Helix Energy Solutions - 10-Q quarterly report FY

 

(Exact Name of Registrant as Specified in its Charter)

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 þ No o

Indicate by check whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes þ No o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No o

     At November 8, 2005 there were 38,924,202 shares of common stock, no par value, outstanding.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

The accompanying notes are an integral part of these condensed consolidated financial statements.

     The accompanying condensed consolidated financial statements include the accounts of Cal Dive International, Inc. and its majority-owned subsidiaries (collectively, “Cal Dive”, “CDI” or the “Company”). The Company accounts for its 50% interest in Deepwater Gateway, L.L.C., its 20% interest in Independence Hub, LLC and its 40% interest in Offshore Technology Solutions Limited (“OTSL”) using the equity method of accounting as the Company does not have voting or operational control of these entities. 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 unless otherwise identified) 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, 2005 are not necessarily indicative of the results that may be expected for the year ending December 31, 2005. The Company’s balance sheet as of December 31, 2004 included herein has been derived from the audited balance sheet as of December 31, 2004 included in the Company’s 2004 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 2004 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.

     In December 2004, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 123 (revised 2004) Share-Based Payment (“SFAS No. 123R”), which replaces SFAS No. 123, Accounting for Stock-Based Compensation, (“SFAS No. 123”) and supersedes APB Opinion No. 25, Accounting for Stock Issued to Employees. SFAS No. 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim period in fiscal 2006, with early adoption encouraged. The pro forma disclosures previously permitted under SFAS No. 123 no longer will be an alternative to financial statement recognition. The Company is required to adopt SFAS No. 123R in the first quarter of fiscal 2006. Under SFAS No. 123R, the Company must determine the appropriate fair value model to be used for valuing share-based payments, the amortization method for compensation cost and the transition method to be used at date of adoption. The transition methods include prospective and retroactive adoption options. Under the retroactive option, prior periods may be restated either as of the beginning of the year of adoption or for all periods presented. The prospective method requires that compensation expense be recorded for all unvested stock options and restricted stock beginning with the first quarter of adoption of SFAS No. 123R as the requisite service is rendered on or after the required effective date, while the retroactive methods would record compensation expense for all unvested stock options and restricted stock beginning with the first period restated. The Company intends to adopt SFAS No. 123R using the prospective method beginning January 1, 2006 and does not expect the adoption of SFAS No. 123R to have a material impact on the Company’s consolidated results of operations and earnings per share.

     The Company defines cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. As of September 30, 2005, the Company had $24.4 million of restricted cash included in other assets, net, all of which related to Energy Resource Technology, Inc. (“ERT”), a wholly owned subsidiary of the Company, escrow funds for decommissioning liabilities associated with the South Marsh Island 130 (“SMI 130”) field acquisitions in 2002. Under the purchase agreement for those acquisitions, 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. ERT may use the restricted cash for decommissioning the related fields. Additionally, $7.5 million was included in restricted cash in other assets, net, at December 31, 2004 related to the Company’s investment in Deepwater Gateway, L.L.C. The Company was required to escrow up to $22.5 million related to its guarantee under the term loan agreement for Deepwater Gateway, L.L.C. The term loan of $144 million related to Deepwater Gateway, L.L.C. was repaid in full in March 2005. As a result in March 2005, the escrow agreement was canceled and the $7.5 million was released from restricted cash.

     During the three and nine months ended September 30, 2005, the Company made cash payments for interest charges, net of capitalized interest, of $2.5 million and $5.8 million respectively. 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, 2005, the Company paid $780,000 and $2.0 million in income taxes. The Company paid no cash income taxes in the three and nine months ended September 30, 2004.

     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 unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are expensed in the period the drilling is determined to be unsuccessful. In the first nine months of 2005, impairments and unsuccessful capitalized well work totaling $4.4 million were expensed as a result of an analysis on certain properties. Further, the Company expensed $5.3 million of purchased seismic data related to its offshore property acquisitions in the first nine months of 2005.

     As an extension of ERT’s well exploitation and PUD strategies, ERT agreed to participate in the drilling of an exploratory well (Tulane prospect) to be drilled in 2006 that targets reserves in deeper sands, within the same trapping fault system, of a currently producing well with estimated drilling costs of approximately $18 million, of which $5.0 million had been incurred through September 30, 2005. If the drilling is successful, ERT’s share of the development cost is estimated to be an additional $21 million. CDI’s Marine Contracting assets would participate in this development.

     In March 2005, ERT acquired a 30% working interest in a proven undeveloped field in Atwater Block 63 (Telemark) of the deepwater Gulf of Mexico for cash consideration and assumption of certain decommissioning liabilities.

     In April 2005, ERT entered into a participation agreement to acquire a 50% working interest in the Devil’s Island discovery (Garden Banks Block 344 E/2) in 2,300 feet water depth. This deepwater development is operated by Amerada Hess and will be drilled in 2006. The field will be developed via a subsea tieback to Baldpate Field (Garden Banks Block 260). Under the participation agreement, ERT will pay 100% of the drilling costs and a disproportionate share of the development costs to earn a 50% working interest in the field.

     Also in April 2005, ERT acquired a 37.5% working interest in the Bass Lite discovery (Atwater Blocks 182, 380, 381, 425 and 426) in 7,500 feet water depth along with varying interests in 50 other blocks of exploration acreage in the eastern portion of the Atwater lease protraction area from BHP Billiton. The Bass Lite discovery contains proved undeveloped gas reserves in a sand discovered in 2001 by the Atwater 426 #1 well. In October 2005, ERT exchanged 15% of its working interest in Bass Lite for a 40% working interest in the Tiger Prospect located in Green Canyon Block 195. ERT paid $1.0 million in the exchange with no corresponding gain or loss recorded on the transaction.

     As of September 30, 2005, the Company had spent $28.7 million and had committed to an additional estimated $39 million for development and drilling costs related to the above property transactions.

     In June 2005, ERT acquired a mature property package on the Gulf of Mexico shelf from Murphy Exploration & Production Company — USA (“Murphy”), a wholly owned subsidiary of Murphy Oil Corporation. The acquisition cost to ERT included both cash ($163.5 million) and the assumption of the abandonment liability from Murphy of approximately $32.0 million. The acquisition represents essentially all of Murphy’s Gulf of Mexico Shelf properties consisting of eight operated and eleven non-operated fields. ERT estimates proved reserves of the acquisition to be approximately 75 BCF equivalent. Unaudited pro forma combined operating results of the Company and the Murphy acquisition for the three and nine months ended September 30, 2005 and 2004, respectively, were as follows (in thousands, except per share data).

     In July 2005, the Company completed the sale of a certain Marine Contracting DP ROV Support vessel, the Merlin, for $2.29 million in cash. The Company recorded an additional impairment of $790,000 on the vessel in June 2005.

     In March 2005, the Company completed the sale of certain Marine Contracting property and equipment for $4.5 million. Proceeds from the sale consisted of $100,000 cash and a $4.4 million promissory note bearing interest at 6% per annum due in semi-annual installments beginning September 30, 2005. In addition to the asset sale, the Company entered into a five year services agreement with the purchaser whereby the Company has committed to provide the purchaser with a specified amount of services for its Gulf of Mexico fleet on an annual basis ($8 million per year). The measurement period related to the services agreement begins with the twelve months ending June 30, 2006 and continues every six months until the contract ends on March 31, 2010. Further, the promissory note stipulates that should the Company not meet its annual services commitment the purchaser can defer its semi-annual principal and interest payment for six months. The Company determined that the estimated gain on the sale of approximately $2.5 million should be deferred and recognized as the principal and interest payments are received from the purchaser over the course of the promissory note. The first installment on the $4.4 million promissory note was received in October 2005.

     The components of total comprehensive income for the three and nine months ended September 30, 2005 and 2004 were as follows (in thousands):

     The components of accumulated other comprehensive income are as follows (in thousands):

     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 2004 and the first nine months of 2005, 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. The aggregate fair value of the hedge instruments was a net liability of $32.0 million as of September 30, 2005. The Company recorded approximately $18.4 million of unrealized losses, net of taxes of $9.9 million, during the first nine months of 2005 in other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective. During the three and nine months ended September 30, 2005, the Company reclassified approximately $3.2 million and $6.1 million, respectively, of losses from other comprehensive income to Oil and Gas Production revenues upon the sale of the related oil and gas production.

     Hedge ineffectiveness related to cash flow hedges was a loss of $1.8 million, net of taxes of $951,000, in the third quarter of 2005 as reported in current period earnings as a reduction of oil and gas production revenues. Hedge ineffectiveness resulted from ERT’s projected inability to deliver contractual oil and gas production in fourth quarter 2005 due primarily to the effects of Hurricanes Katrina and Rita.

     As of September 30, 2005, the Company had the following volumes under derivative contracts related to its oil and gas producing activities:

     The functional currency for the Company’s foreign subsidiary Cal Dive International 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 were unrealized losses of $1.3 million and $8.0 million in the three and nine months ended September 30, 2005, respectively, is included in accumulated other comprehensive income, a component of shareholders’ equity. Beginning in 2004, deferred taxes have not been provided on foreign currency translation adjustments since the Company considers its undistributed earnings (when applicable) of its non-U.S. subsidiaries to be permanently reinvested. These amounts for the three and nine months ended September 30, 2005, respectively, 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 three and nine months ended September 30, 2005, respectively, were not material to the Company’s results of operations or cash flows.

     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):

     There were no antidilutive stock options in the three and nine months ended September 30, 2005 and 2004, respectively. 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. Net income for the diluted earnings per share calculation for the three and nine months ended September 30, 2005 was adjusted to add back the preferred stock dividends and accretion on the 1.8 million shares. 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.

     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):

     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 in 2004 and expected volatility to be approximately 56 percent in 2004. There have been no stock option grants in 2005. 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 was $17.59. The estimated fair value of the options is amortized to pro forma expense over the vesting period.

     On January 3, 2005, the Company granted certain key executives and selected management employees 94,000 restricted shares under the Incentive Plan. The shares vest 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of grant) of the restricted shares was $39.12 per share, or $3.7 million, at the date of the grant and will be recorded as unearned compensation, a component of shareholders’ equity. On September 1, 2005, a certain key executive of the Company was granted 60,069 restricted shares under the Incentive Plan. The shares vest in two tranches. Tranche 1 (10,069 restricted shares) vests with respect to two-thirds of such shares after two years and fully vests after three years. Tranche 2 (50,000 restricted shares) vests 20% per year for a five year period. The market value (based on the quoted price of the common stock on the date of grant) of the restricted shares was $62.07 per share, or $3.7 million, at the date of grant and will be recorded as unearned compensation, a component of shareholders’ equity. These amounts will be charged to expense over the respective vesting periods. Amortization of unearned compensation totaled $335,000 and $733,000 in the three and nine months ended September 30, 2005, respectively.

     In June 2002, CDI, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, L.L.C. 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 was approximately $120 million, all of which had been incurred as of December 31, 2004. The Company’s investment in Deepwater Gateway, L.L.C. totaled $119.2 million as of September 30, 2005. In August 2002, the Company, along with Enterprise, completed a limited recourse project financing for this venture, In accordance with terms of the term loan, Deepwater Gateway, L.L.C. had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. Deepwater Gateway, L.L.C. repaid in full its term loan in March 2005. The Company and Enterprise made equal cash contributions ($72 million each) to Deepwater Gateway, L.L.C. to fund the repayment. Further, the Company received cash distributions from Deepwater Gateway, L.L.C. totaling $16.1 million in the first nine months of 2005.

     In December 2004, CDI acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence will own the “Independence Hub” platform to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet. CDI’s investment in Independence was $39.7 million at September 30, 2005, and its total investment is expected to be approximately $77 million. Further, CDI is party to a guaranty agreement with Enterprise to the extent of CDI’s ownership in Independence. The agreement states, among other things, that CDI and Enterprise guarantee performance under the Independence Hub Agreement between Independence and the producers group of exploration and production companies up to $397.5 million, plus applicable attorneys’ fees and related expenses. CDI has estimated the fair value of its share of the guarantee obligation to be immaterial at September 30, 2005 based upon the extremely remote possibility of payments being made under the performance guarantee.

     In July 2005, the Company acquired a 40% minority ownership interest in OTSL in exchange for the Company’s DP DSV, Witch Queen. The Company’s investment in OTSL totaled $9.4 million at September 30, 2005. OTSL provides marine construction services to the oil and gas industry in and around Trinidad and Tobago, as well as the U.S. Gulf of Mexico. Effective December 31, 2003, the Company adopted and applied the provisions of FASB Interpretation (“FIN”) No. 46, Consolidation of Variable Interest Entities, as revised December 31, 2003, for all variable interest entities. FIN 46 requires the consolidation of variable interest entities in which an enterprise absorbs a majority of the entity’s expected losses, receives a majority of the entity’s expected residual returns, or both, as a result of ownership, contractual or other financial interests in the entity. OTSL qualified as a variable interest entity

     (“VIE”) under FIN 46 through September 30, 2005. The Company has determined that it was not the primary beneficiary of OTSL and, thus, has not consolidated the financial results of OTSL. The Company accounts for its investment in OTSL under the equity method of accounting. In addition, the Company had certain rights and guarantee obligations of up to $3.5 million under the OTSL shareholder agreement. The estimated fair value of the guarantee obligations was deemed immaterial by CDI at September 30, 2005 due to the remote possibility of payments being made by CDI under the guarantee. In October 2005, the shareholders of OTSL agreed to remove the CDI guarantee obligation from the shareholder agreement effective September 30, 2005.

     Further, in conjunction with its investment in OTSL, the Company entered into a one year, unsecured $1.5 million working capital loan, bearing interest at 6% per annum, with OTSL. Interest is due quarterly beginning September 30, 2005 with a lump sum principal payment due to the Company on June 30, 2006.

     In the third quarter of 2005, OTSL contracted the Witch Queen to the Company for certain services to be performed in the U.S. Gulf of Mexico. The Company incurred costs associated with the contract with OTSL totaling approximately $2.4 million during the third quarter of 2005.

     Included in identifiable assets for Marine Contracting at September 30, 2005 was $150.4 million of unrestricted cash.

     During the three and nine months ended September 30, 2005, the Company derived $14.2 million and $62.9 million, respectively, of its revenues from the U.K. sector utilizing $136.8 million of its total assets in this region. 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. The majority of the remaining revenues were generated in the U.S. Gulf of Mexico.

     On March 30, 2005, the Company issued $300 million of 3.25% Convertible Senior Notes due 2025 (“Convertible Senior Notes”) at 100% of the principal amount to certain qualified institutional buyers. The Company also incurred financing costs of approximately $8.1 million (included in other assets, net) which will be amortized over the life of the debt agreement. The Convertible Senior Notes are convertible into cash and, if applicable, shares of the Company’s common stock based on an initial conversion rate, subject to adjustment, of 15.56 shares of CDI common stock per $1,000 of principal amount of the Convertible Senior Notes. This ratio results in an initial conversion price of approximately $64.27 per share. The Company may redeem the Convertible Senior Notes on or after December 20, 2012. Beginning with the period commencing on December 20, 2012 to June 14, 2013 and for each six-month period thereafter, in addition to the stated interest rate of 3.25% per annum, the Company will pay contingent interest of 0.25% of the market value of the Convertible Senior Notes if, during specified testing periods, the average trading price of the Convertible Senior Notes exceeds 120% or more of the principal value. In addition, holders of the Convertible Senior Notes may require the Company to repurchase the notes at 100% of the principal amount on each of December 15, 2012, 2015, and 2020, and upon certain events.

     The Convertible Senior Notes can be converted prior to the stated maturity under the following circumstances:

     In connection with any conversion, the Company will satisfy its obligation to convert the Convertible Senior Notes by delivering to holders in respect of each $1,000 aggregate principal amount of notes being converted a “settlement amount” consisting of:

     The conversion value means the product of (1) the conversion rate in effect (plus any applicable additional shares resulting from an adjustment to the conversion rate) or, if the Convertible Senior Notes are converted during a registration default, 103% of such conversion rate (and any such additional shares), and (2) the average of the last reported sale prices of CDI’s common stock for the trading days during the cash settlement period.

     Shares underlying the Convertible Senior Notes were not included in the calculation of diluted earnings per share because the Company’s share price as of September 30, 2005, was below the conversion price of approximately $64.27 per share. As a result, there would be no premium over the principal amount, which is paid in cash, so no shares would be issued on conversion. The maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 6,651,885. In addition to the 6,651,885 shares of common stock registered, the Company registered an indeterminate number of shares of common stock issuable upon conversion of the Convertible Senior Notes by means of an

antidilution adjustment of the conversion price pursuant to the terms of the Convertible Senior Notes. Proceeds from the offering were used for general corporate purposes including a capital contribution of $72 million made in March 2005 to Deepwater Gateway, L.L.C. to enable it to repay its term loan, $163.5 million related to the ERT acquisition of the Murphy properties in June 2005 and approximately $85.4 million for the Torch vessels acquired in August 2005 (see Note 19).

     At September 30, 2005, $134.9 million was outstanding on the Company’s 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 initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements, in September 2005, the Company fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027). 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, 2005, the Company was in compliance with these covenants.

     In September 2005, the company entered into an interest rate swap agreement with a bank. The swap was designated as a cash flow hedge of a forecasted transaction in anticipation of the refinancing of the MARAD Debt from floating rate debt to fixed-rate debt that closed on September 30, 2005. The interest rate swap agreement totaled an aggregate notional amount of $134.9 million with a fixed interest rate of 4.695%. On September 30, 2005, the Company terminated the interest rate swap and received cash proceeds of approximately $1.5 million representing a gain on the interest rate differential. This gain will be deferred and amortized over the remaining life of the MARAD Debt as an adjustment to interest expense.

     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 the existing or additional lenders. The credit facility is secured by the stock in certain Company subsidiaries and contains a negative pledge on assets. The 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, 2005, the Company was in compliance with these covenants and there was no outstanding balance under this facility.

     Scheduled maturities of Long-term Debt and Capital Lease Obligations outstanding as of September 30, 2005 were as follows (in thousands):

     The Company had unsecured letters of credit outstanding at September 30, 2005 totaling approximately $3.7 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 was collateralized by substantially all of Deepwater Gateway, L.L.C.’s assets and was non-recourse to the Company except for the balloon payment due at the end of the term. In March 2005, the term loan was repaid in full by Deepwater Gateway, L.L.C. and the term loan agreement was canceled.

     Deferred financing costs of $18.7 million (included in other assets, net) related to the Convertible Senior Notes, the MARAD Debt and the revolving credit facility, respectively, are being amortized over the life of the respective agreements and are included in other assets, net, as of September 30, 2005.

     The Company capitalized interest totaling $526,000 and $1.1 million during the three and nine months ended September 30, 2005, respectively. The Company capitalized interest totaling $0 and $243,000 during the three and nine months ended September 30, 2004, respectively. The Company incurred interest expense of $2.2 million and $4.2 million during the three and nine months ended September 30, 2005, respectively, and $694,000 and $3.2 million during the three and nine months ended September 30, 2004, respectively.

     The effective tax rate of 37% in the three months ended September 30, 2005 was higher than the effective rate of 36% in third quarter 2004. Further the effective rate of 36% in the nine months ended September 30, 2005 was higher than the effective tax rate of 34% in the first nine months of 2004. The effective tax rate was lower in the first nine months of 2004 primarily due to the income tax provision benefit recorded in the first quarter of 2004 of $1.7 million, offset by interest expense of $430,000, to report the impact of research and development credits resulting from the conclusion of the Internal Revenue Service examination of the Company’s income tax returns for 2001 and 2002.

     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 preliminary findings by the arbitrator is applicable to CDO, and CDO holds substantial counterclaims against Seacore.

     Although the above discussed matters may have the potential for 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.

     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 believed under the terms of the contract the Company was entitled to indemnification for the contractual stand-by rate for the vessels during their downtime. The customer had disputed these invoices along with certain other change orders. In May 2004, the Company and its customer settled certain elements of the dispute. The remaining elements were settled in March 2005 with no material effect on the Company’s financial position, results of operations or cash flows.

     The Company sustained damage to certain of its oil and gas production facilities in HurricanesKatrina and Rita. The Company estimates total repair and inspection costs resulting from the hurricanes will range from $5 million to $8 million, net of expected insurance reimbursement. These costs, and any related insurance reimbursements, will be recorded as incurred over the next year.

     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 or not employment continued. 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 were classified as long-term debt in the accompanying balance sheet and have been adjusted to their estimated redemption value at each reporting period based on Canyon’s performance. In March 2005, the Company purchased the final one-third of the redeemable shares at the minimum purchase price of $13.53 per share. Consideration included approximately $337,000 of contingent consideration relating to tax gross-up payments paid to the Canyon employees in accordance with the purchase agreement. This gross-up amount was recorded as goodwill in the period paid.

     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 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. In the event the holder of the convertible preferred stock elects to redeem into Cal Dive common stock and Cal Dive’s common stock price is below the conversion prices, unless the Company has elected to settle in cash, the holder would receive additional shares above the 833,334 common shares (Series A-1 tranche) and 982,029 common shares (Series A-2 tranche). The incremental shares would be treated as a dividend and reduce net income applicable to common shareholders.

     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 2005 and 2004 on the last day of the respective quarter in cash. 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.

     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. 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 lower of the Company’s share price at the beginning of the applicable period or the applicable conversion price ($30.00 and $30.549).

     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 $7.5 million and $20.8 million in the three and nine months ended September 30, 2005, respectively, and $5.5 million and $13.2 million in the three and nine months ended September 30, 2004, respectively.

     In a bankruptcy auction held in June 2005, CDI was the high bidder for seven vessels, including the Midnight Express, and a portable saturation system for approximately $85 million, subject to the terms of an amended and restated asset purchase agreement, executed in May 2005, with Torch Offshore, Inc. and its wholly owned subsidiaries, Torch Offshore, L.L.C. and Torch Express, L.L.C. This transaction received regulatory approval, including completion of a review pursuant to a Second Request from the U.S. Department of Justice, in August 2005 and subsequently closed. The total purchase price for the Torch vessels was approximately $85.4 million, including certain costs incurred related to the transaction. The acquisition was accounted for as a purchase with the acquisition price allocated to the assets acquired based upon their estimated fair values. The results of the acquired vessels are included in the accompanying condensed consolidated statements of operations since the date of the purchase, August 31, 2005.

     Also in April 2005, the Company agreed to acquire the diving and shallow water pipelay assets of Stolt Offshore that currently operate in the waters of the Gulf of Mexico (GOM) and Trinidad. The transaction includes: seven diving support vessels; two diving and pipelay vessels (the Kestreland the DB 801); a portable saturation diving system; various general diving equipment and Louisiana operating bases at the Port of Iberia and Fourchon. The transaction required regulatory approval, including the completion of a review pursuant to a Second Request from the U.S. Department of Justice. On October 18, 2005, the Company received clearance from the U.S. Department of Justice to close the asset purchase from Stolt. Under the terms of the clearance, the Company will divest two diving support vessels and a portable saturation diving system from the combined asset package acquired through this transaction and the Torch transaction which closed August 31, 2005. On November 1, 2005, the Company closed the transaction to purchase the diving assets of Stolt that operate in the Gulf of Mexico. The assets include: seven diving support vessels, a portable saturation diving system, various general diving equipment and Louisiana operating bases at the Port of Iberia and Fourchon. Separate agreements to purchase the DB801 andKestrel will be closed when those assets complete their present work campaigns in Trinidadian waters. The total transaction value for all of the assets will be approximately $123 million. The acquisition will be accounted for as a purchase with the acquisition price allocated to the assets acquired based upon their estimated fair values.

     On November 3, 2005 the Company acquired for approximately $31 million, Helix Energy Limited, an Aberdeen, UK based provided of reservoir and well technology services to the upstream oil and gas industry with offices in London, Kuala Lampur (Malaysia) and Perth (Australia). This acquisition will be accounted for as a purchase with the acquisition price allocated to the assets and liabilities acquired based upon their estimated fair values.

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

     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, 2004, filed with the Securities and Exchange Commission.

     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. There have been no 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, 2004.

     Revenues: During the three months ended September 30, 2005, the Company’s revenues increased 59% to $209.3 million compared to $132.0 million for the three months ended September 30, 2004. Of the overall $77.4 million increase, $61.9 million was generated by the Marine Contracting segment due to improved market conditions for marine contracting services, specifically improved contract rates and utilization rates for all divisions within the segment.

     Oil and Gas Production revenue for the three months ended September 30, 2005 increased $15.5 million, or 26%, to $75.5 million from $60.0 million during the comparable prior year period. Production decreased 15% (8.4 Bcfe for the three months ended September 30, 2005 compared to 10 Bcfe in the third quarter of 2004) primarily due to the effects of production shut-ins due to Hurricanes Katrina and Rita in the third quarter of 2005. The average realized natural gas price of $8.66 per Mcf, net of hedges in place, during the third quarter of 2005 was 48% higher than the $5.84 per Mcf realized in the comparable prior year quarter while average realized oil prices, net of hedges in place, also increased 48% to $54.30 per barrel compared to $36.79 per barrel realized during the third quarter of 2004.

     Gross Profit. Gross profit of $82.9 million for the third quarter of 2005 represented a 81% increase compared to the $45.7 million recorded in the comparable prior year period with the Marine Contracting segment contributing 80% of the increase. Marine Contracting gross profit increased $29.6 million to $42.1 million, for the three months ended September 30, 2005, from $12.4 million in the prior

year period. All divisions within Marine Contracting achieved higher gross profit due to improved market conditions (i.e., overall improved contract rates and utilization rates, for the segment).

     Gross margins of 40% in the third quarter of 2005 were five points better than the 35% in the prior year period. Marine Contracting margins increased fourteen points to 31% for the three months ended September 30, 2005, from 17% in the comparable prior year quarter, due to the factors noted above. In addition, margins in the Oil and Gas Production segment decreased one point to 54% for the three months ended September 30, 2005 from 55% in the year ago quarter, due primarily to $2.7 million of losses associated with hedge instrument ineffectiveness due to production shut-ins also as a result of the aforementioned hurricanes.

     The Company sustained damage to certain of its oil and gas production facilities in HurricanesKatrina and Rita. The Company estimates total repair and inspection costs resulting from hurricanes will range from $5 million to $8 million, net of expected insurance reimbursement. These costs, and any related insurance reimbursements, will be recorded as incurred over the next year.

     Gain on Sale of Assets. The Company recognized a gain of approximately $329,000 in the third quarter of 2005 related to its exchange of the Witch Queen for a 40% minority ownership interest in Offshore Technology Solutions Limited (“OTSL”).

     Selling & Administrative Expenses. Selling and administrative expenses of $15.9 million for the third quarter of 2005 were $5.0 million higher than the $10.9 million incurred in the third quarter of 2004 due primarily to increased incentive compensation as a result of increased profitability. Selling and administrative expenses were 8% of revenues for the third quarter of 2005 compared with 8% in the third quarter of 2004.

     Equity in Earnings of Investments. Equity in earnings of the Company’s 50% investment in Deepwater Gateway, L.L.C. was $3.1 million in the third quarter of 2005 comparable to the $3.1 million in the prior year period. Demand fees commenced following the March 2004 mechanical completion of the Marco Polo tension leg platform, owned by Deepwater Gateway, L.L.C. Production tariff charges commenced in the third quarter of 2004 as Marco Polo began producing. Further, equity in earnings from the Company’s 40% minority ownership interest in OTSL in third quarter 2005 totaled approximately $672,000.

     Other (Income) Expense. The Company reported other expense of $2.8 million in the third quarter of 2005 compared to other expense of $838,000 in the third quarter of 2004. Net interest expense of $2.2 million in the third quarter of 2005 was higher than the $694,000 incurred in the third quarter of 2004 due to higher levels of debt.

     Income Taxes. Income taxes increased to $25.1 million in the third quarter of 2005 compared to $13.2 million in the comparable prior year period primarily due to increased profitability. The effective rate was 37% in third quarter 2005 compared with 36% in third quarter 2004.

     Net Income. Net income of $42.7 million in the third quarter of 2005 was $19.9 million greater than the comparable period in 2004 as a result of factors described above.

     Revenues. During the nine months ended September 30, 2005, the Company’s revenues increased 41% to $535.4 million compared to $380.4 million for the nine months ended September 30, 2004. Of the overall $155.0 million increase, $125.1 million was generated by the Marine Contracting segment due to improved market conditions for marine contracting services, specifically improved contract rates and utilization rates.

     Oil and Gas Production revenue for the nine months ended September 30, 2005 increased $29.9 million, or 17%, to $206.4 million from $176.5 million during the comparable prior year period. Production decreased 12% (26.3 Bcfe for the nine months ended September 30, 2005 compared to 30.0 Bcfe in the first nine months of 2004) primarily due to natural decline in the Company’s Shelf properties production and the effects of production shut-ins due to Hurricanes Katrina and Rita in the third quarter of 2005. The average

realized natural gas price of $7.54 per Mcf, net of hedges in place, during the first nine months of 2005 was 29% higher than the $5.83 per Mcf realized in the comparable prior year period while average realized oil prices, net of hedges in place, increased 42% to $47.80 per barrel compared to $33.62 per barrel realized during the first nine months of 2004.

     Gross Profit. Gross profit of $187.2 million for the first nine months of 2005 represented a 57% increase compared to the $118.9 million recorded in the comparable prior year period with the Marine Contracting segment contributing 81% of the increase. Marine Contracting gross profit increased $55.6 million to $79.8 million, for the nine months ended September 30, 2005, from $24.2 million in the prior year period. All divisions within Marine Contracting achieved higher gross profit due to improved market conditions (i.e. overall improved contract rates and utilization rates for the segment). Oil and Gas Production gross profit increased $12.8 million, up 13% from the first nine months of 2004, due to higher commodity prices.

     Gross margins of 35% in the first nine months of 2005 were four points better than the 31% in the first nine months of 2004. Marine Contracting margins increased twelve points to 24% for the nine months ended September 30, 2005, from 12% in the comparable prior year period, due to the factors noted above. In addition, margins in the Oil and Gas Production segment decreased two points to 52% for the nine months ended September 30, 2005 from 54% in the comparable prior year period, due primarily to impairment analysis on certain properties and expensed well work which resulted in $4.4 million of impairments, $5.3 million of expensed seismic data purchased for ERT’s offshore property acquisitions and $2.7 million of losses associated with hedge instrument ineffectiveness due to production shut-ins also as a result of the aforementioned hurricanes.

     The Company sustained damage to certain of its oil and gas production facilities in HurricanesKatrina and Rita. The Company estimates total repair and inspection costs resulting from hurricanes will range from $5 million to $8 million, net of expected insurance reimbursement. These costs, and any related insurance reimbursements, will be recorded as incurred over the next year.

     Gain of Sale of Assets. The Company’s ROV division, Canyon Offshore, sold an ROV in the first quarter of 2005 and recognized a $925,000 gain on the sale. Further, the Company recognized a gain of approximately $329,000 in the third quarter of 2005 related to the Company’s exchange of theWitch Queen for a 40% minority ownership interest in OTSL.

     Selling & Administrative Expenses. Selling and administrative expenses of $41.6 million for the first nine months of 2005 were $6.8 million higher than the $34.7 million incurred in the first nine months of 2004 due to higher profitability which led to higher incentive compensation costs. Selling and administrative expenses were 8% of revenues for the first nine months of 2005 compared with 9% in the comparable prior year period.

     Equity in Earnings of Investments. Equity in earnings of the Company’s 50% investment in Deepwater Gateway, L.L.C. increased to $7.5 million in the first nine months of 2005 compared with $4.4 million 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 as Marco Polo began producing. Further, equity in earnings from the Company’s 40% minority ownership interest in OTSL in the first nine months of 2005 totaled approximately $672,000.

     Other (Income) Expense. The Company reported other expense of $4.9 million in the first nine months of 2005 compared to other expense of $3.6 million in the first nine months of 2004. Net interest expense of $4.2 million in the first nine months of 2005 was higher than the $3.2 million incurred in the first nine months of 2004 due to higher levels of debt.

     Income Taxes. Income taxes increased to $54.4 million in the first nine months of 2005 compared to $28.5 million in the comparable prior year period primarily due to increased profitability. The effective tax rate of 36% in the first nine months of 2005 was higher than the effective tax rate of 34% in the prior

year period 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 $94.1 million in the first nine months of 2005 was $39.5 million greater than the comparable period in 2004 as a result of factors described above.

     Total debt as of September 30, 2005 was $442.5 million comprised primarily of $300 million of Convertible Senior Notes which mature in 2025 and $134.9 million of MARAD debt which matures in 2027. See further discussion below under “Financing Activities”. In addition, the Company had $150.5 million of unrestricted cash as of September 30, 2005, as well as a $150 million, undrawn revolving credit facility. The majority of the unrestricted cash will be utilized for the previously announced acquisition of certain assets of Stolt Offshore and the acquisition of Helix Energy Limited.

     Hedging 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 2004 and the first nine months of 2005, 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. The aggregate fair value of the hedge instruments was a net liability of $32.0 million as of September 30, 2005. The Company recorded approximately $18.4 million of unrealized losses, net of taxes of $9.9 million, during the first nine months of 2005 in other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective. During the three and nine months ended September 30, 2005, the Company reclassified approximately $3.2 million and $6.1 million, respectively, of losses from other comprehensive income to Oil and Gas Production revenues upon the sale of the related oil and gas production.

     Hedge ineffectiveness related to cash flow hedges was a loss of $1.8 million, net of taxes of $951,000, in the third quarter of 2005 as reported in current period earnings as a reduction of oil and gas production revenues. Hedge ineffectiveness resulted from ERT’s projected inability to deliver contractual oil and gas production in fourth quarter 2005 due primarily to the effects of Hurricanes Katrina and Rita.

     Operating Activities. Net cash provided by operating activities was $183.0 million during the nine months ended September 30, 2005, compared to $129.8 million generated during the first nine months of 2004, due primarily to an increase in profitability ($39.4 million) and an increase in accounts payable and accrued liabilities due primarily to increased royalty accruals, hedge liability accruals and accruals for capital expenditures for which cash has not yet been expended. Cash flow from operations was negatively impacted by an increase in trade accounts receivable of approximately $33.2 million due primarily to increased revenues in the Marine Contracting and Oil and Gas Production segments. Further, cash flow from operations was negatively impacted by approximately $20 million of cash used to fund regulatory drydocking activity in the first nine months of 2005.

     Investing Activities. We incurred $319.1 million of capital acquisitions and expenditures during the first nine months of 2005 compared to $26.0 million during the comparable prior year period. Included in the capital acquisitions and expenditures during the first nine months of 2005 was $163.5 million for the Murphy properties acquisition by ERT, $85.4 million for the acquisition of the Torch Offshore assets, $49.6 million for ERT well exploitation programs and further Gunnisonfield development, $10.9 million for Canyon Offshore ROV and trencher systems, and approximately $6.7 million for vessel upgrades on certain Marine Contracting vessels. Included in the capital expenditures during the first nine months of 2004 was $5.5 million for the purchase of our intervention riser system installed on the Q4000 and $18.1 million for ERT well exploitation programs and further Gunnison field development.

     During the first nine months of 2005, the Company invested $100.5 million in its Production Facilities segment which consists of our investments in Deepwater Gateway, L.L.C. and Independence Hub, LLC. In June 2002, CDI, along with Enterprise Products Partners L.P. (“Enterprise”), 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 TLP production hub primarily for Anadarko Petroleum Corporation’s Marco Polo field discovery in the Deepwater Gulf of Mexico. The Company’s

investment in Deepwater Gateway, L.L.C. totaled $119.2 million as of September 30, 2005. Included in the investment account was capitalized interest and insurance paid by the Company totaling approximately $1.8 million. In August 2002, the Company along with Enterprise, completed a limited recourse project financing for this venture. In accordance with terms of the term loan of $144 million, Deepwater Gateway, L.L.C. had the right to repay the principal amount plus any accrued interest due under its term loan at any time without penalty. Deepwater Gateway, L.L.C. repaid in full its term loan in March 2005. The Company and Enterprise made equal cash contributions ($72 million each) to Deepwater Gateway, L.L.C. to fund the repayment. Upon repayment of the term loan, the Company’s $7.5 million of restricted cash was released from escrow and the escrow agreement was terminated. Further, the Company received cash distributions from Deepwater Gateway, L.L.C. totaling $16.1 million in the first nine months of 2005.

     In December 2004, CDI acquired a 20% interest (accounted for by CDI under the equity method of accounting) in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence will own the “Independence Hub” platform to be located in Mississippi Canyon block 920 in a water depth of 8,000 feet. CDI’s investment was $39.7 million as of September 30, 2005, and its total investment is expected to be approximately $77 million. Further, CDI is party to a guaranty agreement with Enterprise to the extent of CDI’s ownership in Independence. The agreement states, among other things, that CDI and Enterprise guarantee performance under the Independence Hub Agreement between Independence and the producers group of exploration and production companies up to $397.5 million, plus applicable attorneys’ fees and related expenses. CDI has estimated the fair value of its share of the guarantee obligation to be immaterial at September 30, 2005 based upon the extremely remote possibility of payments being made under the performance guarantee.

     In July 2005, the Company acquired a 40% minority ownership interest in OTSL (accounted for by CDI under the equity method of accounting) in exchange for the Company’s DP DSV, Witch Queen. The Company’s investment in OTSL totaled $9.4 million at September 30, 2005. OTSL provides marine construction services to the oil and gas industry in and around Trinidad and Tobago, as well as the U.S. Gulf of Mexico. The Company accounts for its investment in OTSL under the equity method of accounting. In addition, the Company had certain rights and guarantee obligations of up to $3.5 million under the OTSL shareholder agreement. The estimated fair value of the guarantee obligations was deemed immaterial by CDI at September 30, 2005 due to the remote possibility of payments being made by CDI under the guarantee. In October 2005, the shareholders of OTSL agreed to remove the CDI guarantee obligation from the shareholder agreement effective September 30, 2005.

     Further, in conjunction with its investment in OTSL, the Company entered into a one year, unsecured $1.5 million working capital loan, bearing interest at 6% per annum, with OTSL. Interest is due quarterly beginning September 30, 2005 with a lump sum principal payment due to the Company on June 30, 2006.

     In the third quarter of 2005, OTSL contracted the Witch Queen to the Company for certain services to be performed in the U.S. Gulf of Mexico. The Company incurred costs associated with the contract OTSL totaling approximately $2.4 million during the third quarter of 2005.

     As of September 30, 2005, the Company had $24.4 million of restricted cash, included in other assets, net, in the accompanying condensed consolidated balance sheet, all of which related to ERT’s escrow funds for decommissioning liabilities associated with the SMI 130 field acquisitions in 2002. Under the purchase agreement for the acquisitions ERT is obligated to escrow 50% of production up to the first $20 million and 37.5% of production on the remaining balance up to $33 million in total escrow. ERT may use the restricted cash for decommissioning the related fields.

     In March 2005, Canyon Offshore sold an ROV for $2.1 million in cash and recognized a gain on the sale totaling $925,000. In conjunction with the Company’s exchange of the Witch Queen for a 40% minority ownership interest in OTSL, the Company recognized a gain of approximately 329,000.

     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 $20.8 million and $13.2 million in the first nine months of 2005 and 2004, respectively.

     As an extension of ERT’s well exploitation and PUD strategies, ERT agreed to participate in the drilling of an exploratory well (Tulane prospect) to be drilled in 2006 that targets reserves in deeper sands, within the same trapping fault system, of a currently producing well with estimated drilling costs of approximately $18 million, of which $5.0 million had been incurred through September 30, 2005. If the drilling is successful, ERT’s share of the development cost is estimated to be an additional $21 million. CDI’s Marine Contracting assets would participate in this development.

     In March 2005, ERT acquired a 30% working interest in a proven undeveloped field in Atwater Block 63 (Telemark) of the deepwater Gulf of Mexico for cash consideration and assumption of certain decommissioning liabilities.

     In April 2005, ERT entered into a participation agreement to acquire a 50% working interest in the Devil’s Island discovery (Garden Banks Block 344 E/2) in 2,300 feet water depth. This deepwater development is operated by Amerada Hess and will be drilled in 2006. The field will be developed via a subsea tieback to Baldpate Field (Garden Banks Block 260). Under the participation agreement, ERT will pay 100% of the drilling costs and a disproportionate share of the development costs to earn 50% working interest in the field.

     Also in April 2005, ERT acquired a 37.5% working interest in the Bass Lite discovery (Atwater Blocks 182, 380, 381, 425 and 426) in 7,500 feet water depth along with varying interests in 50 other blocks of exploration acreage in the eastern portion of the Atwater lease protraction area from BHP Billiton. The Bass Lite discovery contains proved undeveloped gas reserves in a sand discovered in 2001 by the Atwater 426 #1 well. In October 2005, ERT exchanged 15% of its working interest in Bass Lite for a 40% working interest in the Tiger Prospect located in Green Canyon Block 195. ERT paid $1.0 million in the exchange with no corresponding gain or loss recorded on the transaction.

     As of September 30, 2005, the Company had spent $28.7 million and had committed to an additional estimated $39 million for development and drilling costs related to the above property transactions.

     In a bankruptcy auction held in June 2005, CDI was the high bidder for seven vessels, including the Midnight Express, and a portable saturation system for approximately $85 million, subject to the terms of an amended and restated asset purchase agreement, executed in May 2005, with Torch Offshore, Inc. and its wholly owned subsidiaries, Torch Offshore, L.L.C. and Torch Express, L.L.C. This transaction received regulatory approval, including completion of a review pursuant to a Second Request from the U.S. Department of Justice, in August 2005 and subsequently closed. The total purchase price for the Torch vessels was approximately $85.4 million, including certain costs incurred related to the transaction. The acquisition was accounted for as a purchase with the acquisition price allocated to the assets acquired based upon their estimated fair values. The results of the acquired vessels are included in the accompanying condensed consolidated statements of operations since the date of the purchase, August 31, 2005.

     Also in April 2005, the Company agreed to acquire the diving and shallow water pipelay assets of Stolt Offshore that currently operate in the waters of the Gulf of Mexico (GOM) and Trinidad. The transaction includes: seven diving support vessels; two diving and pipelay vessels (the Kestreland the DB 801); a portable saturation diving system; various general diving equipment and Louisiana operating bases at the Port of Iberia and Fourchon. The transaction required regulatory approval, including the completion of a review pursuant to a Second Request from the U.S. Department of Justice. On October 18, 2005, the Company received clearance from the U.S. Department of Justice to close the asset purchase from Stolt. Under the terms of the clearance, the Company will divest two diving support vessels and a portable saturation diving system from the combined asset package acquired through this transaction and the Torch transaction which closed August 31, 2005. On November 1, 2005, the

Company closed the transaction to purchase the diving assets of Stolt that operate in the Gulf of Mexico. The assets include: seven diving support vessels, a portable saturation diving system, various general diving equipment and Louisiana operating bases at the Port of Iberia and Fourchon. Separate agreements to purchase the DB801 and Kestrel will be closed when those assets complete their present work campaigns in Trinidadian waters. The total transaction value for all of the assets will be approximately $123 million. The acquisition will be accounted for as a purchase with the acquisition price allocated to the assets acquired based upon their estimated fair values.

     On November 3, 2005, the Company acquired for approximately $31 million, Helix Energy Limited, an Aberdeen, UK based provided of reservoir and well technology services to the upstream oil and gas industry with offices in London, Kuala Lampur (Malaysia) and Perth (Australia). This acquisition will be accounted for as a purchase with the acquisition price allocated to the assets and liabilities acquired based upon their estimated fair values.

     In June 2005, ERT acquired a mature property package on the Gulf of Mexico shelf from Murphy Exploration & Production Company — USA (“Murphy”), a wholly owned subsidiary of Murphy Oil Corporation. The acquisition cost to ERT included both cash ($163.5 million) and the assumption of the abandonment liability from Murphy of approximately $32.0 million. The acquisition represents essentially all of Murphy’s Gulf of Mexico Shelf properties consisting of eight operated and eleven non-operated fields. ERT estimates proved reserves of the acquisition to be approximately 75 BCF equivalent.

     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.

     On March 30, 2005, the Company issued $300 million of 3.25% Convertible Senior Notes due 2025 (“Convertible Senior Notes”) at 100% of the principal amount to certain qualified institutional buyers. The Company also incurred financing costs of approximately $8.1 million (included in other assets, net, in the accompanying condensed consolidated balance sheet) which will be amortized over the life of the debt agreement. The Convertible Senior Notes are convertible into cash and, if applicable, shares of the Company’s common stock based on an initial conversion rate, subject to adjustment, of 15.56 shares of CDI common stock per $1,000 of principal amount of the Convertible Senior Notes. This ratio results in an initial conversion price of approximately $64.27 per share. The Company may redeem the Convertible Senior Notes on or after December 20, 2012. Beginning with the period commencing on December 20, 2012 to June 14, 2013 and for each six-month period thereafter, in addition to the stated interest rate of 3.25% per annum, the Company will pay contingent interest of 0.25% of the market value of the Convertible Senior Notes if, during specified testing periods, the average trading price of the Convertible Senior Notes exceeds 120% or more of the principal value. In addition, holders of the Convertible Senior Notes may require the Company to repurchase the notes at 100% of the principal amount on each of December 15, 2012, 2015, and 2020, and upon certain events.

     The Convertible Senior Notes can be converted prior to the stated maturity under the following circumstances:

     In connection with any conversion, the Company will satisfy its obligation to convert the Convertible Senior Notes by delivering to holders in respect of each $1,000 aggregate principal amount of notes being converted a “settlement amount” consisting of:

     The conversion value means the product of (1) the conversion rate in effect (plus any applicable additional shares resulting from an adjustment to the conversion rate) or, if the Convertible Senior Notes are converted during a registration default, 103% of such conversion rate (and any such additional shares), and (2) the average of the last reported sale prices of CDI’s common stock for the trading days during the cash settlement period.

     Shares underlying the Convertible Senior Notes were not included in the calculation of diluted earnings per share because the Company’s share price as of September 30, 2005, was below the conversion price of approximately $64.27 per share. As a result, there would be no premium over the principal amount, which is paid in cash, so no shares would be issued on conversion. The maximum number of shares of common stock which may be issued upon conversion of the Convertible Senior Notes is 6,651,885. In addition to the 6,651,885 shares of common stock registered, the Company registered an indeterminate number of shares of common stock issuable upon conversion of the Convertible Senior Notes by means of an antidilution adjustment of the conversion price pursuant to the terms of the Convertible Senior Notes. Proceeds from the offering were used for general corporate purposes including a capital contribution of $72 million (made in March 2005) to Deepwater Gateway, L.L.C. to enable it to repay its term loan, $163.5 million related to the ERT acquisition of the Murphy properties in June 2005 and approximately $85.4 million for the Torch vessels acquired in August 2005.

     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 during each of the nine months ended September 30, 2005 and 2004 totaling $4.3 million and $2.9 million, respectively. The MARAD Debt is collateralized by the Q4000, with Cal Dive guaranteeing 50% of the debt, and initially bore interest at a floating rate which approximated AAA Commercial Paper yields plus 20 basis points. As provided for in the MARAD Debt agreements in September 2005, the Company fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027). 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, 2005, we were in compliance with these covenants.

     In September 2005, the Company entered into an interest rate swap agreement with a bank. The swap was designated as a cash flow hedge of a forecasted transaction in anticipation of the refinancing of the MARAD Debt from floating rate debt to fixed-rate debt that closed on September 30, 2005. The interest rate swap agreement totaled an aggregate notional amount of $134.9 million with a fixed interest rate of 4.695%. On September 30, 20005, the Company terminated the interest rate swap and received cash proceeds of approximately $1.5 million representing a gain on the interest rate differential. This gain will be deferred and amortized over the remaining life of the MARAD Debt as an adjustment to interest expense.

     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 $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 credit facility is secured by the stock in certain Company subsidiaries and contains a negative pledge on assets. The 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, 2005, 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.

     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 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. In the event the holder of the convertible preferred stock elects to redeem into Cal Dive common stock and Cal Dive’s common stock price is below the conversion prices, unless the Company has elected to settle in cash, the holder would receive additional shares above the 833,334 common shares (Series A-1 tranche) and 982,029 common shares (Series A-2 tranche). The incremental shares would be treated as a dividend and reduce net income applicable to common shareholders. 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 2005 and 2004 on the last day of the respective quarter in cash. 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.

     During the first nine months of 2005 and 2004, we made payments of $2.1 million and $2.6 million respectively, on capital leases relating to Canyon. The only other financing activity during the nine months ended September 30, 2005 and 2004 involved the exercise of employee stock options ($7.2 million and $9.5 million, respectively).

     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 or not employment continued. 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 were classified as long-term debt in the accompanying balance sheet and have been adjusted to their estimated redemption value at each reporting period based on Canyon’s performance. In March 2005 the Company purchased the final one-third of the redeemable shares at the minimum purchase price of $13.53 per share ($2.4 million). Consideration included approximately $337,000 of contingent consideration relating to tax gross-up payments paid to the Canyon employees in accordance with the purchase agreement. This gross-up amount was recorded as goodwill in the period paid.

     The following table summarizes our contractual cash obligations as of September 30, 2005 and the scheduled years in which the obligations are contractually due (in thousands):

     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.

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.

     Because none of the Company’s outstanding debt at September 30, 2005 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.

     The Company has utilized derivative financial instruments with respect to a portion of 2005 and 2004 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, 2005, the Company has the following volumes under derivative contracts related to its oil and gas producing activities:

     Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, caused the fair value of these instruments to increase or decrease inversely to the change in NYMEX prices.

     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 Cal Dive International Limited). The functional currency for Cal Dive International 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 each of the three and nine months ended September 30, 2005 and 2004, respectively, did not have a material effect on reported amounts of revenues or net income.

     Assets and liabilities of Cal Dive International 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 in the shareholders’ equity section of our balance sheet. Approximately 9% of our assets are impacted by changes in foreign currencies in relation to the U.S. dollar. We recorded unrealized losses of $1.3 million and $8.0 million, respectively, to our equity account in the three and nine months ended September 30, 2005 and gains of $546,000 and $1.8 million, respectively, to our equity account in the three and nine months ended September 30, 2004. Beginning in 2004, deferred taxes

have not been provided on foreign currency translation adjustments since the Company considers its undistributed earnings (when applicable) of its non-U.S. subsidiaries to be permanently reinvested.

     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, 2005 and 2004, 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, 2005. 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, 2005 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 (i) recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms and (ii) accumulated and communicated to the Company’s management, as appropriate, to allow timely decisions regarding required disclosure.

     There were no changes in the Company’s internal control over financial reporting that occurred during the fiscal quarter ended September 30, 2005 that have materially affected, or are reasonable likely to materially affect, the Company’s internal control over financial reporting.

ITEM 1. LEGAL PROCEEDINGS

     See Part I, Item I, Note 15 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

ITEM 6. EXHIBITS

Exhibit 2.1 Bond Purchase Agreement dated September 27, 2005, between Cal Dive I-Title XI, Inc. and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on October 6, 2005 (the “October Form 8-K”)

Exhibit 4.1 Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.1 to the October Form 8-K

Exhibit 4.2 Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.2 to the October Form 8-K

Exhibit 4.3 Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.3 to the October Form 8-K

Exhibit 4.4 Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.4 to the October Form 8-K

Exhibit 4.5 Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.5 to the October Form 8-K

Exhibit 4.6 Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027 (filed as Exhibit A to Exhibit 4.5)

Exhibit 4.7 Form of Third Amended and Restated Promissory Note to United States of America, incorporated by reference to Exhibit 4.7 to the October Form 8-K

Exhibit 4.8 Amendment to Asset Purchase Agreement by and between Cal Dive International, Inc., as Buyer, and Stolt Offshore Inc., S&H Diving LLC and SCS Shipping Limited, as Sellers, dated November 2, 2005, incorporated by reference to Exhibit 1.01 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on November 4, 2005.

Exhibit 10.1 Employment Agreement by and between Cal Dive International, Inc. and Bart H. Heijermans, effective as of September 1, 2005, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on September 1, 2005

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

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.

Exhibit 2.1 Bond Purchase Agreement dated September 27, 2005, between Cal Dive I-Title XI, Inc. and J.P. Morgan Securities Inc., incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on October 6, 2005 (the “October Form 8-K”)

Exhibit 4.1 Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.1 to the October Form 8-K

Exhibit 4.2 Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.2 to the October Form 8-K

Exhibit 4.3 Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.3 to the October Form 8-K

Exhibit 4.4 Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.4 to the October Form 8-K

Exhibit 4.5 Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee, incorporated by reference to Exhibit 4.5 to the October Form 8-K

Exhibit 4.6 Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027 (filed as Exhibit A to Exhibit 4.5)

Exhibit 4.7 Form of Third Amended and Restated Promissory Note to United States of America, incorporated by reference to Exhibit 4.7 to the October Form 8-K

Exhibit 4.8 Amendment to Asset Purchase Agreement by and between Cal Dive International, Inc., as Buyer, and Stolt Offshore Inc., S&H Diving LLC and SCS Shipping Limited, as Sellers, dated November 2, 2005, incorporated by reference to Exhibit 1.01 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on November 4, 2005

Exhibit 10.1 Employment Agreement by and between Cal Dive International, Inc. and Bart H. Heijermans, effective as of September 1, 2005, incorporated by reference from Exhibit 10.1 to the Current Report on Form 8-K, filed by the registrant with the Securities and Exchange Commission on September 1, 2005

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