MMBtu $4.04 November - December 2002 Swap 420,000 MMBtu $3.56 October 2002 Swap 360,000 MMBtu $2.98
Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, cause the fair market value of these instruments to increase or decrease. Subsequent to September 30, 2002, the Company entered into natural gas swaps for the period January through December 2003. The contracts cover 800,000 MMBtu per month at $4.21 for January through March 2003, and 400,000 MMBtu per month at $4.015 for April through December 2003. 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 (UK) Ltd.). The functional currency for Well Ops (UK) Ltd. is the applicable local currency. 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 nine months ended September 30, 2002 did not have a material effect on reported amounts of revenues or net income. Assets and liabilities of Well Ops (UK) Ltd. are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in 19 accumulated other comprehensive loss in the stockholders' equity section of our balance sheet. Approximately 25% of our net assets are impacted by changes in foreign currencies in relation to the U.S. dollar. We recorded a $549,000 adjustment, net of taxes, to our equity account for the nine months ended September 30, 2002 to reflect the net impact of the decline of the British Pound against the U.S. dollar. ITEM 4. CONTROLS AND PROCEDURES As of September 30, 2002, an evaluation was performed under the supervision and with the participation of the Company's management, including the CEO and CFO, of the effectiveness of the design and operation of the Company's disclosure controls and procedures. Based on that evaluation, the Company's management, including the CEO and CFO, concluded that the Company's disclosure controls and procedures were effective as of September 30, 2002. There have been no significant changes in the Company's internal controls or in other factors that could significantly affect internal controls subsequent to September 30, 2002. 20 PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS 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 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. During the third quarter of 2002, the Company engaged in a large construction project at the Bombax field in Trinidad. In late September, supports engineered by a subcontractor failed resulting in over a month of downtime for the Q4000. Management believes that under the terms of the contract the Company is entitled to the contractual stand-by rate for the Q4000 during its downtime. Although we have not reached agreement on these issues with the customer, we continue to maintain constructive dialogue in order to resolve this matter amicably. Although such matters have the potential of significant liability, the Company believes that 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. In 1998, one of the Company's subsidiaries entered into a subcontract with Seacore Marine Contractors Limited to provide the Sea Sorceress to a Coflexip subsidiary in Canada. Due to difficulties with respect to the sea states 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. Cal Dive was not a party to this arbitration proceeding. Only one of the grounds is potentially applicable to our subsidiary. In the event that Seacore chooses to seek contribution from our subsidiary which could entail another arbitration, it is anticipated that the Company's exposure if any, should be less than $500,000. In another lengthy commercial dispute, EEX Corporation sued Cal Dive and others alleging breach of fiduciary duty by a former EEX employee and damages resulting from certain construction and property acquisition agreements. Cal Dive has responded alleging EEX Corporation breached various provisions of the same contracts and is defending the litigation vigorously. The Company has commenced the variety of activities necessary in connection with the trial date, which has been set for February 2003. Although such litigation has the potential of significant liability, the Company believes that the outcome of all such proceedings is not likely to have a material adverse effect on its consolidated financial position, results of operations or cash flows. ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K (a) Exhibits -- Exhibit 99.1 -- Certification of Periodic Report by Chief Executive Officer Exhibit 99.2 -- Certification of Periodic Report by Chief Financial Officer (b) Reports on Form 8-K -- Current Report on Form 8-K filed August 2, 2002 to report the Company's 2002 second quarter financial results and its forecasted results for the quarter ending September 30, 2002. Current Report on Form 8-K filed September 16, 2002 to disclose business acquisitions. 21 Current report on Form 8-K/A filed November 13, 2002 amending September 16, 2002 Form 8-K to include audited financial statements of significant business acquisitions. 22 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 14, 2002 By: --------------------------------------- Owen Kratz, Chairman and Chief Executive Officer Date: November 14, 2002 By: --------------------------------------- A. Wade Pursell, Senior Vice President and Chief Financial Officer 23 CERTIFICATIONS I, Owen Kratz, the Principal Executive Officer of Cal Dive International, Inc., certify that: 1. I have reviewed this quarterly report on Form 10-Q of Cal Dive International, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 24 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 ------------------------------------ Owen Kratz Chairman and Chief Executive Officer ----------------------- I, A. Wade Pursell, the Principal Financial Officer of Cal Dive International, Inc., certify that: 1. I have reviewed this quarterly report on Form 10-Q of Cal Dive International, Inc.; 2. Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this quarterly report; 3. Based on my knowledge, the financial statements, and other financial information included in this quarterly report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this quarterly report; 4. The registrant's other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have: a) designed such disclosure controls and procedures to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared; b) evaluated the effectiveness of the registrant's disclosure controls and procedures as of a date within 90 days prior to the filing date of this quarterly report (the "Evaluation Date"); and 25 c) presented in this quarterly report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date; 5. The registrant's other certifying officers and I have disclosed, based on our most recent evaluation, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function): a) all significant deficiencies in the design or operation of internal controls which could adversely affect the registrant's ability to record, process, summarize and report financial data and have identified for the registrant's auditors any material weaknesses in internal controls; and b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal controls; and 6. The registrant's other certifying officers and I have indicated in this quarterly report whether or not there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses. Date: November 14, 2002 ------------------------------- A. Wade Pursell Senior Vice President and Chief Financial Officer 26 EXHIBIT INDEX Exhibit 99.1 -- Certification of Periodic Report by Chief Executive Officer Exhibit 99.2 -- Certification of Periodic Report by Chief Financial Officer 24