Helix Energy Solutions - 10-Q quarterly report FY

 

     Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

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     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

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As of April 30, 2008, 91,664,674 shares of common stock were 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 condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its majority-owned subsidiaries (collectively, “Helix” or the “Company”). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its majority-owned subsidiaries. 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 (“SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles.

          The accompanying condensed consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles and are consistent in all material respects with those applied in our Annual Report on Form 10-K for the year ended December 31, 2007 (“2007 Form 10-K”). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. Management has reflected all adjustments (which were normal recurring adjustments unless otherwise disclosed herein) 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 March 31, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008. Our balance sheet as of December 31, 2007 included herein has been derived from the audited balance sheet as of December 31, 2007 included in our 2007 Form 10-K. These condensed consolidated financial statements should be read in conjunction with the annual consolidated financial statements and notes thereto included in our 2007 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.

          We are an international offshore energy company that provides reservoir development solutions and other contracting services to the energy market as well as to our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and proprietary technologies to deliver services that reduce finding and development costs and cover the complete lifecycle of an offshore oil and gas field. Our Oil and Gas segment engages in prospect generation, exploration, development and production activities. We operate primarily in the Gulf of Mexico, North Sea, Asia Pacific and Middle East regions.

          We seek to provide services and methodologies which we believe are critical to finding and developing offshore reservoirs and maximizing production economics, particularly from marginal fields. By “marginal”, we mean reservoirs that are no longer wanted by major operators or are too small to be material to them. Our “life of field” services are organized in five disciplines: construction, well operations, production facilities, reservoir and well technology services, and drilling. We have disaggregated our contracting services operations into three reportable segments in accordance with Financial Accounting Standards Board (“FASB”) Statement No. 131, Disclosures about Segments of an Enterprise and Related Information (“SFAS No. 131”): Contracting Services (which currently includes deepwater construction, well operations and reservoir and well technology services and in the future, drilling); Shelf Contracting; and Production Facilities. Within our contracting services operations, we operate primarily in the Gulf of Mexico, the North Sea, Asia/Pacific and Middle East regions, with services that cover the lifecycle of an offshore oil or gas field. The assets of our Shelf Contracting segment are the

assets of Cal Dive International, Inc. (“Cal Dive” or “CDI”). Our ownership in CDI was approximately 58.2% as of March 31, 2008.

          In 1992 we began our oil and gas operations to provide a more efficient solution to offshore abandonment, to expand our off-season asset utilization of our contracting services assets and to achieve incremental returns to our contracting services. Over the last 16 years we have evolved this business model to include not only mature oil and gas properties but also proved and unproved reserves yet to be developed and explored. This has led to the assembly of services that allows us to create value at key points in the life of a reservoir from exploration through development, life of field management and operating through abandonment.

          We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of less than three months. As of March 31, 2008 and December 31, 2007, we had $35.0 million and $34.8 million, respectively, of restricted cash included in other assets, net, all of which was related to funds required to be escrowed to cover decommissioning liabilities associated with the South Marsh Island 130 (“SMI 130”) acquisition in 2002 by our Oil and Gas segment. We had fully satisfied the escrow requirement as of March 31, 2008. We may use the restricted cash for decommissioning the related field.

          The following table provides supplemental cash flow information for the three months ended March 31, 2008 and 2007 (in thousands):

          Non-cash investing activities for the three months ended March 31, 2008 included $45.7 million of accruals for capital expenditures. Non-cash investing activities for the three months ended March 31, 2007 were immaterial. The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.

          On December 11, 2007, CDI acquired 100% of Horizon Offshore, Inc. (“Horizon”), a marine construction services company headquartered in Houston, Texas. Upon consummating the merger of Horizon into a subsidiary of CDI, each share of Horizon common stock, par value $0.00001 per share, was converted into the right to receive $9.25 in cash and 0.625 shares of CDI’s common stock. All shares of Horizon restricted stock that had been issued but had not vested prior to the effective time of the merger became fully vested at such time and converted into the right to receive the merger consideration. CDI issued approximately 20.3 million shares of common stock and paid approximately $300 million in cash to the former Horizon stockholders upon completion of the acquisition. The cash portion of the merger consideration was paid from cash on hand and from borrowings of $375 million under CDI’s $675 million credit facility, which consists of a $375 million senior secured term loan and a $300 million senior secured revolving credit facility (see "—Note 9—Long-Term Debt” below).

          We recognized a non-cash pre-tax gain of $151.7 million ($98.6 million net of taxes of $53.1 million) in December 2007 as the value of our interest in CDI’s underlying equity increased as a result of CDI’s issuance of 20.3 million shares of common stock to former Horizon stockholders. The gain was

calculated as the difference in the value of our investment in CDI immediately before and after CDI’s stock issuance.

          The aggregate purchase price, including transaction costs of $7.7 million, was approximately $630 million, consisting of $308 million of cash and $322 million of stock. CDI also assumed and repaid approximately $104 million in Horizon’s debt, including accrued interest and prepayment penalties, and acquired $171 million of cash. Through the acquisition, CDI acquired nine construction vessels, including four pipelay/pipebury barges, one dedicated pipebury barge, one dive support vessel, one combination derrick/pipelay barge and two derrick barges. The acquisition was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair values.

          The following table summarizes the estimated preliminary fair values of the assets acquired and liabilities assumed at the date of acquisition (in thousands):

At March 31, 2008, the net carrying amount for these intangible assets was $7.7 million.

          The allocation of the purchase price was based upon preliminary valuations. Estimates and assumptions are subject to change upon the receipt and CDI management’s review of the final valuations. The primary area of the purchase price allocation that is not yet finalized relates to post-closing purchase price adjustments and the receipt of final valuations. The final valuation of net assets is expected to be completed no later than one year from the acquisition date. The results of Horizon are included in our Shelf Contracting segment in the accompanying condensed consolidated statements of operations since the date of purchase.

          The following unaudited pro forma combined operating results of us and Horizon for the quarter ended March 31, 2007 is presented as if the acquisition had occurred on January 1, 2007 (in thousands, except per share data):

          The pro forma operating results reflect adjustments for the increases in depreciation related to the “step-up” of the acquired assets to their fair value and to reflect depreciation calculations under the straight-line method instead of the units-of-production method used by Horizon. Pro forma results include the amortization of identifiable intangible assets. We estimated interest expense based upon increases in CDI’s long-term debt to fund the cash portion of the purchase price at an estimated annual interest rate of 7.55% for the quarter ended March 31, 2007, based upon the terms of CDI’s new term loan of three month LIBOR plus 2.25%. The pro forma adjustment to income tax reflects the statutory federal and state income tax impacts of the pro forma adjustments to our pretax income with an applied tax rate of 35%. The unaudited pro forma combined results of operations are not indicative of the actual results had the acquisition occurred on January 1, 2007 or of future operations of the combined companies. All material intercompany transactions between us and Horizon were eliminated.

          In October 2006, we acquired a 58% interest in Seatrac Pty Ltd. (“Seatrac”) for total consideration of approximately $12.7 million (including $180,000 of transaction costs), with approximately $9.1 million paid to existing Seatrac shareholders and $3.4 million for subscription of new Seatrac shares. We renamed this entity Well Ops SEA Pty Ltd. (“WOSEA”). WOSEA is a subsea well intervention and engineering services company located in Perth, Australia. Under the terms of the purchase agreement, we had an option to purchase the remaining 42% of the entity for approximately $10.1 million. On July 1, 2007, we exercised this option and now own 100% of the entity. In addition, the agreement with the existing shareholders provides for an earnout period of five years from the closing date for the purchase of the remaining 42% of WOSEA. If during this five-year period WOSEA achieves certain financial performance objectives, the shareholders will be entitled to additional consideration of approximately $4.6 million. This purchase was accounted for as a business combination with the acquisition price allocated to the assets acquired and liabilities assumed based upon their estimated fair value, with the excess being recorded as goodwill. The following table summarizes the preliminary estimated fair values of the assets acquired and liabilities assumed at July 1, 2007 (in thousands):

          The allocation of the purchase price was based upon preliminary valuations. Estimates and assumptions are subject to change upon the receipt and management’s review of the final valuations. The primary areas of the purchase price allocation that are not yet finalized relate to the valuation of

certain equipment. The final valuation of net assets is expected to be completed no later than one year from the acquisition date. Pro forma combined operating results for the three months ended March 31, 2007 are not provided because the pre-acquisition results related to WOSEA were immaterial to the historical results of the Company.

          We follow the successful efforts method of accounting for our interests in oil and gas properties. Under the successful efforts method, the costs of successful wells and leases containing productive reserves are capitalized. Costs incurred to drill and equip development wells, including unsuccessful development wells, are capitalized. Costs incurred relating to unsuccessful exploratory wells are expensed in the period in which the drilling is determined to be unsuccessful.

          As of March 31, 2008, we capitalized approximately $19.3 million of exploratory drilling costs associated with ongoing exploration and/or appraisal activities. Such capitalized costs may be charged against earnings in future periods if management determines that commercial quantities of hydrocarbons have not been discovered or that future appraisal drilling or development activities are not likely to occur. The following table provides a detail of our capitalized exploratory project costs at March 31, 2008 and December 31, 2007 (in thousands):

          As of March 31, 2008, the exploratory well costs for Castleton and Huey had been capitalized for longer than one year. We are not the operator of Castleton.

          The following table reflects net changes in suspended exploratory well costs during the three months ended March 31, 2008 (in thousands):

          Further, the following table details the components of exploration expense for the three months ended March 31, 2008 and 2007 (in thousands):

          On March 31, 2008, we agreed to sell 30% working interest in the Bushwood discoveries (Garden Banks Blocks 463, 506 and 507) and other Outer Continental Shelf oil and gas properties (East Cameron blocks 371 and 381), in two separate transactions to affiliates of a private independent oil and gas company for total cash consideration of approximately $165 million (which includes the purchasers’ share

of past capital expenditures on these fields), and additional cash payments of up to $20 million based upon certain field production milestones. The new co-owners will also pay their pro rata share of all future capital expenditures related to the exploration and development of these fields. The assumption of certain decommissioning liabilities will be satisfied on a pro rata share basis between the new co-owners and us. On March 31, 2008, we received $110 million related to the sale of a 20% working interest and we accrued an additional $11 million of receivables related to the reimbursement of capital expenditures on these fields from the purchasers. Proceeds from the sale of these properties were used to pay down our outstanding revolving loans in April 2008. As a result of the 20% sale, we recognized a pre-tax gain of $61.1 million. The remaining 10% was closed and funded in April 2008.

          As a result of our unsuccessful development well in January 2008 on Devil’s Island (Garden Banks 344), we recognized impairment expense of $14.3 million in the first quarter of 2008. Costs incurred as of December 31, 2007 of $20.9 million related to this well were charged to income in 2007 and were included in the 2007 impairment expense.

          Other current assets consisted of the following as of March 31, 2008 and December 31, 2007:

          Other assets, net, consisted of the following as of March 31, 2008 and December 31, 2007:

          Accrued liabilities consisted of the following as of March 31, 2008 and December 31, 2007:

          As of March 31, 2008, we have the following material investments that are accounted for under the equity method of accounting:

          On December 21, 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (“Senior Unsecured Notes”). Interest on the Senior Unsecured Notes is payable semiannually in arrears on each January 15 and July 15, commencing July 15, 2008. The Senior Unsecured Notes are fully and unconditionally guaranteed by substantially all of our existing restricted domestic subsidiaries, except for CDI and Cal Dive I-Title XI, Inc. In addition, any future restricted domestic subsidiaries that guarantee any of our and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes. CDI, the subsidiaries of CDI, Cal Dive I -Title XI, Inc., and our foreign subsidiaries are

not guarantors. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).

          On July 3, 2006, which was subsequently amended on November 29, 2007, we entered into a Credit Agreement (the “Credit Agreement”) under which we borrowed $835 million in a term loan (the “Term Loan”) and may borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”). In addition, the full amount of the Revolving Credit Facility may be used for issuances of letters of credit. The proceeds from the Term Loan were used to fund the cash portion of the Remington Oil and Gas Corporation (“Remington”) acquisition.

          The Term Loan matures on July 1, 2013 and is subject to quarterly scheduled principal payments. As a result of a $400 million prepayment made in December 2007, the quarterly scheduled principal payment was reduced from $2.1 million to $1.1 million. The Revolving Loans mature on July 1, 2011. At March 31, 2008, there were $116.9 million available under the Revolving Loans (including $31.6 million of unsecured letters of credit).

          The Term Loan currently bears interest at the one-, three- or six-month LIBOR at our election plus a 2.00% margin. Our average interest rate on the Term Loan for the three months ended March 31, 2008 and 2007 was approximately 6.6% and 7.3%, respectively, including the effects of our interest rate swaps (see below). The Revolving Loans bear interest based on one-, three- or six-month LIBOR at our election plus a margin ranging from 1.00% to 2.25%. Margins on the Revolving Loans will fluctuate in relation to the consolidated leverage ratio as provided in the Credit Agreement. Our average interest rate on the Revolving Loans for the three months ended March 31, 2008 was approximately 6.2%.

          As the rates for our Term Loan are subject to market influences and will vary over the term of the credit agreement, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments for our Term Loan. See detailed discussions related to these swaps in “—Note 11 — Hedging Activities” below.

          In December 2007, CDI replaced its five-year $250 million revolving credit facility by entering into a secured credit facility consisting of a $375 million term loan and a $300 million revolving credit facility. Both the term loan and the revolving loans mature on December 11, 2012. Loans under this facility are non-recourse to Helix. The term loan and the revolving loans may consist of loans bearing interest in relation to the Federal Funds Rate or to Bank of America’s base rate, known as Base Rate Loans, and loans bearing interest in relation to a LIBOR rate, known as Eurodollar Rate Loans, in each case plus an applicable margin. The margins on the revolving loans range from 0.75% to 1.50% on Base Rate Loans and 1.75% to 2.50% on Eurodollar Rate Loans. The margins on the term loan are 1.25% on Base Rate Loans and 2.25% on Eurodollar Rate Loans. If a default exists, the interest rates may be increased. During the three months ended March 31, 2008, CDI’s average interest rate was 7.1%.

          CDI used the $375 million proceeds from their term loan to fund the cash portion of its merger consideration in connection with CDI’s acquisition of Horizon and to retire Horizon’s existing debt. The term loan requires quarterly principal payments of $20 million beginning June 20, 2008. At March 31, 2008 there was $293.6 million available under the revolving credit facility (including $6.4 million of unsecured letters of credit).

          On March 30, 2005, we issued $300 million of our Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers. The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.

          The Convertible Senior Notes can be converted prior to the stated maturity under certain triggering events specified in the indenture governing the Convertible Senior Notes. To the extent we do not have long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. During the first quarter of 2008, no conversion triggers were met.

          Approximately 706,000 and 179,000 shares underlying the Convertible Senior Notes were included in the calculation of diluted earnings per share for the three months ended March 31, 2008 and 2007, respectively, because our average share price for the respective periods was above the conversion price of approximately $32.14 per share. In the event our average share price exceeds the conversion price, there would be a premium, payable in shares of common stock, in addition to the principal amount, which is paid in cash, and such 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 13,303,770.

          At March 31, 2008 and December 31, 2007, $125.5 million and $127.5 million was outstanding on our long-term financing for construction of the Q4000. This U.S. government guaranteed financing (“MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 which is administered by the Maritime Administration. 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 theQ4000, with us 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, we 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 Senior Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes, MARAD Debt agreements and CDI’s credit facility, 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 March 31, 2008, we were in compliance with these covenants and restrictions. The Senior Unsecured Notes and Senior Credit Facilities contain provisions that limit our ability to incur certain types of additional indebtedness.

          Deferred financing costs of $38.6 million and $39.3 million are included in other assets, net as of March 31, 2008 and December 31, 2007, respectively, and are being amortized over the life of the respective loan agreements.

          Scheduled maturities of long-term debt and capital lease obligations outstanding as of March 31, 2008 were as follows (in thousands):

     We had unsecured letters of credit outstanding at March 31, 2008 totaling approximately $38.0 million. These letters of credit primarily guarantee various contract bidding, contractual performance and insurance activities and shipyard commitments. The following table details our interest expense and capitalized interest for the three months ended March 31, 2008 and 2007 (in thousands):

     The effective tax rate for the three months ended March 31, 2008 and March 31, 2007 was 36.6% and 33.8%, respectively. The effective tax rate for the first quarter of 2008 increased as a result of the additional deferred tax expense recorded as a result of the increase in the equity earnings of CDI in excess of our tax basis in CDI. This increase was partially offset by the benefit derived from the Internal Revenue Code section 199 manufacturing deduction as it primarily related to oil and gas production and the effect of lower tax rates in certain foreign jurisdictions. The effective tax rate for the three months ended March 31, 2007 was favorably impacted by the effect of Internal Revenue Code Section 199 and the effects of lower tax rates in foreign jurisdictions.

     We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain; therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions. See detailed discussion related to a tax assessment in “—Note 19 – Commitments and Contingencies” below.

     We are currently exposed to market risk in three major areas: commodity prices, interest rates and foreign currency exchange rates. Our risk management activities include the use of derivative financial instruments to hedge the impact of market price risk exposures primarily related to our oil and gas production, variable interest rate exposure and foreign currency exchange rate exposure, as well as non-derivative forward sale contracts to reduce commodity price risk on future sales of hydrocarbons. All derivatives are reflected in our balance sheet at fair value unless otherwise noted.

     We have entered into various cash flow hedging costless collar contracts to stabilize cash flows relating to a portion of our expected oil and gas production. All of these qualify for hedge accounting. The aggregate fair value of the hedge instruments was a net liability of $13.6 million and $8.1 million as of March 31, 2008 and December 31, 2007, respectively. We recorded unrealized losses of approximately $3.5 million and $8.3 million, net of tax benefit of $1.9 million and $4.5 million during the three months ended March 31, 2008 and 2007, respectively, in accumulated other comprehensive income, a component of shareholders’ equity, as these hedges were highly effective. During the three months ended March 31, 2008, we reclassified approximately $4.0 million of losses from other comprehensive income to net revenues upon the sale of the related oil and gas production. For the three months ended March 31, 2007, we reclassified approximately $2.1 million of gains from other comprehensive income to net revenues.

     As of March 31, 2008, we had the following volumes under derivative and forward sale contracts related to our oil and gas producing activities totaling 2,535 MBbl of oil and 34,156,600 MMbtu of natural gas:

     Subsequent to March 31, 2008, we entered into two cash flow hedging swap agreements. The first contract covers 115 MBbl total at a price of $107.85 for the period from July to September 2008. The second contract covers 125 MBbl at a price of $106.25 for the period from October to December 2008. Changes in NYMEX oil and gas strip prices would, assuming all other things being equal, cause the fair value of these instruments to increase or decrease inversely to the change in NYMEX prices.

As the rates for our Term Loan are subject to market influences and will vary over the term of the Credit Agreement, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan. The interest rate swaps were effective October 3, 2006. These interest rate swaps qualified for hedge accounting. See “–Note 9 – Long-Term Debt” above for a detailed discussion of our Term Loan. On December 21, 2007, a prepayment made to a hedged portion of our Term Loan brought the balance of that portion below the amount hedged by interest rate swaps. As a result, the interest rate swaps no longer qualified for hedge accounting treatment under FASB Statement No. 133, Accounting for Derivative Instruments and Hedging Activities, (“SFAS No. 133”). On January 31, 2008, we re-designated these swaps as cash flow hedges with respect to our outstanding LIBOR-based debt. During the three months ended March 31, 2008, we recognized $1.8 million of unrealized losses as other expense, net of taxes of $954,000, as a result of the change in fair value of our interest rate swaps from January 1, 2008 to January 31, 2008, the date of re-designation. Changes in fair value from February 1, 2008 through March 31, 2008 were recognized in other comprehensive income, in accordance with SFAS No. 133. No ineffectiveness was recognized during the three months ended March 31, 2007. As of March 31, 2008 and December 31, 2007, the aggregate fair value of the derivative instruments was a net liability of $8.4 million and $4.7 million, respectively.

     Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar. In December 2006, we entered into various foreign currency forward purchase contracts to stabilize expected cash outflows relating to a shipyard contract where the contractual payments are denominated in euros. These forward contracts qualify for hedge accounting. Under the forward contracts, we hedged €11.0 million at an exchange rate of 1.3326 that was settled in December 2007. In August 2007, we entered into a €14.0 million foreign currency forward contract at an exchange rate of 1.3595 to be settled in May 2008.

     In February 2008, we entered into various foreign currency forward purchase contracts to stabilize expected cash outflows relating to certain vessel charters denominated in British pounds. These forward contracts qualify for hedge accounting. The following table provides details related to the remaining forward contracts at March 31, 2008 (amount in thousands):

          The aggregate fair value of the foreign currency forwards described above was a net asset of $3.2 million and $1.4 million as of March 31, 2008 and December 31, 2007, respectively. For the three months ended March 31, 2008 and 2007, we recorded unrealized gains of approximately $1.2 million and $331,000, respectively, net of tax expense of $628,000 and $79,000, respectively, in accumulated other comprehensive income, a component of shareholders’ equity.

          In September 2006, the FASB issued Statement No. 157, Fair Value Measurements(“SFAS No. 157”). SFAS No. 157 was originally effective for financial statements issued for fiscal years beginning after November 15, 2007 and interim periods within those fiscal years. The FASB agreed to defer the effective date of SFAS No. 157 for all nonfinancial assets and liabilities, except those that are recognized or disclosed at fair value in the financial statements on a recurring basis. We adopted the provisions of SFAS No. 157 on January 1, 2008 for assets and liabilities not subject to the deferral and expect to adopt this standard for all other assets and liabilities by January 1, 2009. The adoption of SFAS No. 157 had immaterial impact on our results of operations, financial condition and liquidity.

          SFAS No. 157, among other things, defines fair value, establishes a consistent framework for measuring fair value and expands disclosure for each major asset and liability category measured at fair value on either a recurring or nonrecurring basis. SFAS No. 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset, or paid to transfer a liability, in an orderly transaction between market participants. SFAS No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

          Assets and liabilities measured at fair value are based on one or more of three valuation techniques noted in SFAS No. 157. The valuation techniques are as follows:

          The following table provides additional information related to assets and liabilities measured at fair value on a recurring basis at March 31, 2008 (in thousands):

          The components of total comprehensive income for the three months ended March 31, 2008 and 2007 were as follows (in thousands):

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

          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 that 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 EPS amounts for the three months ended March 31, 2008 and 2007 were as follows (in thousands):

          There were no antidilutive stock options in the three months ended March 31, 2008 and 2007 as the option strike price was below the average market price for the applicable periods. Net income for the

diluted EPS calculation for the three months ended March 31, 2008 and 2007 was adjusted to add back the preferred stock dividends as if the convertible preferred stock were converted into 3.6 million shares of common stock.

          We have three stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”), the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”) and the 1998 Employee Stock Purchase Plan, as amended (the “ESPP”). In addition, CDI has a stock-based compensation plan, the 2006 Long-Term Incentive Plan (the “CDI Incentive Plan”) and an Employee Stock Purchase Plan (the “CDI ESPP”) available only to the employees of CDI and its subsidiaries.

          During the first three months ended March 31, 2008, we made the following restricted share or restricted stock unit grants to certain key executives, selected management employees and non-employee members of the board of directors under the 2005 incentive plan:

There were no stock option grants in the three months ended March 31, 2008 and 2007.

          Compensation cost is recognized over the respective vesting periods on a straight-line basis. For the three months ended March 31, 2008, $537,000 was recognized as compensation expense related to stock options (of which $322,000 was related to the acceleration of unvested options per the separation agreement between the Company and our former Chief Executive Officer, Martin Ferron). For the three months ended March 31, 2008, $6.9 million was recognized as compensation expense related to restricted shares (of which $1.1 million of expense was related to the CDI Incentive Plan and $3.1 million was related to the accelerated vesting of restricted shares per the separation agreement between the Company and our former Chief Executive Officer, Martin Ferron). For the three months ended March 31, 2007, $3.0 million was recognized as compensation expense related to restricted shares (of which $503,000 of expense was related to the CDI Incentive Plan).

          Effective May 12, 1998, we adopted a qualified, non-compensatory employee stock purchase plan, which allows employees to acquire shares of our common stock through payroll deductions over a six-month period. The purchase price is equal to 85% of the fair market value of the common stock on either the first or last day of the subscription period, whichever is lower. Purchases under the plan are limited to the lesser of 10% of an employee’s base salary or $25,000 of our stock value. In January 2008 and 2007, we issued 46,152 and 109,754 shares, respectively, of our common stock to our employees under the ESPP, which increased the number of shares of our outstanding common stock. In January 2007, we subsequently repurchased approximately the same number of shares of our common stock in the open market at $29.94 per share and reduced the number of shares of our outstanding common stock. For the three months ended March 31, 2008, we recognized $585,000 of compensation expense related to the ESPP and the CDI ESPP (of which $278,000 of expense was related to the CDI ESPP that

became effective third quarter 2007). For the three months ended March 31, 2007, we recognized $500,000 of compensation expense related to the ESPP.

          Our operations are conducted through two lines of business: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into three reportable segments in accordance with SFAS No. 131: Contracting Services, Shelf Contracting and Production Facilities. As a result, our reportable segments consist of the following: Contracting Services, Shelf Contracting, Production Facilities, and Oil and Gas. The Contracting Services segment includes services such as deepwater pipelay, well operations, and reservoir and well technology services. The Shelf Contracting segment are the assets of Cal Dive, which consists of assets deployed primarily for diving-related activities and shallow water construction. All material intercompany transactions among the segments have been eliminated in our consolidated results of operations.

          We evaluate our performance based on income before income taxes of each segment. Segment assets are comprised of all assets attributable to the reportable segment. The majority of our Production Facilities segment is accounted for under the equity method of accounting. Our investment in Kommandor LLC, a Delaware limited liability company, was consolidated in accordance with FASB Interpretation No. 46, Consolidation of Variable Interest Entities (“FIN 46”) and is included in our Production Facilities segment.

          Intercompany segment revenues during the three months ended March 31, 2008 and 2007 were as follows:

          Intercompany segment profits during the three months ended March 31, 2008 and 2007 were as follows:

          During the three months ended March 31, 2008, we derived $54.6 million of our revenues from our operations in the United Kingdom, utilizing $328.2 million of our total assets in this region. During the three months ended March 31, 2007, we derived $40.6 million of our revenues from our operations in the United Kingdom, utilizing $242.9 million of our total assets in this region. The majority of the remaining revenues were generated in the U.S. Gulf of Mexico.

          Martin Ferron resigned as our President and Chief Executive Officer effective February 4, 2008. Concurrently, Mr. Ferron resigned from our Board of Directors. Mr. Ferron remained employed by us through February 18, 2008, after which his employment terminated. At the time of Mr. Ferron’s resignation, Owen Kratz, who served as Executive Chairman of Helix, resumed the role and assumed the duties of the President and Chief Executive Officer, and was subsequently elected as President and Chief Executive Officer of Helix. In February 2008, we recognized approximately $5.4 million of compensation expense related to the separation agreement between us and Mr. Ferron.

          In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect of Kerr-McGee. 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 Helix senior management, in exchange for a revenue interest that is an overriding royalty interest of 25% of Helix’s 20% working interest. Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 73% of the partnership. Another executive officer of the Company, A. Wade Pursell, our Executive Vice President and Chief Financial Officer, owns approximately 1.33% of the partnership. In 2000, OKCD also awarded Class B limited partnership interests to key Helix employees. Production began in December 2003. Payments to OKCD from us totaled $5.5 million and $6.0 million in the three months ended March 31, 2008 and 2007, respectively.

          We are converting the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. Total conversion costs are estimated to range between $165 million and $185 million, of which approximately $102 million had been incurred, with an additional $29 million committed, at March 31, 2008. The Caesar is expected to be completed in the third quarter of 2008. In addition, we are upgrading the Q4000 to include drilling capability by adding a modular-based drilling system, and have performed other significant upgrades on the vessel. The total cost for all of these activities related to the Q4000 is estimated to range between $160 million and $165 million, of which approximately $117 million had been incurred, with an additional $23 million committed at March 31, 2008. The Q4000 is expected to be completed in second quarter 2008.

          We are also constructing the Well Enhancer. Total construction cost for the Well Enhancer is expected to range between $190 million to $200 million multi-service dynamically positioned dive support/well intervention vessel that will be capable of working in the North Sea and West of Shetlands to support our expected growth in that region. We expect the Well Enhancer to join our fleet in 2009. At March 31, 2008, we had incurred approximately $104 million, with an additional $68 million committed to this project.

          Further, we, along with Kommandor RØMØ, a Danish corporation, formed a joint venture called Kommandor LLC to convert a ferry vessel into a floating production unit to be named the Helix Producer I (the “Vessel”). Total cost of the ferry and the conversion is estimated to range between $130 million and $140 million which will be funded through equity contributions and project financing. Each of the partners will guarantee the project financing on a several basis in relation to their respective ownership interest in Kommandor LLC. Total equity contributions and indebtedness guarantees provided by us and Kommandor RØMØ are expected to be $87.5 million and $42.5 million, respectively. We have agreed to provide all interim construction financing to the joint venture on terms that would equal an arms length financing transaction. Total borrowings will be approximately $45 million, and will be repaid with the proceeds of the permanent financing facility described below. Upon completion of the conversion, scheduled for third quarter 2008, we will charter the Vessel from Kommandor LLC, and will install, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the Vessel for use on our Phoenix field. The cost of these additional facilities is approximately $130 million. As of March 31, 2008, we have incurred approximately $180 million of costs related to the purchase of the Vessel ($20 million), conversion of the Vessel and construction of the additional facilities, with an additional $68 million committed. Kommandor LLC qualified as a variable interest entity under FIN 46. We determined that we were the primary beneficiary of Kommandor LLC and thus have consolidated the financial results of Kommandor LLC as of March 31, 2008 in our Production Facilities segment. Kommandor LLC has been a development stage enterprise since its formation in October 2006.

          On June 19, 2007, Kommandor LLC entered into a term loan agreement (“Nordea Loan Agreement”) with Nordea Bank Norge ASA. Pursuant to the Nordea Loan Agreement, the lenders will make available to Kommandor up to $45.0 million pursuant to a secured term loan facility. Kommandor will use all amounts borrowed under the facility to repay its existing subordinated indebtedness for the long-term financing of the Vessel and to fund expenses and fees related to the conversion of such Vessel to operate as a floating production unit. Kommandor expects this borrowing to occur in the third quarter of 2008 upon the delivery of the Vessel after its conversion, and at such time, in accordance with the provisions of FIN 46, the entire obligation will be included in our consolidated balance sheet. The funding of the amount set forth in the draw request is subject to certain customary conditions.

          Our projected capital expenditures on certain projects have increased as compared to the initially budgeted amounts due primarily to scope changes, escalating costs for certain materials and services due to increasing demand and the weakening of the U.S. dollar with respect to foreign denominated contracts. In addition, as of March 31, 2008, we have also committed approximately $180 million in

additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties.

          We are involved in various legal proceedings, primarily involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.

          On December 2, 2005, we received an order from the U.S. Department of the Interior Minerals Management Service (“MMS”) that the price thresholds for both oil and gas were exceeded for 2004 production and that royalties are due on such production notwithstanding the provisions of the Outer Continental Shelf Deep Water Royalty Relief Act of 2005 (“DWRRA”), which was intended to stimulate exploration and production of oil and natural gas in the deepwater Gulf of Mexico by providing relief from the obligation to pay royalties on certain federal leases up to certain specified production volumes. Our only leases affected by this order are the Gunnison leases. On May 2, 2006, the MMS issued an order that superseded and replaced the December 2005 order, and claimed that royalties on gas production are due for 2003 in addition to oil and gas production in 2004. The May 2006 order also seeks interest on all royalties allegedly due. We filed a timely notice of appeal with respect to both MMS orders. Other operators in the deepwater Gulf of Mexico who have received notices similar to ours are seeking royalty relief under the DWRRA, including Kerr-McGee, the operator of Gunnison. In March of 2006, Kerr-McGee filed a lawsuit in federal district court challenging the enforceability of price thresholds in certain deepwater Gulf of Mexico leases, including ours. On October 30, 2007, the federal district court in the Kerr-McGee case entered judgment in favor of Kerr-McGee and held that the Department of the Interior exceeded its authority by including the price thresholds in the subject leases. The government filed a notice of appeal of that decision on December 21, 2007. We do not anticipate that the MMS director will issue decisions in our or the other companies’ administrative appeals until the Kerr-McGee litigation has been resolved in a final decision. As a result of our dispute with the MMS, we have recorded reserves for the disputed royalties (and any other royalties that may be claimed from the Gunnison leases), plus interest at 5%, for our portion of the Gunnison related MMS claim. The total reserved amount at March 31, 2008 and December 31, 2007 was approximately $58.5 million and $55.1 million, respectively and was included in Other Long Term Liabilities in the accompanying condensed consolidated balance sheet included herein. At this time, it is not anticipated that any penalties would be assessed if we are unsuccessful in our appeal.

          During the fourth quarter of 2006, Horizon received a tax assessment from the Servicio de Administracion Tributaria (“SAT”), the Mexican taxing authority, for approximately $23 million related to fiscal 2001, including penalties, interest and monetary correction. The SAT’s assessment claims unpaid taxes related to services performed among the Horizon subsidiaries that CDI acquired at the time it acquired Horizon. CDI believes under the Mexico and United States double taxation treaty that these services are not taxable and that the tax assessment itself is invalid. On February 14, 2008, CDI received notice from the SAT upholding the original assessment. On April 21, 2008, CDI filed a petition in Mexico tax court disputing the assessment. We believe that CDI’s position is supported by law and CDI intends to vigorously defend its position. However, the ultimate outcome of this litigation and CDI’s potential liability from this assessment, if any, cannot be determined at this time. Nonetheless, an unfavorable outcome with respect to the Mexico tax assessment could have a material adverse effect on our and CDI’s financial position and results of operations. Horizon’s 2002 through 2007 tax years remain subject to examination by the appropriate governmental agencies for Mexico tax purposes, with 2002 through 2004 currently under audit.

          In March 2008, the FASB issued Statement No. 161, Disclosures about Derivative Instruments and Hedging Activities, an amendment of FASB Statement No. 133 (“SFAS No. 161”). SFAS 161 applies to all derivative instruments and related hedged items accounted for under FASB Statement No. 133,

Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). SFAS No. 161 asks entities to provide qualitative disclosures about the objectives and strategies for using derivatives, quantitative data about the fair value of and gains and losses on derivative contracts, and details of credit-risk-related contingent features in their hedged positions. The standard is effective for financial statements issued for fiscal years and interim periods beginning after November 15, 2008, with early application encouraged, but not required. We are currently evaluating the impact of this statement on our disclosures.

          The payment of obligations under the Senior Unsecured Notes is guaranteed by all of our restricted domestic subsidiaries (“Subsidiary Guarantors”) except for Cal Dive and its subsidiaries and Cal Dive I-Title XI, Inc. Each of these Subsidiary Guarantors is included in our consolidated financial statements and has fully and unconditionally guaranteed the Senior Unsecured Notes on a joint and several basis. As a result of these guarantee arrangements, we are required to present the following condensed consolidating financial information. The accompanying guarantor financial information is presented on the equity method of accounting for all periods presented. Under this method, investments in subsidiaries are recorded at cost and adjusted for our share in the subsidiaries’ cumulative results of operations, capital contributions and distributions and other changes in equity. Elimination entries related primarily to the elimination of investments in subsidiaries and associated intercompany balances and transactions.