e10vq
Table of Contents

 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
     
þ   Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the quarterly period ended March 31, 2008
or
     
o   Transition report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
For the transition period from                     to                    
Commission File Number 001-32936
(HELIX LOGO)
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
     
Minnesota   95—3409686
(State or other jurisdiction   (I.R.S. Employer
of incorporation or organization)   Identification No.)
     
400 North Sam Houston Parkway East    
Suite 400   77060
Houston, Texas   (Zip Code)
(Address of principal executive offices)    
(281) 618—0400
(Registrant’s telephone number, including area code)
NOT APPLICABLE
(Former name, former address and former fiscal year, if changed since last report)
     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.
Yes þ       No o
     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):
             
Large accelerated filer þ    Accelerated filer o    Non-accelerated filer   o
(Do not check if a smaller reporting company)
  Smaller reporting company 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 þ
As of April 30, 2008, 91,664,674 shares of common stock were outstanding.
 
 

 


 

TABLE OF CONTENTS
             
        PAGE  
PART I.          
   
 
       
Item 1.          
   
 
       
        1  
   
 
       
        2  
   
 
       
        3  
   
 
       
        4  
   
 
       
Item 2.       28  
   
 
       
Item 3.       39  
   
 
       
Item 4.       40  
   
 
       
PART II.          
   
 
       
Item 1.       42  
   
 
       
Item 2.       42  
   
 
       
Item 6.       42  
   
 
       
        43  
   
 
       
        44  
 Acknowledgement Letter from Ernst & Young LLP
 Certification of CEO Pursuant to Rule 13a-14(a)
 Certification of CFO Pursuant to Rule 13a-14(a)
 Certification of CEO & CFO Pursuant to Section 906
 Report of Ernst & Young LLP

 


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PART I. FINANCIAL INFORMATION
Item 1. Financial Statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
                 
    March 31,     December 31,  
    2008     2007  
    (Unaudited)          
ASSETS
Current assets:
               
Cash and cash equivalents
  $ 176,119     $ 89,555  
Accounts receivable —
               
Trade, net of allowance for uncollectible accounts of $4,172 and $2,874, respectively
    330,815       447,502  
Unbilled revenue
    20,519       10,715  
Costs in excess of billing
    52,674       53,915  
Other current assets
    122,720       125,582  
 
           
Total current assets
    702,847       727,269  
 
           
Property and equipment
    4,328,953       4,088,561  
Less — accumulated depreciation
    (934,183 )     (843,873 )
 
           
 
    3,394,770       3,244,688  
 
               
Other assets:
               
Equity investments
    207,579       213,429  
Goodwill
    1,087,904       1,089,758  
Other assets, net
    194,870       177,209  
 
           
 
  $ 5,587,970     $ 5,452,353  
 
           
 
               
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
               
Accounts payable
  $ 321,595     $ 382,767  
Accrued liabilities
    215,092       221,366  
Income tax payable
    26,849        
Current maturities of long-term debt
    54,301       74,846  
 
           
Total current liabilities
    617,837       678,979  
 
           
Long-term debt
    1,835,878       1,725,541  
Deferred income taxes
    626,946       625,508  
Decommissioning liabilities
    192,727       193,650  
Other long-term liabilities
    66,026       63,183  
 
           
Total liabilities
    3,339,414       3,286,861  
 
               
Minority interest
    267,978       263,926  
Convertible preferred stock
    55,000       55,000  
 
               
Commitments and contingencies
           
Shareholders’ equity:
               
 
               
Common stock, no par, 240,000 shares authorized, 91,662 and 91,385 shares issued, respectively
    762,075       755,758  
Retained earnings
    1,143,881       1,069,546  
Accumulated other comprehensive income
    19,622       21,262  
 
           
Total shareholders’ equity
    1,925,578       1,846,566  
 
           
 
  $ 5,587,970     $ 5,452,353  
 
           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
(in thousands, except per share amounts)
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Net revenues:
               
Contracting services
  $ 279,686     $ 265,088  
Oil and gas
    171,051       130,967  
 
           
 
    450,737       396,055  
 
           
 
               
Cost of sales:
               
Contracting services
    220,186       178,055  
Oil and gas
    109,672       82,385  
 
           
 
    329,858       260,440  
 
           
 
               
Gross profit
    120,879       135,615  
 
               
Gain on sale of assets, net
    61,113        
Selling and administrative expenses
    47,784       30,600  
 
           
Income from operations
    134,208       105,015  
Equity in earnings of investments
    10,923       6,104  
Net interest expense and other
    26,046       13,012  
 
           
Income before income taxes
    119,085       98,107  
Provision for income taxes
    43,632       33,123  
Minority interest
    237       8,219  
 
           
Net income
    75,216       56,765  
Preferred stock dividends
    881       945  
 
           
Net income applicable to common shareholders
  $ 74,335     $ 55,820  
 
           
 
               
Earnings per common share:
               
Basic
  $ 0.82     $ 0.62  
 
           
Diluted
  $ 0.79     $ 0.60  
 
           
 
               
Weighted average common shares outstanding:
               
Basic
    90,413       89,994  
 
           
Diluted
    95,186       94,312  
 
           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
(in thousands)
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Cash flows from operating activities:
               
Net income
  $ 75,216     $ 56,765  
Adjustments to reconcile net income to net cash provided by (used in) operating activities —
               
Depreciation and amortization
    85,133       69,885  
Asset impairment charge
    16,723        
Dry hole expense
    (52 )     126  
Equity in earnings of investments, net of distributions
    (19 )      
Amortization of deferred financing costs
    953       728  
Stock compensation expense
    8,079       3,744  
Deferred income taxes
    6,323       15,992  
Excess tax benefit from stock-based compensation
    (629 )     (187 )
Gain on sale of assets
    (61,113 )      
Minority interest
    237       8,219  
Changes in operating assets and liabilities:
               
Accounts receivable, net
    111,726       (14,738 )
Other current assets
    (5,071 )     10  
Income tax payable
    36,343       (137,259 )
Accounts payable and accrued liabilities
    (116,073 )     (46,734 )
Other noncurrent, net
    (32,210 )     (19,605 )
 
           
Net cash provided by (used in) operating activities
    125,566       (63,054 )
 
           
 
               
Cash flows from investing activities:
               
Capital expenditures
    (241,550 )     (181,899 )
Acquisition of businesses, net of cash acquired
          (79 )
Sale of short-term investments
          265,820  
Investments in equity investments
    (207 )     (10,294 )
Distributions from equity investments, net
    5,995       4,896  
Increase in restricted cash
    (232 )     (266 )
Proceeds from sales of property
    110,147       (383 )
 
           
Net cash (used in) provided by investing activities
    (125,847 )     77,795  
 
           
 
               
Cash flows from financing activities:
               
Repayment of Helix Term Notes
    (1,082 )     (2,100 )
Borrowings on Helix Revolver
    318,500        
Repayments on Helix Revolver
    (185,000 )      
Repayment of MARAD borrowings
    (1,982 )     (1,888 )
Repayments on CDI Revolver
          (29,000 )
Repayments on CDI Term Note
    (40,000 )      
Deferred financing costs
    (409 )     (36 )
Capital lease payments
          (622 )
Preferred stock dividends paid
    (881 )     (945 )
Repurchase of common stock
    (3,309 )     (3,956 )
Excess tax benefit from stock-based compensation
    629       187  
Exercise of stock options, net
    321       376  
 
           
Net cash provided by (used in) financing activities
    86,787       (37,984 )
 
           
 
               
Effect of exchange rate changes on cash and cash equivalents
    58       113  
 
           
Net increase (decrease) in cash and cash equivalents
    86,564       (23,130 )
Cash and cash equivalents:
               
Balance, beginning of year
    89,555       206,264  
 
           
Balance, end of period
  $ 176,119     $ 183,134  
 
           
The accompanying notes are an integral part of these condensed consolidated financial statements.

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 — Basis of Presentation
          The accompanying condensed consolidated financial statements include the accounts of 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.
Note 2 — Company Overview
          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.
Contracting Services Operations
          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

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assets of Cal Dive International, Inc. (“Cal Dive” or “CDI”). Our ownership in CDI was approximately 58.2% as of March 31, 2008.
Oil and Gas Operations
          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.
Note 3 — Statement of Cash Flow Information
          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):
                 
    Three Months Ended
    March 31,
    2008   2007
Interest paid
  $ 17,019     $ 25,887  
Income taxes paid
  $ 966     $ 154,388  
          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.
Note 4 — Acquisition of Horizon Offshore, Inc.
          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

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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):
         
Cash
  $ 170,806  
Other current assets
    158,532  
Property and equipment
    351,155  
Goodwill
    259,183  
Intangible assets(1)
    9,510  
Other long-term assets
    15,270  
 
     
Total assets acquired
  $ 964,456  
 
     
 
       
Current liabilities
  $ 178,853  
Long-term debt
    87,641  
Deferred income taxes
    67,826  
Other non-current liabilities
    100  
 
     
Total liabilities assumed
  $ 334,420  
 
     
 
       
Net assets acquired
  $ 630,036  
 
     
 
(1)   The intangible assets relate to the fair value of contract backlog, customer relationships and non-compete agreements between CDI and certain members of Horizon’s senior management as follows (amounts in thousands):
                 
            Amortization  
    Fair Value     Period  
Customer relationships
  $ 3,060     5 years  
Contract backlog
    2,960     1.5 years  
Non-compete
    3,000     1 year    
Trade name
    490     9 years  
 
             
Total
  $ 9,510          
 
             
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.

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          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):
         
    Three Months
    Ended
    March 31, 2007
Net revenues
  $ 478,622  
Income before income taxes
    96,078  
Net income
    51,732  
Net income applicable to common shareholders
    50,787  
Earnings per common share:
       
Basic
  $ 0.56  
Diluted
  $ 0.54  
          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.
Note 5 — Well Ops SEA Pty Ltd. Acquisition
          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):
         
Cash and cash equivalents
  $ 2,631  
Other current assets
    4,279  
Property and equipment
    12,277  
Goodwill
    8,622  
 
     
Total assets acquired
  $ 27,809  
 
     
 
       
Accounts payable and accrued liabilities
  $ 5,059  
 
     
 
       
Net assets acquired
  $ 22,750  
 
     
          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

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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.
Note 6 — Oil and Gas Properties
          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):
                 
    March 31,     December 31,  
    2008     2007  
Huey
  $ 11,555     $ 11,556  
Castleton (part of Gunnison)
    7,071       7,071  
Other
    658       469  
 
           
Total
  $ 19,284     $ 19,096  
 
           
          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):
         
    2008  
Beginning balance at January 1,
  $ 19,096  
Additions pending the determination of proved reserves
    1,100  
Reclassifications to proved properties
    (964 )
Charged to dry hole expense
    52  
 
     
Ending balance at March 31,
  $ 19,284  
 
     
          Further, the following table details the components of exploration expense for the three months ended March 31, 2008 and 2007 (in thousands):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Delay rental and geological and geophysical costs
  $ 1,940     $ 1,064  
Dry hole expense
    (52 )     126  
 
           
Total exploration expense
  $ 1,888     $ 1,190  
 
           
          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

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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.
Note 7 — Details of Certain Accounts (in thousands)
          Other current assets consisted of the following as of March 31, 2008 and December 31, 2007:
                 
    March 31,     December 31,  
    2008     2007  
Other receivables
  $ 9,080     $ 6,733  
Prepaid insurance
    14,086       21,133  
Other prepaids
    17,651       14,922  
Current deferred tax assets
    11,662       13,810  
Insurance claims to be reimbursed
    8,983       10,173  
Hedging assets
    3,219       1,424  
Gas imbalance
    6,415       6,654  
Inventory
    35,399       29,925  
Income tax receivable
          8,838  
Other
    16,225       11,970  
 
           
 
  $ 122,720     $ 125,582  
 
           
          Other assets, net, consisted of the following as of March 31, 2008 and December 31, 2007:
                 
    March 31,     December 31,  
    2008     2007  
Restricted cash
  $ 35,020     $ 34,788  
Deposits
    10,002       8,417  
Deferred drydock expenses, net
    59,417       47,964  
Deferred financing costs
    38,592       39,290  
Intangible assets with definite lives, net
    20,263       22,216  
Intangible asset with indefinite life
    7,008       7,022  
Contract receivables
    14,831       14,635  
Other
    9,737       2,877  
 
           
 
  $ 194,870     $ 177,209  
 
           

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          Accrued liabilities consisted of the following as of March 31, 2008 and December 31, 2007:
                 
    March 31,     December 31,  
    2008     2007  
Accrued payroll and related benefits
  $ 34,294     $ 50,389  
Royalties payable
    27,894       21,974  
Current decommissioning liability
    23,883       23,829  
Unearned revenue
    1,680       1,140  
Billings in excess of costs
    7,754       20,403  
Insurance claims to be reimbursed
    8,983       14,173  
Accrued interest
    23,343       7,090  
Accrued severance(1)
          14,786  
Deposit
    17,000       13,600  
Hedge liability
    17,882       10,308  
Other
    52,379       43,674  
 
           
 
  $ 215,092     $ 221,366  
 
           
 
(1)   Related to payments made to former Horizon personnel in the first quarter of 2008 as a result of the acquisition by CDI.
Note 8 — Equity Investments
          As of March 31, 2008, we have the following material investments that are accounted for under the equity method of accounting:
    Deepwater Gateway, L.L.C. In June 2002, we, along with Enterprise Products Partners L.P. (“Enterprise”), formed Deepwater Gateway, L.L.C. (“Deepwater Gateway”) (each with a 50% interest) to design, construct, install, own and operate a tension leg platform (“TLP”) production hub primarily for Anadarko Petroleum Corporation’s Marco Polo field in the Deepwater Gulf of Mexico. Our investment in Deepwater Gateway totaled $109.3 million and $112.8 million as of March 31, 2008 and December 31, 2007, respectively, and was included in our Production Facilities segment.
 
    Independence Hub, LLC. In December 2004, we acquired a 20% interest in Independence Hub, LLC (“Independence”), an affiliate of Enterprise. Independence owns the “Independence Hub” platform located in Mississippi Canyon block 920 in a water depth of 8,000 feet. The platform reached mechanical completion in May 2007. As a result, our performance guaranty related to Independence terminated in May 2007 with no further obligations. First production began in July 2007. Our investment in Independence was $93.1 million and $95.7 million as of March 31, 2008 and December 31, 2007, respectively (including capitalized interest of $6.1 million and $6.2 million at March 31, 2008 and December 31, 2007, respectively), and was included in our Production Facilities segment.
Note 9 — Long-Term Debt
Senior Unsecured Notes
          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

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not guarantors. We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our senior secured credit facilities (see below).
Senior Credit Facilities
          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.
Cal Dive International, Inc. Revolving Credit Facility
          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).
Convertible Senior Notes
          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.

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          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.
MARAD Debt
          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 the Q4000, 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.
Other
          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):
                                                                 
    Helix     Helix     CDI     Senior     Convertible                    
    Term     Revolving     Term     Unsecured     Senior     MARAD              
    Loan     Loans     Loan     Notes     Notes     Debt     Other(1)     Total  
Less than one year
  $ 4,326     $     $ 40,000     $     $     $ 4,113     $ 5,862     $ 54,301  
One to two years
    4,326             80,000                   4,318             88,644  
Two to three years
    4,326             80,000                   4,533             88,859  
Three to four years
    4,326       151,500       80,000                   4,760             240,586  
Four to five years
    4,326             55,000                   4,997             64,323  
Over five years
    400,706                   550,000       300,000       102,760             1,353,466  
 
                                               
Long-term debt
    422,336       151,500       335,000       550,000       300,000       125,481       5,862       1,890,179  
Current maturities
    (4,326 )           (40,000 )                 (4,113 )     (5,862 )     (54,301 )
 
                                               
Long-term debt, less current maturities
  $ 418,010     $ 151,500     $ 295,000     $ 550,000     $ 300,000     $ 121,368     $     $ 1,835,878  
 
                                               
 
(1)   Includes $5 million loan provided by Kommandor RØMØ to Kommandor LLC and capital leases of $862,000.

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     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):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Interest expense
  $ 34,882     $ 23,093  
Interest income
    (1,042 )     (4,642 )
Capitalized interest
    (10,971 )     (5,403 )
 
           
     Interest expense, net
  $ 22,869     $ 13,048  
 
           
Note 10 – Income Taxes
     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.
Note 11 – Hedging Activities
     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.
Commodity Hedges
     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.

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     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:
                         
            Average   Weighted Average
Production Period   Instrument Type   Monthly Volumes   Price
Crude Oil:
                       
   April 2008 – December 2008
  Collar   40 MBbl   $ 57.50 — $78.04  
   April 2008 – December 2009
  Forward Sale   103.6 MBbl   $ 71.86  
 
                       
Natural Gas:
                       
   April 2008 – December 2008
  Collar   550,000 MMBtu   $ 7.23 — $9.77  
   April 2008 – December 2009
  Forward Sale   1,390,790 MMBtu   $ 8.24  
     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.
Interest Rate Hedge
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.
Foreign Currency Hedge
     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):

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        Exchange
Forecasted Settlement Date   Amount   Rate
April 30, 2008
  £563     1.9382  
May 30, 2008
  £581     1.9343  
June 30, 2008
  £563     1.9302  
July 31, 2008
  £581     1.9263  
August 29, 2008
  £581     1.9225  
          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.
Note 12 — Fair Value Measurements
          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:
    Level 1. Observable inputs such as quoted prices in active markets;
 
    Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
 
    Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.
          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:
  (a)   Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
 
  (b)   Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).
 
  (c)   Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).
          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):

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    Fair Value as of March 31, 2008
                                    Valuation
    Level 1   Level 2   Level 3   Total   Technique
Assets:
                                       
Foreign currency forwards
          3,219             3,219       (c )
 
                                       
Liabilities:
                                       
Oil and gas costless collars
          13,587             13,587       (c )
Interest rate swaps
          8,439             8,439       (c )
 
                                       
Total
          22,026             22,026          
 
                                       
Note 13 — Comprehensive Income
          The components of total comprehensive income for the three months ended March 31, 2008 and 2007 were as follows (in thousands):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Net income
  $ 75,216     $ 56,765  
Foreign currency translation gain
    807       637  
Unrealized loss on hedges, net
    (2,447 )     (8,190 )
 
           
Total comprehensive income
  $ 73,576     $ 49,212  
 
           
          The components of accumulated other comprehensive income were as follows (in thousands):
                 
    March 31,     December 31,  
    2008     2007  
Cumulative foreign currency translation adjustment
  $ 29,067     $ 28,260  
Unrealized loss on hedges, net
    (9,445 )     (6,998 )
 
           
Accumulated other comprehensive income
  $ 19,622     $ 21,262  
 
           
Note 14 — Earnings Per Share
          Basic earnings per share (“EPS”) is computed by dividing the net income available to common shareholders by the weighted average shares of outstanding common stock. The calculation of diluted EPS is similar to basic EPS, except 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):
                                 
    Three Months Ended     Three Months Ended  
    March 31, 2008     March 31, 2007  
    Income     Shares     Income     Shares  
Earnings applicable per common share — Basic
  $ 74,335       90,413     $ 55,820       89,994  
Effect of dilutive securities:
                               
Stock options
          336             364  
Restricted shares
          100             132  
Employee stock purchase plan
                      12  
Convertible Senior Notes
          706             179  
Convertible preferred stock
    881       3,631       945       3,631  
 
                       
Earnings applicable per common share — Diluted
  $ 75,216       95,186     $ 56,765       94,312  
 
                       
          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

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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.
Note 15 — Stock-Based Compensation Plans
          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:
                             
                    Market    
                    Value    
                    Per    
Date of Grant   Type   Shares   Share   Vesting Period
January 2, 2008
    (1 )     418,434     $ 41.50     20% per year over five years
January 2, 2008
    (2 )     45,784       41.50     20% per year over five years
January 2, 2008
    (1 )     1,107       41.50     100% on January 2, 2010
February 28, 2008
    (1 )     11,074       33.11     20% per year over five years
 
(1)   Restricted shares
 
(2)   Restricted stock units
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).
Employee Stock Purchase 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

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became effective third quarter 2007). For the three months ended March 31, 2007, we recognized $500,000 of compensation expense related to the ESPP.
Note 16 — Business Segment Information (in thousands)
          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.
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Revenues–
               
Contracting Services
  $ 183,789     $ 137,717  
Shelf Contracting
    144,571       149,226  
Oil and Gas
    171,051       130,967  
Intercompany elimination
    (48,674 )     (21,855 )
 
           
Total
  $ 450,737     $ 396,055  
 
           
 
               
Income from operations–
               
Contracting Services
  $ 20,911     $ 22,866  
Shelf Contracting
    7,548       48,304  
Production Facilities equity investments(1)
    (138 )     (187 )
Oil and Gas
    109,917       39,445  
Intercompany elimination
    (4,030 )     (5,413 )
 
           
Total
  $ 134,208     $ 105,015  
 
           
 
               
Equity in earnings of OTSL
  $     $ 952  
 
           
Equity in earnings of equity investments excluding OTSL
  $ 10,923     $ 5,152  
 
           
 
(1)   Includes selling and administrative expense of Production Facilities incurred by us. See equity in earnings of equity investments excluding Offshore Technology Solutions Limited (“OTSL”) for earnings contribution.
                 
    March 31,     December 31,  
    2008     2007  
Identifiable Assets–
               
Contracting Services
  $ 1,334,930     $ 1,177,431  
Shelf Contracting
    1,154,511       1,274,050  
Production Facilities
    395,675       366,634  
Oil and Gas
    2,702,854       2,634,238  
 
           
Total
  $ 5,587,970     $ 5,452,353  
 
           

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          Intercompany segment revenues during the three months ended March 31, 2008 and 2007 were as follows:
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Contracting Services
  $ 42,323     $ 14,596  
Shelf Contracting
    6,351       7,259  
 
           
Total
  $ 48,674     $ 21,855  
 
           
          Intercompany segment profits during the three months ended March 31, 2008 and 2007 were as follows:
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Contracting Services
  $ 2,913     $ 2,018  
Shelf Contracting
    1,117       3,395  
 
           
Total
  $ 4,030     $ 5,413  
 
           
          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.
Note 17 — Resignation of Chief Executive Officer
          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.
Note 18 — Related Party Transactions
          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.

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Note 19 — Commitments and Contingencies
Commitments
          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

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additional capital expenditures for exploration, development and drilling costs related to our oil and gas properties.
Contingencies
          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.
Note 20 — Recently Issued Accounting Principles
          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,

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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.
Note 21 — Condensed Consolidated Guarantor and Non-Guarantor Financial Information
          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.

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HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
                                         
    As of March 31, 2008  
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
ASSETS
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 113,675     $ 255     $ 62,189     $     $ 176,119  
Accounts receivable, net
    82,132       125,784       196,092             404,008  
Other current assets
    72,435       57,634       51,166       (58,515 )     122,720  
 
                             
Total current assets
    268,242       183,673       309,447       (58,515 )     702,847  
 
                             
Intercompany
    83,465       46,742       (118,529 )     (11,678 )      
Property and equipment, net
    122,402       2,155,676       1,119,825       (3,133 )     3,394,770  
Other assets:
                                       
Equity investments
    3,100,792       38,372       207,579       (3,139,164 )     207,579  
Goodwill
          757,752       330,427       (275 )     1,087,904  
Other assets, net
    54,449       40,087       129,747       (29,413 )     194,870  
 
                             
 
  $ 3,629,350     $ 3,222,302     $ 1,978,496     $ (3,242,178 )   $ 5,587,970  
 
                             
 
                                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
Current liabilities:
                                       
Accounts payable
  $ 53,643     $ 172,706     $ 95,205     $ 41     $ 321,595  
Accrued liabilities
    58,120       76,964       84,369       (4,361 )     215,092  
Income taxes payable
    (4,089 )     35,821       705       (5,588 )     26,849  
Current maturities of long-term debt
    4,326             93,433       (43,458 )     54,301  
 
                             
Total current liabilities
    112,000       285,491       273,712       (53,366 )     617,837  
 
                             
Long-term debt
    1,419,511             441,852       (25,485 )     1,835,878  
Deferred income taxes
    138,782       317,199       177,207       (6,242 )     626,946  
Decommissioning liabilities
          188,651       4,076             192,727  
Other long-term liabilities
    4,144       59,657       7,444       (5,219 )     66,026  
Due to parent
    (37,028 )     97,411       37,028       (97,411 )      
 
                             
Total liabilities
    1,637,409       948,409       941,319       (187,723 )     3,339,414  
Minority interests
                      267,978       267,978  
Convertible preferred stock
    55,000                         55,000  
Shareholders’ equity
    1,936,941       2,273,893       1,037,177       (3,322,433 )     1,925,578  
 
                             
 
  $ 3,629,350     $ 3,222,302     $ 1,978,496     $ (3,242,178 )   $ 5,587,970  
 
                             

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HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
                                         
    As of December 31, 2007  
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
ASSETS
                                       
Current assets:
                                       
Cash and cash equivalents
  $ 3,507     $ 2,609     $ 83,439     $     $ 89,555  
Accounts receivable, net
    99,354       104,339       308,439             512,132  
Other current assets
    74,665       45,752       55,529       (50,364 )     125,582  
 
                             
Total current assets
    177,526       152,700       447,407       (50,364 )     727,269  
 
                             
Intercompany
    38,989       48,047       (80,592 )     (6,444 )      
Property and equipment, net
    92,864       2,093,194       1,060,298       (1,668 )     3,244,688  
Other assets:
                                       
Equity investments
    3,015,250       33,000       213,429       (3,048,250 )     213,429  
Goodwill
          757,752       332,281       (275 )     1,089,758  
Other assets, net
    59,554       40,686       111,259       (34,290 )     177,209  
 
                             
 
  $ 3,384,183     $ 3,125,379     $ 2,084,082     $ (3,141,291 )   $ 5,452,353  
 
                             
 
                                       
LIABILITIES AND SHAREHOLDERS’ EQUITY
                                       
Current liabilities:
                                       
Accounts payable
  $ 43,774     $ 207,222     $ 131,730     $ 41     $ 382,767  
Accrued liabilities
    40,415       71,945       110,443       (1,437 )     221,366  
Income taxes payable
    (3,043 )     159       4,467       (1,583 )      
Current maturities of long-term debt
    4,327       2       113,975       (43,458 )     74,846  
 
                             
Total current liabilities
    85,473       279,328       360,615       (46,437 )     678,979  
 
                             
Long-term debt
    1,287,092             463,934       (25,485 )     1,725,541  
Deferred income taxes
    137,967       318,492       178,275       (9,226 )     625,508  
Decommissioning liabilities
          189,639       4,011             193,650  
Other long-term liabilities
    3,294       56,325       9,244       (5,680 )     63,183  
Due to parent
    (35,681 )     98,504       37,028       (99,851 )      
 
                             
Total liabilities
    1,478,145       942,288       1,053,107       (186,679 )     3,286,861  
Minority interests
                      263,926       263,926  
Convertible preferred stock
    55,000                         55,000  
Shareholders’ equity
    1,851,038       2,183,091       1,030,975       (3,218,538 )     1,846,566  
 
                             
 
  $ 3,384,183     $ 3,125,379     $ 2,084,082     $ (3,141,291 )   $ 5,452,353  
 
                             

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HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS
(in thousands)
                                         
    Three Months Ended March 31, 2008        
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
Net revenues
  $ 84,891     $ 202,242     $ 218,371     $ (54,767 )   $ 450,737  
Cost of sales
    66,114       137,751       175,655       (49,662 )     329,858  
 
                             
Gross profit
    18,777       64,491       42,716       (5,105 )     120,879  
Gain on sale of assets
          61,113                   61,113  
Selling and administrative expenses
    10,895       14,459       23,531       (1,101 )     47,784  
 
                             
Income from operations
    7,882       111,145       19,185       (4,004 )     134,208  
Equity in earnings of investments
    82,389       5,372       10,923       (87,761 )     10,923  
Net interest expense and other
    6,494       13,263       8,755       (2,466 )     26,046  
 
                             
Income before income taxes
    83,777       103,254       21,353       (89,299 )     119,085  
Provision for income taxes
    4,307       33,526       3,081       2,718       43,632  
Minority interest
                      237       237  
 
                             
Net income
    79,470       69,728       18,272       (92,254 )     75,216  
Preferred stock dividends
    881                         881  
 
                             
Net income applicable to common shareholders
  $ 78,589     $ 69,728     $ 18,272     $ (92,254 )   $ 74,335  
 
                             
                                         
    Three Months Ended March 31, 2007  
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
Net revenues
  $ 55,683     $ 165,869     $ 200,976     $ (26,473 )   $ 396,055  
Cost of sales
    37,902       112,240       131,018       (20,720 )     260,440  
 
                             
Gross profit
    17,781       53,629       69,958       (5,753 )     135,615  
Selling and administrative expenses
    6,193       10,273       14,478       (344 )     30,600  
 
                             
Income from operations
    11,588       43,356       55,480       (5,409 )     105,015  
Equity in earnings of investments
    49,146       3,067       6,104       (52,213 )     6,104  
Net interest expense and other
    (2,353 )     11,258       4,107             13,012  
 
                             
Income before income taxes
    63,087       35,165       57,477       (57,622 )     98,107  
Provision for income taxes
    10,714       14,583       17,361       (9,535 )     33,123  
Minority interest
                100       8,119       8,219  
 
                             
Net income
    52,373       20,582       40,016       (56,206 )     56,765  
Preferred stock dividends
    945                         945  
 
                             
Net income applicable to common shareholders
  $ 51,428     $ 20,582     $ 40,016     $ (56,206 )   $ 55,820  
 
                             

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HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(in thousands)
                                         
    Three Months Ended March 31, 2008          
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
Cash flow from operating activities:
                                       
Net income
  $ 79,470     $ 69,728     $ 18,272     $ (92,254 )   $ 75,216  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Equity in earnings of unconsolidated affiliates
                (19 )           (19 )
Equity in earnings of affiliates
    (82,389 )     (5,372 )           87,761        
Other adjustments
    53,801       (42,157 )     35,232       3,493       50,369  
 
                             
Net cash provided by (used in) operating Activities
    50,882       22,199       53,485       (1,000 )     125,566  
 
                             
Cash flows from investing activities:
                                       
Capital expenditures
    (22,383 )     (159,236 )     (59,931 )           (241,550 )
Investments in equity investments
                (207 )           (207 )
Distributions from equity investments, net
                5,995             5,995  
Increases in restricted cash
          (232 )                 (232 )
Proceeds from sales of property
          110,086       61             110,147  
 
                             
Net cash used in investing activities
    (22,383 )     (49,382 )     (54,082 )           (125,847 )
 
                             
 
                                       
Cash flows from financing activities:
                                       
Borrowings on revolver
    318,500                         318,500  
Repayments on revolver
    (185,000 )                       (185,000 )
Repayments of debt
    (1,082 )           (41,982 )           (43,064 )
Deferred financing costs
    (409 )                       (409 )
Preferred stock dividends paid
    (881 )                       (881 )
Repurchase of common stock
    (3,309 )                       (3,309 )
Excess tax benefit from stock-based compensation
    629                         629  
Exercise of stock options, net
    321                         321  
Intercompany financing
    (47,100 )     24,829       21,271       1,000        
 
                             
Net cash provided by (used in) financing activities
    81,669       24,829       (20,711 )     1,000       86,787  
 
                             
Effect of exchange rate changes on cash and cash equivalents
                58             58  
 
                             
Net increase (decrease) in cash and cash equivalents
    110,168       (2,354 )     (21,250 )           86,564  
Cash and cash equivalents:
                                       
Balance, beginning of year
    3,507       2,609       83,439             89,555  
 
                             
Balance, end of year
  $ 113,675     $ 255     $ 62,189     $     $ 176,119  
 
                             

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HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS
(in thousands)
                                         
    Three Months Ended March 31, 2007  
                    Non-     Consolidating        
    Helix     Guarantors     Guarantors     Entries     Consolidated  
Cash flow from operating activities:
                                       
Net income
  $ 52,373     $ 20,583     $ 40,016     $ (56,207 )   $ 56,765  
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
                                       
Equity in earnings of affiliates
    (49,146 )     (3,067 )           52,213        
Other adjustments
    (177,036 )     46,477       2,752       7,988     (119,819 )
 
                             
Net cash provided by (used in) operating Activities
    (173,809 )     63,993       42,768       3,994     (63,054 )
 
                             
Cash flows from investing activities:
                                       
Capital expenditures
    (9,546 )     (151,674 )     (20,679 )           (181,899 )
Acquisition of businesses, net of cash acquired
          (79 )                 (79 )
(Purchases) sale of short-term investments
    265,820                         265,820  
Investments in equity investments
                (10,294 )           (10,294 )
Distributions from equity investments, net
                4,896             4,896  
Increases in restricted cash
          (266 )                 (266 )
Proceeds from sales of property
          (400 )     17             (383 )
 
                             
Net cash provided by (used in) investing activities
    256,274       (152,419 )     (26,060 )           77,795  
 
                             
 
                                       
Cash flows from financing activities:
                                       
Repayments on revolver
                (29,000 )           (29,000 )
Repayments of debt
    (2,100 )           (1,888 )           (3,988 )
Deferred financing costs
    (21 )           (15 )           (36 )
Capital lease payments
              (622 )           (622 )
Preferred stock dividends paid
    (945 )                       (945 )
Repurchase of common stock
    (3,956 )                       (3,956 )
Excess tax benefit from stock-based compensation
    187                         187  
Exercise of stock options, net
    376                         376  
Intercompany financing
    (84,881 )     83,512       5,363     (3,994 )      
 
                             
Net cash provided by (used in) financing activities
    (91,340 )     83,512       (26,162 )     (3,994 )     (37,984 )
 
                             
Effect of exchange rate changes on cash and cash equivalents
                113             113  
 
                             
Net decrease in cash and cash equivalents
    (8,875 )     (4,914 )     (9,341 )           (23,130 )
Cash and cash equivalents:
                                       
Balance, beginning of year
    142,489       7,690       56,085             206,264  
 
                             
Balance, end of year
  $ 133,614     $ 2,776     $ 46,744     $     $ 183,134  
 
                             

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.
FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS
          This Quarterly Report on Form 10-Q contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included herein or incorporated herein by reference are forward-looking statements. Included among forward-looking statements are, among other things:
    statements regarding our anticipated production volumes, results of exploration, exploitation, development, acquisition or operations expenditures, and current or prospective reserve levels with respect to any property or well;
 
    statements related to the volatility in commodity prices for oil and gas and in the supply of and demand for oil and natural gas or the ability to replace oil and gas reserves;
 
    statements relating to our proposed acquisition , exploration, development and/or production of oil and gas properties, prospects or other interests and any anticipated costs related thereto;
 
    statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
 
    statements relating to the construction or acquisition of vessels or equipment, including statements concerning the engagement of any engineering, procurement and construction contractor and any anticipated costs related thereto;
 
    statements that our proposed vessels, when completed, will have certain characteristics or the effectiveness of such characteristics;
 
    statements regarding projections of revenues, gross margin, expenses, earnings or losses or other financial items;
 
    statements regarding our business strategy, our business plans or any other plans, forecasts or objectives, any or all of which is subject to change;
 
    statements regarding any Securities and Exchange Commission (“SEC”) or other governmental or regulatory inquiry or investigation;
 
    statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
 
    statements regarding anticipated developments, industry trends, performance or industry ranking;
 
    statements related to the underlying assumptions related to any projection or forward-looking statement;
 
    statements related to environmental risks, exploration and development risks, or drilling and operating risks;
 
    statements related to the ability of the Company to retain key members of its senior management and key employees;
 
    statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we are doing business; and
 
    any other statements that relate to non-historical or future information.
          These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “achieve,” “should,” “could” and similar terms and phrases. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements.
          Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those described under the heading “Risk Factors” in our 2007 Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of

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the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.
RESULTS OF OPERATIONS
          Our operations are conducted through two lines of business: contracting services operations and oil and gas operations.
Contracting Services Operations
          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. Our “life of field” services are organized in five disciplines: construction, well operations, production facilities, reservoir and well tech services, and drilling. We have disaggregated our contracting services operations into three reportable segments in accordance with 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 Shelf Contracting segment consists of assets deployed primarily for diving-related activities and shallow water construction. The assets of our Shelf Contracting segment are the assets of Cal Dive. Our ownership in Cal Dive was 58.2% as of March 31, 2008. As of March 31, 2008, our contracting services operations had backlog of approximately $1.3 billion, of which approximately $790 million was expected to be completed in the remainder of 2008.
Oil and Gas Operations
          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 business 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. By owning oil and gas reservoirs and prospects, we are able to utilize the services we otherwise provide to third parties to create value at key points in the life of our own reservoirs including during the exploration and development stages, the field management stage and the abandonment stage. It is also a feature of our business model to opportunistically monetize part of the created reservoir value, through sales of working interests, in order to help fund field development and reduce gross profit deferrals from our Contracting Services operations. Therefore the reservoir value we create is realized through oil and gas production and/or monetization of working interest stakes.

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Comparison of Three Months Ended March 31, 2008 and 2007
     The following table details various financial and operational highlights for the periods presented:
                         
    Three Months Ended        
    March 31,     Increase/  
    2008     2007     (Decrease)  
Revenues (in thousands) —
                       
Contracting Services
  $ 183,789     $ 137,717     $ 46,072  
Shelf Contracting
    144,571       149,226       (4,655 )
Oil and Gas
    171,051       130,967       40,084  
Intercompany elimination
    (48,674 )     (21,855 )     (26,819 )
 
                 
 
  $ 450,737     $ 396,055     $ 54,682  
 
                 
 
                       
Gross profit (in thousands) —
                       
Contracting Services
  $ 38,840     $ 34,494     $ 4,346  
Shelf Contracting
    24,690       57,952       (33,262 )
Oil and Gas
    61,379       48,582       12,797  
Intercompany elimination
    (4,030 )     (5,413 )     1,383  
 
                 
 
  $ 120,879     $ 135,615     $ (14,736 )
 
                 
 
                       
Gross Margin —
                       
Contracting Services
    21 %     25 %   (4 pts )
Shelf Contracting
    17 %     39 %   (22 pts )
Oil and Gas
    36 %     37 %   (1 pt )
 
                       
Total company
    27 %     34 %   (7 pts )
 
                       
Number of vessels(1)/ Utilization(2)
                       
Contracting Services:
                       
Pipelay
    3/99 %     3/93 %        
Well operations
    2/26 %     2/65 %        
ROVs
    42/66 %     33/70 %        
Shelf Contracting
    34/31 %     25/70 %        
 
(1)   Represents number of vessels as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.
 
(2)   Average vessel utilization rate is calculated by dividing the total number of days the vessels in this category generated revenues by the total number of calendar days in the applicable period.
     Intercompany segment revenues during the three months ended March 31, 2008 and 2007 were as follows (in thousands):
                         
    Three Months Ended        
    March 31,     Increase/  
    2008     2007     (Decrease)  
Contracting Services
  $ 42,323     $ 14,596     $ 27,727  
Shelf Contracting
    6,351       7,259       (908 )
 
                 
 
  $ 48,674     $ 21,855     $ 26,819  
 
                 

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     Intercompany segment profit during the three months ended March 31, 2008 and 2007 was as follows (in thousands):
                         
    Three Months Ended        
    March 31,     Increase/  
    2008     2007     (Decrease)  
Contracting Services
  $ 2,913     $ 2,018     $ 895  
Shelf Contracting
    1,117       3,395       (2,278 )
 
                 
 
  $ 4,030     $ 5,413     $ (1,383 )
 
                 
     The following table details various financial and operational highlights related to our Oil and Gas segment for the periods presented:
                         
    Three Months Ended        
    March 31,     Increase/  
    2008     2007     (Decrease)  
Oil and Gas information—
                       
Oil production volume (MBbls)
    910       959       (49 )
Oil sales revenue (in thousands)
  $ 79,454     $ 54,053     $ 25,401  
Average oil sales price per Bbl (excluding hedges)
  $ 92.15     $ 56.11     $ 36.04  
Average realized oil price per Bbl (including hedges)
  $ 87.32     $ 56.36     $ 30.96  
Increase (decrease) in oil sales revenue due to:
                       
Change in prices (in thousands)
  $ 29,691                  
Change in production volume (in thousands)
    (4,290 )                
 
                     
Total increase in oil sales revenue (in thousands)
  $ 25,401                  
 
                     
 
                       
Gas production volume (MMcf)
    10,103       9,970       133  
Gas sales revenue (in thousands)
  $ 90,463     $ 75,912     $ 14,551  
Average gas sales price per mcf (excluding hedges)
  $ 8.91     $ 7.43     $ 1.48  
Average realized gas price per mcf (including hedges)
  $ 8.95     $ 7.61     $ 1.34  
Increase (decrease) in gas sales revenue due to:
                       
Change in prices (in thousands)
  $ 13,364                  
Change in production volume (in thousands)
    1,187                  
 
                     
Total increase in gas sales revenue (in thousands)
  $ 14,551                  
 
                     
 
                       
Total production (MMcfe)
    15,563       15,725       (162 )
Price per Mcfe
  $ 10.92     $ 8.27     $ 2.65  
 
                       
Oil and Gas revenue information (in thousands)—
                       
Oil and gas sales revenue
  $ 169,917     $ 129,965     $ 39,952  
Miscellaneous revenues(1)
    1,134       1,002       132  
 
                 
 
  $ 171,051     $ 130,967     $ 40,084  
 
                 
 
(1)   Miscellaneous revenues primarily relate to fees earned under our process handling agreements.

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     Presenting the expenses of our Oil and Gas segment on a cost per Mcfe of production basis normalizes for the impact of production gains/losses and provides a measure of expense control efficiencies. The following table highlights certain relevant expense items in total (in thousands) converted to Mcfe at a ratio of one barrel of oil to six Mcf:
                                 
    Three Months Ended March 31,  
    2008     2007  
    Total     Per Mcfe     Total     Per Mcfe  
Oil and gas operating expenses(1):
                               
Direct operating expenses(2)
  $ 22,300     $ 1.43     $ 19,812     $ 1.26  
Workover
    2,742       0.18       3,345       0.21  
Transportation
    952       0.06       1,219       0.08  
Repairs and maintenance
    4,873       0.31       3,291       0.21  
Overhead and company labor
    2,662       0.17       2,632       0.17  
 
                       
Total
  $ 33,529     $ 2.15     $ 30,299     $ 1.93  
 
                       
 
                               
Depletion expense
  $ 53,628     $ 3.45     $ 46,918     $ 2.98  
Abandonment
    659       0.04       1,324       0.08  
Accretion expense
  3,246     0.21     2,655     0.17  
Impairment
    16,723       1.07              
 
(1)   Excludes exploration expense of $1.9 million and $1.2 million for the three months ended March 31, 2008 and 2007, respectively. Exploration expense is not a component of lease operating expense.
 
(2)   Includes production taxes.
     Revenues. During the three months ended March 31, 2008, our revenues increased by 14% as compared to the same period in 2007. Contracting Services revenues increased primarily due to improved contract pricing and market demand for the pipelay and ROV divisions in deepwater. These increases were partially offset by increased number of out-of-service days for drilling upgrade and regulatory drydock for the Q4000. Shelf Contracting revenues decreased primarily due to lower vessel utilization related to winter weather seasonality during first quarter 2008, partially offset by revenues earned from assets obtained through the Horizon acquisition. During the first quarter of 2007, Shelf Contracting continued to experience a high level of hurricane repair activity and earned stand-by revenue for many of CDI’s vessels despite winter weather work interruptions.
     Oil and Gas revenues increased 31% during the three months ended March 31, 2008 as compared to the same period in 2007. The increase in oil revenues was attributable to a significant increase in oil prices as production was slightly lower than the prior year period. The increase in gas revenues was attributable to higher gas production and higher gas prices realized in the first quarter of 2008 as compared to the same prior year period.
     Gross Profit. Gross profit in the first quarter of 2008 decreased 11% as compared to the same period in 2007. This decrease was due to decreased Shelf Contracting profitability as a result of lower vessel utilization and increased depreciation and amortization resulting from the Horizon acquisition.
     The decrease in Shelf Contracting gross profit was partially offset by increased profitability in Contracting Services. This increase was primarily attributable to improved contract pricing and market demand for the pipelay and ROV divisions in deepwater. These increases were partially offset by increased number of out-of-service days for drilling upgrade and regulatory drydock for the Q4000.
     The Oil and Gas gross profit increase of $12.8 million in first quarter 2008 as compared to the same period in 2007 was primarily due to increases in oil and gas prices, as discussed above. These increases were partially offset by impairment expense of approximately $16.7 million, of which approximately $14.3 million was related to the unsuccessful development well in January 2008 on Devil’s Island (Garden Banks 344).

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          Gain on Sale of Assets, Net. Gain on sale of assets, net, was $61.1 million during the three months ended March 31, 2008. This gain was related to the March 31, 2008 sale of a 20% 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). We sold an additional 10% working interest in the Bushwood discoveries in April 2008.
          Selling and Administrative Expenses. Selling and administrative expenses of $47.8 million for the first quarter of 2008 were $17.2 million higher than the $30.6 million incurred in the same prior year period. The increase was due primarily to higher overhead (primarily related to the Horizon acquisition) to support our growth. In addition, in February 2008, we recognized approximately $5.4 million of expenses related to the separation agreement between the Company and Mr. Ferron, our former Chief Executive Officer, as a result of his resignation and the termination of his employment with the Company.
          Equity in Earnings of Investments. Equity in earnings of investments increased by $4.8 million during the three months ended March 31, 2008 as compared to the same prior year period. This increase was mostly due to a $5.4 million increase in equity in earnings related to our 20% investment in Independence Hub which began production during the third quarter of 2007. On April 9, 2008, Independence hub platform was shut-in as the result of a leak in the gas export pipeline. The owner of the pipeline expects the shut-down to last until mid-May 2008. Our investment in Deepwater Gateway contributed a $335,000 increase.
          Net Interest Expense and Other. We reported net interest and other expense of $26.0 million in first quarter 2008 as compared to $13.0 million in the same prior year period. Gross interest expense of $34.9 million during the three months ended March 31, 2008 was higher than the $23.1 million incurred in 2007 due to overall higher levels of indebtedness as a result of our Senior Unsecured Notes and CDI’s term loan, which both closed in December 2007. Offsetting the increase in interest expense was $11.0 million of capitalized interest and $1.0 million of interest income in the first quarter of 2008, compared with $5.4 million of capitalized interest and $4.6 million of interest income in the same prior year period.
          Provision for Income Taxes. Income taxes increased to $43.6 million in the first quarter of 2008 as compared to $33.1 million in the same prior year period. The increase was primarily due to increased profitability. The effective tax rate of 36.6% for the first quarter of 2008 was higher than the 33.8% for the first quarter of 2007. 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. This increase was partially offset by the benefit derived from the Internal Revenue Code section 199 manufacturing deduction primarily related to oil and gas production and the effect of lower tax rates in certain foreign jurisdictions.
LIQUIDITY AND CAPITAL RESOURCES
Overview
          The following tables present certain information useful in the analysis of our financial condition and liquidity for the periods presented (in thousands):
                 
    March 31,   December 31,
    2008   2007
Net working capital
  $ 85,010     $ 48,290  
Long-term debt(1)
    1,835,878       1,725,541  
 
(1)   Long-term debt does not include the current maturities portion of the long-term debt as such amount is included in net working capital.

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    Three Months Ended
    March 31,
(in thousands)   2008   2007
Net cash provided by (used in):
               
Operating activities
  $ 125,566     $ (63,054 )
Investing activities
  $ (125,847 )   $ 77,795  
Financing activities
  $ 86,787     $ (37,984 )
          Our primary cash needs are to fund capital expenditures to allow the growth of our current lines of business and to repay outstanding borrowings and make related interest payments. Historically, we have funded our capital program, including acquisitions, with cash flows from operations, borrowings under credit facilities and use of project financing along with other debt and equity alternatives.
          In accordance with the Senior Unsecured Notes, amended Senior Credit Facilities, Convertible Senior Notes, MARAD Debt and Cal Dive’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 and December 31, 2007, 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.
          The Senior Unsecured Notes essentially prohibit any of our restricted subsidiaries from creating, issuing, incurring, assuming, guaranteeing or becoming directly or indirectly liable for the payment of any indebtedness unless specified otherwise in the indenture. 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. The Senior Unsecured Notes may be redeemed prior to the stated maturity under certain circumstances specified in the indenture governing the Senior Unsecured Notes.
          Provisions of the amended Senior Credit Facilities effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by the Company. The Senior Credit Facilities do, however, permit us to incur unsecured indebtedness (such as our Senior Unsecured Notes), and also permit our subsidiaries to incur project financing indebtedness secured by the underlying asset, provided that the indebtedness is not guaranteed by us.
          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.
          As of March 31, 2008, we had $116.9 million of available borrowing capacity under our credit facilities, and CDI had $293.6 million of available borrowing under its revolving credit facility. We do not have access to any unused portion of CDI’s revolving credit facility. See “Notes to Condensed Consolidated Financial Statements (Unaudited) — Note 9 — Long-term Debt” for additional information related to our long-term obligations.
Working Capital
          Cash flow from operating activities increased by $188.6 million in the three months ended March 31, 2008 as compared to the same period in 2007. This increase was primarily due to net income taxes paid in the first three months of 2008 of approximately $966,000 compared to approximately $154.4 million in the first three months of 2007, most of which ($126.6 million) was related to the proceeds received from the CDI initial public offering.

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Investing Activities
          Capital expenditures have consisted principally of strategic asset acquisitions related to the purchase or construction of dynamically positioned vessels, acquisition of select businesses, improvements to existing vessels, acquisition of oil and gas properties and investments in our production facilities. Significant sources (uses) of cash associated with investing activities for the three months ended March 31, 2008 and 2007 were as follows (in thousands):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Capital expenditures:
               
Contracting Services
  $ (72,858 )   $ (39,514 )
Shelf Contracting
    (9,608 )     (2,146 )
Production Facilities
    (27,536 )     (13,508 )
Oil and Gas
    (131,548 )     (126,731 )
Acquisition of Remington, net of cash acquired
          (79 )
Sale of short-term investments
          265,820  
Investments in production facilities
    (207 )     (10,294 )
Distributions from equity investments, net(1)
    5,995       4,896  
Increase in restricted cash
    (232 )     (266 )
Proceeds from sale of properties
    110,147       (383 )
 
           
Cash (used in) provided by investing activities
  $ (125,847 )   $ 77,795  
 
           
 
(1)   Distributions from equity investments are net of undistributed equity earnings from our equity investments. Gross distributions from our equity investments are detailed below.
Restricted Cash
          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, in the accompanying condensed consolidated balance sheet, all of which related to the funds required to be escrowed to cover decommissioning liabilities associated with the 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.
Equity Investments
     We made the following contributions to our equity investments during the three months ended March 31, 2008 and 2007 (in thousands):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
Independence
  $     $ 7,935  
Other
    238       2,359  
 
           
Total
  $ 238     $ 10,294  
 
           

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          We received the following distributions from our equity investments during the three months ended March 31, 2008 and 2007 (in thousands):
                 
    Three Months Ended  
    March 31,  
    2008     2007  
 
           
Deepwater Gateway
  $ 8,500     $ 11,000  
Independence
    8,400        
 
           
Total
  $ 16,900     $ 11,000  
 
           
Sale of Oil and Gas Properties
          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 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 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.
Outlook
          We anticipate capital expenditures for the remainder of 2008 will range from $725 million to $825 million. 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. We may increase or decrease these plans based on various economic factors. We believe internally generated cash flow, cash from future sales of oil and gas interests and borrowings under our existing credit facilities will provide the necessary capital to fund our 2008 initiatives.
          The following table summarizes our contractual cash obligations as of March 31, 2008 and the scheduled years in which the obligations are contractually due (in thousands):
                                         
            Less Than                     More Than  
    Total(1)     1 year     1-3 Years     3-5 Years     5 Years  
Convertible Senior Notes(2)
  $ 300,000     $     $     $     $ 300,000  
Senior Unsecured Notes
    550,000                         550,000  
Term Loan
    422,336       4,326       8,652       8,652       400,706  
MARAD debt
    125,481       4,113       8,851       9,757       102,760  
Revolving Credit Facility
    151,500                   151,500        
CDI Term Loan
    335,000       40,000       160,000       135,000        
Loan notes
    5,000       5,000                    
Interest related to long-term debt
    797,657       105,582       199,213       181,754       311,108  
Preferred stock dividends(3)
    2,999       2,999                    
Capital leases
    862       862                    
Drilling and development costs
    180,000       180,000                    
Property and equipment(4)
    188,000       188,000                    
Operating leases(5)
    151,318       54,441       46,934       35,152       14,791  
Other(6)
    1,740       1,740                    
 
                             
Total cash obligations
  $ 3,211,893     $ 587,063     $ 423,650     $ 521,815     $ 1,679,365  
 
                             

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(1)   Excludes unsecured letters of credit outstanding at March 31, 2008 totaling $38.0 million. These letters of credit primarily guarantee various contract bidding, insurance activities and shipyard commitments.
 
(2)   Maturity 2025. Can be converted prior to stated maturity if closing sale price of Helix’s common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 120% of the closing price on that 30th trading day (i.e. $38.56 per share) and under certain triggering events as specified in the indenture governing the Convertible Senior Notes. To the extent we do not have alternative long-term financing secured to cover the conversion, the Convertible Senior Notes would be classified as a current liability in the accompanying balance sheet. At March 31, 2008, the conversion trigger was not met.
 
(3)   Amount represents dividend payment for one year only. Dividends are paid quarterly until such time the holder elects to redeem the stock.
 
(4)   Costs incurred as of March 31, 2008 and additional property and equipment commitments (excluding capitalized interest) at March 31, 2008 consisted of the following (in thousands):
                         
    Costs     Costs     Total Estimated  
    Incurred     Committed     Project Cost Range  
Caesar conversion
  $ 102,000     $ 29,000     $ 165,000 — 185,000  
Q4000 upgrade
    117,000       23,000       160,000 — 165,000  
Well Enhancer construction
    104,000       68,000       190,000 — 200,000  
Helix Producer I(a)
    180,000       68,000       260,000 — 270,000  
 
                 
Total
  $ 503,000     $ 188,000     $ 775,000 — 820,000  
 
                 
 
(a)   Represents 100% of the cost of the vessel, conversion and construction of additional facilities, of which we expect our portion to range between $218 million and $228 million.
(5)   Operating leases included facility leases and vessel charter leases. Vessel charter lease commitments at March 31, 2008 were approximately $105.4 million.
 
(6)   Other consisted of scheduled payments pursuant to 3-D seismic license agreements.
Contingencies
          In orders from the MMS dated December 2005 and May 2006, we received notice from the MMS that lease price thresholds were exceeded for 2004 oil and gas production and for 2003 gas production, and that royalties are due on such production notwithstanding the provisions of the DWRRA. As of March 31, 2008, we have approximately $58.5 million accrued for the related royalties and interest. 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. See “Notes to Condensed Consolidated Financial Statements (Unaudited)—Note 19” for a detailed discussion of this contingency.
          During the fourth quarter of 2006, Horizon received a tax assessment from the 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 CDI’s and our 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.
CRITICAL ACCOUNTING POLICIES AND ESTIMATES
          Our discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements. We prepare these financial statements in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates,

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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. Due to the adoption of SFAS No. 157, we have updated our critical accounting policies fair value measurement. Please read the following discussion in conjunction with our “Critical Accounting Policies and Estimates” as disclosed in our 2007 Form 10-K.
Fair Value Measurement
          SFAS No. 157 provides enhanced guidance for using fair value to measure assets and liabilities. 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. SFAS No. 157 establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
    Level 1. Observable inputs such as quoted prices in active markets;
 
    Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
 
    Level 3. Unobservable inputs in which there is little or no market data, which require the reporting entity to develop its own assumptions.
          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:
  (a)   Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
 
  (b)   Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).
 
  (c)   Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).
          The financial assets and liabilities that are recognized based on fair value on a recurring basis at March 31, 2008 include our oil and gas costless collars, interest rate swaps and foreign currency forwards. The following table provides additional details regarding the significant inputs used in the calculation of the fair values:
             
    Fair Value   Valuation    
Item   Hierarchy   Technique   Significant Inputs
Oil costless collars
  Level 2   Income  
  Hedged oil price
 
         
  NYMEX sweet crude oil forward price
 
         
  Light surface crude oil volatility rate
Gas costless collars
  Level 2   Income  
  Hedged gas price
 
         
  NYMEX natural gas forward price
 
         
  Natural gas volatility rate
Interest rate swaps
  Level 2   Income  
  Fixed rate
 
         
  Three months LIBOR forward rate
Foreign currency forwards
  Level 2   Income  
  Hedged rate
 
         
  Spot exchange rate
 
         
  Forward exchange rate — calculated by adjusting the spot exchange rate by the prevailing interest differential between the currencies

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As the financial assets and liabilities listed above qualify for hedge accounting, and as long as these instruments continue to be effective hedges, changes to the significant inputs described above would not have a material impact on results of operations as the change in the fair value is recorded in accumulated other comprehensive income, a component of shareholders’ equity. In addition, changes to significant inputs would not have a material impact on our liquidity, however, they may have a material impact on our financial condition.
Recently Issued Accounting Principles
          In March 2008, the FASB issued SFAS No. 161, which 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.
Proposed Accounting Principle
          In August 2007, the FASB proposed FASB Staff Position (“FSP”) APB 14-a, Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement). The proposed FSP would require the proceeds from the issuance of convertible debt instruments to be allocated between a liability component (issued at a discount) and an equity component. The resulting debt discount would be amortized over the period the convertible debt is expected to be outstanding as additional non-cash interest expense. The original proposed change in accounting treatment would have been effective for fiscal years beginning after December 15, 2007, and applied retrospectively to prior periods. As of March 31, 2008, the FASB had not finalized this FSP and it has not been issued. If adopted, this FSP would change the accounting treatment for our Convertible Senior Notes. This new accounting treatment could impact our results of operations and result in an increase to non-cash interest expense beginning in 2008 for financial statements covering past and future periods. We are currently evaluating the potential impact of this issue on our consolidated financial statements in the event that this pronouncement is adopted by the FASB.
Item 3. Quantitative and Qualitative Disclosure about Market Risk
          We are currently exposed to market risk in three major areas: interest rates, commodity prices and foreign currency exchange rates.
          Interest Rate Risk. As of March 31, 2008, including the effects of interest rate swaps, approximately 48.4% of our outstanding debt was based on floating rates. As a result, we are subject to interest rate risk. In September 2006, we entered into various cash flow hedging interest rate swaps to stabilize cash flows relating to interest payments on $200 million of our Term Loan. Excluding the portion of our debt for which we have interest rate swaps in place, the interest rate applicable to our remaining variable rate debt may rise, increasing our interest expense. The impact of market risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional $2.3 million and $2.6 million in interest expense for the three months ended March 31, 2008 and 2007, respectively.

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          Commodity Price Risk. 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:
                         
            Average   Weighted
Production Period   Instrument Type   Monthly Volumes   Average Price
Crude Oil:
                       
April 2008 — December 2008
  Collar   40 MBbl   $ 57.50 — $78.04  
April 2008 — December 2009
  Forward Sale   103.6 MBbl   $ 71.86  
 
                       
Natural Gas:
                       
April 2008 — December 2008
  Collar   550,000 MMBtu   $ 7.23 — $9.77  
April 2008 — December 2009
  Forward Sale   1,390,790 MMBtu   $ 8.24  
          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.
          Foreign Currency Exchange Risk. 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 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. 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.
          Canyon Offshore, our ROV subsidiary, has operations in the United Kingdom and Asia Pacific. We entered into various foreign currency forward purchase contracts to stabilize expected cash outflows relating to Canyon’s vessel charter. 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):
             
        Exchange
Forecasted Settlement Date   Amount   Rate
April 30, 2008
  £563     1.9382  
May 30, 2008
  £581     1.9343  
June 30, 2008
  £563     1.9302  
July 31, 2008
  £581     1.9263  
August 29, 2008
  £581     1.9225  
          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.
Item 4. Controls and Procedures
          (a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) promulgated under the Exchange Act) as of the end of the fiscal quarter ended March 31, 2008. Based on this evaluation, the principal executive officer and the principal financial officer have concluded that our disclosure controls and procedures were effective as of the end of the fiscal quarter ended March 31, 2008 to ensure that information that is required to be disclosed by us in the reports we file or submit 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

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and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.
          (b) Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting, as defined in Rule 13a-15(f) of the Exchange Act, in the period covered by this report that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We implemented an enterprise resource planning system on January 1, 2008 for our Deepwater division (excluding ROV and trencher business) and our U.S. Well Operations division but continued to perform the majority of controls following our previously tested control structure, often in parallel with the new enterprise resource planning system. Resulting impacts on internal controls over financial reporting were evaluated and determined not to be significant for the fiscal quarter ended March 31, 2008. However, this ongoing implementation effort will lead to our making additional changes in our internal controls over financial reporting in future fiscal periods. On December 11, 2007, our majority owned subsidiary, Cal Dive International, Inc., completed the acquisition of Horizon Offshore, Inc. Cal Dive continues to integrate Horizon’s historical internal controls over financial reporting into their own internal controls over financial reporting within our overall control structure. This ongoing integration may lead to our making additional changes in our internal controls over financial reporting in future fiscal periods.

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Part II. OTHER INFORMATION
Item 1. Legal Proceedings
          See Part I, Item 1, Note 19 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities
                                 
                    (c) Total        
                    number        
                    of shares     (d) Maximum  
                    purchased as     value of shares  
    (a) Total number     (b) Average     part of publicly     that may yet be  
    of shares     price paid     announced     purchased under  
Period   purchased     per share     program     the program  
 
                       
January 1 to January 31, 2008(1)
    46,875     $ 41.54           $ N/A  
February 1 to February 29, 2008(1)
    37,854       32.93             N/A  
March 1 to March 31, 2008(1)
    841       30.38             N/A  
 
                         
 
    85,570     $ 35.60           $ N/A  
 
                         
 
(1)   Represents shares subject to restricted share awards withheld to satisfy tax obligations arising upon the vesting of restricted shares.
Item 6. Exhibits
     
15.1
  Independent Registered Public Accounting Firm’s Acknowledgement Letter(1)
 
   
31.1
  Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer(1)
 
   
31.2
  Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by A. Wade Pursell, Chief Financial Officer(1)
 
   
32.1
  Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes — Oxley Act of 2002(2)
 
   
99.1
  Report of Independent Registered Public Accounting Firm(1)
 
   
 
  (1) Filed herewith
 
  (2) Furnished herewith

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
         
  HELIX ENERGY SOLUTIONS GROUP, INC.
(Registrant)

 
 
Date: May 2, 2008  By:   /s/ Owen Kratz    
    Owen Kratz   
    President and Chief Executive Officer   
 
     
Date: May 2, 2008  By:   /s/ A. Wade Pursell    
    A. Wade Pursell   
    Executive Vice President and Chief Financial Officer   

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INDEX TO EXHIBITS
OF
HELIX ENERGY SOLUTIONS GROUP, INC.
     
15.1
  Independent Registered Public Accounting Firm’s Acknowledgement Letter(1)
 
   
31.1
  Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer(1)
 
   
31.2
  Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by A. Wade Pursell, Chief Financial Officer(1)
 
   
32.1
  Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes — Oxley Act of 2002(2)
 
   
99.1
  Report of Independent Registered Public Accounting Firm(1)
 
   
 
  (1) Filed herewith
 
  (2) Furnished herewith

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