form10q.htm
 
 

 

 UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
Form 10-Q
 
[X]
 
Quarterly report pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934
 
For the quarterly period ended March 31, 2010
 
or
[   ]
 
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 ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
 
Minnesota
(State or other jurisdiction
of incorporation or organization)
             
95–3409686
(I.R.S. Employer
Identification No.)
  
   
400 North Sam Houston Parkway East
Suite 400
Houston, Texas
(Address of principal executive offices)
 
 
77060
(Zip Code)
 
(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  
[ √ ] 
    No 
[  ] 
 
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).
     Yes  
[   ] 
    No 
[  ] 
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer.  See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer
 ] 
Accelerated filer  
[    ] 
    Non-accelerated filer 
[    ] 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
     Yes  
[   ] 
    No 
[ √ ] 
 
As of April 27, 2010, 104,561,347 shares of common stock were outstanding.


TABLE OF CONTENTS
 
         
PART I.
 
FINANCIAL INFORMATION
 
PAGE
 
Item 1.
 
Financial Statements:
   
   
 
 
 
  
 
 
   
 
 
   
 
 
 
Item 2.
 
 
  
 
Item 3.
   
 
Item 4.
   
 
PART II.
 
OTHER INFORMATION
   
Item 1.
 
 
 
 
Item 2.
   
Item 6.
 
 
 
   
 
 
   
 
 


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,
   
2010
 
2009
   
(Unaudited)
   
ASSETS
Current assets:
               
  Cash and cash equivalents
 
$
212,178
   
$
270,673
 
  Accounts receivable —
     Trade, net of allowance for uncollectible accounts
         of $918  and $5,172, respectively
   
159,704
     
145,519
 
     Unbilled revenue
   
27,383
     
17,854
 
     Costs in excess of billing
   
28
     
9,305
 
  Other current assets
   
129,490
     
122,209
 
          Total current assets
   
528,783
     
565,560
 
Property and equipment
   
4,402,651
     
4,352,109
 
Less — accumulated depreciation
   
(1,551,136
)
   
(1,488,403
)
     
2,851,515
     
2,863,706
 
Other assets:
               
  Equity investments
   
186,944
     
189,411
 
  Goodwill
   
77,771
     
78,643
 
  Other assets, net
   
85,934
     
82,213
 
   
$
3,730,947
   
$
3,779,533
 
                 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
               
  Accounts payable
 
$
135,985
   
$
155,457
 
  Accrued liabilities
   
202,481
     
200,607
 
  Current maturities of long-term debt
   
11,834
     
12,424
 
          Total current liabilities
   
350,300
     
368,488
 
Long-term debt
   
1,347,007
     
1,348,315
 
Deferred income taxes
   
431,147
     
442,607
 
Asset retirement obligations
   
178,371
     
182,399
 
Other long-term liabilities
   
4,789
     
4,262
 
          Total liabilities
   
2,311,614
     
2,346,071
 
                 
Convertible preferred stock
   
6,000
     
6,000
 
                 
Commitments and contingencies
               
Shareholders’ equity:
               
  Common stock, no par, 240,000 shares authorized,      
     104,578 and 104,281 shares issued, respectively
   
907,362
     
907,691
 
  Retained earnings
   
501,916
     
519,807
 
  Accumulated other comprehensive loss
   
(18,978
)
   
(22,241
)
          Total controlling interest shareholders’ equity
   
1,390,300
     
1,405,257
 
  Noncontrolling interests                                                                          
   
23,033
     
22,205
 
          Total equity                                                                          
   
1,413,333
     
1,427,462
 
   
$
3,730,947
   
$
3,779,533
 
                 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
 (in thousands, except per share amounts)
 
 
     
Three Months Ended
 
     
March 31,
 
     
2010
     
2009
 
                 
Net revenues:
               
  Contracting services                                                                         
 
$
110,855
   
$
410,794
 
  Oil and gas                                                                         
   
90,715
     
160,181
 
     
201,570
     
570,975
 
                 
Cost of sales:
               
  Contracting services                                                                         
   
86,248
     
325,698
 
  Oil and gas                                                                         
   
89,466
     
84,067
 
     
175,714
     
409,765
 
                 
     Gross profit                                                                         
   
25,856
     
161,210
 
                 
Gain on oil and gas derivative contracts                                                                         
   
     
74,609
 
Gain on sale or acquisition of assets, net                                                                         
   
6,247
     
454
 
Selling and administrative expenses                                                                         
   
(40,501
)
   
(41,353
)
Income (loss) from operations                                                                         
   
(8,398
)
   
194,920
 
  Equity in earnings of investments                                                                         
   
5,055
     
7,503
 
  Net interest expense and other                                                                         
   
(21,193
)
   
(22,195
)
Income (loss) before income taxes                                                                         
   
(24,536
)
   
180,228
 
  (Provision) benefit for income taxes                                                                         
   
7,561
 
   
(64,919
Income (loss) from continuing operations                                                                         
   
(16,975
)
   
115,309
 
  Discontinued operations, net of tax                                                                         
   
(27
)
   
(2,554
)
Net income (loss), including noncontrolling interests
   
(17,002
)
   
112,755
 
  Less: net income (loss) applicable to noncontrolling interests
   
(829
)
   
(5,553
)
Net income (loss) applicable to  Helix                                                                         
   
(17,831
)
   
107,202
 
  Preferred stock dividends                                                                         
   
(60
)
   
(313
)
  Preferred stock beneficial conversion charges
   
     
(53,439
)
Net income (loss) applicable to Helix common shareholders
 
$
(17,891
)
 
$
53,450
 
                 
Basic earnings (loss) per share of common stock:
               
  Continuing operations                                                                         
 
$
(0.17
)
 
$
0.58
 
  Discontinued operations                                                                         
   
     
(0.03
)
  Net income (loss) per common share                                                                       
 
$
(0.17
)
 
$
0.55
 
                 
Diluted earnings (loss) per share of common stock:
               
  Continuing operations                                                                       
 
$
(0.17
)
 
$
0.52
 
  Discontinued operations                                                                       
   
     
(0.02
)
  Net income (loss) per common share                                                                       
 
$
(0.17
)
 
$
0.50
 
                 
Weighted average common shares outstanding:
               
  Basic                                                                         
   
103,090
     
95,052
 
  Diluted                                                                         
   
103,090
     
105,863
 
                 
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
 
 
 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
 (in thousands)
     
Three Months Ended
 
     
March 31,
 
     
2010
     
2009
 
Cash flows from operating activities:
               
  Net income (loss), including noncontrolling interests
 
$
(17,002
)
 
$
112,755
 
  Adjustments to reconcile net income (loss), including noncontrolling interests to net cash provided by operating activities
               
         Depreciation and amortization                                                                                 
   
60,827
     
82,893
 
         Asset impairment charge and dry hole expense
   
11,292
     
361
 
         Equity in earnings of investments, net of distributions
   
     
320
 
         Amortization of deferred financing costs                                                                                 
   
1,726
     
1,482
 
         Loss from discontinued operations                                                                                 
   
27
     
2,554
 
         Stock compensation expense                                                                                 
   
2,488
     
4,084
 
         Amortization of debt discount                                                                                 
   
2,068
     
1,938
 
         Deferred income taxes                                                                                 
   
(2,110
)
   
43,699
 
         Excess tax benefit from stock-based compensation
   
1,842
     
1,676
 
         Gain on sale or acquisition of assets                                                                                 
   
(6,247
)
   
(454
)
         Unrealized (gain) loss  on derivative contracts
   
3,001
     
(55,420
)
         Changes in operating assets and liabilities:
               
            Accounts receivable, net                                                                                 
   
(23,823
)
   
41,134
 
            Other current assets                                                                                 
   
30,780
     
(2,448
)
            Income tax payable                                                                                 
   
(9,513
)
   
54,518
 
            Accounts payable and accrued liabilities
   
(22,027
)
   
(51,713
)
            Other noncurrent, net                                                                                 
   
(14,865
)
   
(73,889
)
              Cash provided by operating activities                                                                                 
   
18,464
     
163,490
 
              Cash used in discontinued operations
   
(27
)
   
(1,002
)
              Net cash provided by operating activities
   
18,437
     
162,488
 
                 
Cash flows from investing activities:
               
  Capital expenditures                                                                                 
   
(68,428
)
   
(133,663
)
  Investments in equity investments                                                                                 
   
     
(320
)
  Distributions from equity investments, net                                                                                 
   
965
     
2,477
 
  Proceeds from sales of property                                                                                 
   
(4
)
   
22,481
 
              Net cash used in investing activities
   
(67,467
)
   
(109,025
)
                 
Cash flows from financing activities:
               
  Repayment of Helix Term Loan                                                                                 
   
(1,082
)
   
(1,082
)
  Repayments on Helix Revolver                                                                                 
   
     
(100,000
)
  Repayment of MARAD borrowings                                                                                 
   
(2,403
)
   
(2,081
)
  Borrowings on CDI Revolver                                                                                 
   
     
100,000
 
  Repayments on CDI Term Note                                                                                 
   
     
(20,000
)
  Deferred financing costs                                                                                 
   
(2,789
)
   
 
  Preferred stock dividends paid and other                                                                                 
   
(771
)
   
(250
)
  Repurchase of common stock                                                                                 
   
(976
)
   
(288
)
  Excess tax benefit from stock-based compensation
   
(1,842
)
   
(1,676
)
              Net cash used in financing activities                                                                                 
   
(9,863
)
   
(25,377
)
                 
Effect of exchange rate changes on cash and cash equivalents
   
398
     
(114
)
Net (decrease) increase in cash and cash equivalents
   
(58,495
)
   
27,972
 
Cash and cash equivalents:
               
  Balance, beginning of year                                                                                 
   
270,673
     
223,613
 
  Balance, end of period                                                                                 
 
$
212,178
   
$
251,585
 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.


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.   Until June 2009, Cal Dive International, Inc. (collectively with its subsidiaries referred to as “Cal Dive” or “CDI”) was a majority-owned subsidiary of Helix.  Helix sold substantially all its remaining ownership interest in Cal Dive during 2009 (see Note 4 below and Note 3 of our Annual Report on Form 10-K for the year ended December 31, 2009 (“2009 Form 10-K”)).   All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements 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 2009 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 opera tions, and cash flows, as applicable. The operating results for the period ended March 31, 2010 are not necessarily indicative of the results that may be expected for the year ending December 31, 2010. Our balance sheet as of December 31, 2009 included herein has been derived from the audited balance sheet as of December 31, 2009 included in our 2009 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our 2009 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 our own oil and gas properties. Our Contracting Services segment utilizes our vessels, offshore equipment and methodologies to deliver services that may reduce finding and development costs and encompass the complete lifecycle of an offshore oil and gas field. Our Contracting Services are located primarily in Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.  Our Oil and Gas segment engages in exploration, development and production activities. Our oil and gas operations are almost exclusively located in the Gulf of Mexico.
 
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.  Our “life of field” services are segregated into three disciplines: subsea construction, well operations and production facilities. We have disaggregated our contracting services operations into two continuing reportable segments: Contracting Services and Production Facilities. Our Contracting Services business primarily includes deepwater construction and  well operation activities.  Formerly, we had a third Contracting Service segment, Shelf Contracting, which represented the assets of CDI.  We sold substantially all our remaining ownership of CDI through various transactions in 2009 (Note 4).  Our Production Facilities busines s includes our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”), Independence Hub, LLC (“Independence Hub”) and Kommandor LLC (“Kommandor”).


 
Oil and Gas Operations
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. 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.
 
Discontinued Operations
 In April 2009, we sold Helix Energy Limited (“HEL”), our former reservoir technology consulting business, to a subsidiary of Baker Hughes Incorporated for $25 million.  As a result of the sale of HEL, which entity’s operations were conducted by its wholly owned subsidiary, Helix RDS Limited (“Helix RDS”), we have presented the results of Helix RDS as discontinued operations in the accompanying condensed consolidated financial statements (Note 3).  HEL and Helix RDS were previously components of our Contracting Services segment.
 
Business Strategy
We continue to focus on improving our balance sheet by increasing our liquidity through reductions in planned capital spending and potential additional dispositions of our non-core business assets.  During 2009, we completed the following dispositions of non-core business assets:
 
·  
Sold five oil and gas properties for approximately $24 million;
·  
Sold a total of 15.2 million shares of CDI common stock held by us to CDI for $100 million in separate transactions in January and June 2009;
·  
Sold Helix RDS Limited, our subsurface reservoir consulting business for $25 million in April 2009; and
·  
Sold a total of 45.8 million shares of CDI common stock held by us to third parties in two separate public secondary offerings for approximately $404.4 million, net of underwriting fees in June 2009 and September 2009.  For additional information regarding the sales of CDI common shares by us see Note 4.
 
 In March 2010, we announced that we have engaged advisors to assist us with evaluating potential alternatives for the complete disposition of our oil and gas business.   At the time of the filing of this Current Report on Form 10-Q we do not have an approved or definitive plan for such disposition of our oil and gas business.
 
Note 3 – Details of Certain Accounts
 
Other current assets consisted of the following as of March 31, 2010 and December 31, 2009:
 
     
March 31,
     
December 31,
 
     
2010
     
2009
 
     
(in thousands)
 
Other receivables
 
$
2,208
   
$
7,990
 
Prepaid insurance
   
6,334
     
11,105
 
Other prepaids
   
13,100
     
21,819
 
Restricted cash (Notes 6 and 7)
   
10,000
     
 
Inventory
   
25,108
     
25,755
 
Current deferred tax assets
   
10,980
     
24,517
 
Hedging assets
   
30,491
     
6,214
 
Gas imbalance
   
7,289
     
7,655
 
Income tax receivable
   
17,201
     
8,492
 
Assets of discontinued operations
   
829
     
878
 
Other
   
5,950
     
7,784
 
   
$
129,490
   
$
122,209
 
 


 
 
Other assets, net, consisted of the following as of March 31, 2010 and December 31, 2009:
 
     
March 31,
     
December 31,
 
     
2010
     
2009
 
     
(in thousands)
 
Restricted cash
 
$
35,405
   
$
35,409
 
Deferred drydock expenses, net
   
15,401
     
12,030
 
Deferred financing costs
   
31,228
     
30,061
 
Intangible assets with finite lives, net
   
754
     
768
 
Other
   
3,146
     
3,945
 
   
$
85,934
   
$
82,213
 
 
Accrued liabilities consisted of the following as of March 31, 2010 and December 31, 2009:
 
     
March 31,
     
December 31,
 
     
2010
     
2009
 
     
(in thousands)
 
Accrued payroll and related benefits
 
$
18,291
   
$
30,513
 
Royalties payable
   
10,179
     
5,717
 
Asset retirement obligation
   
76,804
     
65,729
 
Unearned revenue
   
3,617
     
3,672
 
Accrued interest
   
15,828
     
27,830
 
Billing in excess of cost
   
6,838
     
 
Deposit
   
25,542
     
25,542
 
Hedge liability
   
24,489
     
19,536
 
Liabilities of discontinued operations
   
176
     
451
 
Other
   
20,717
     
21,617
 
   
$
202,481
   
$
200,607
 
 
Note 4 — Ownership of Cal Dive International, Inc.
 
In January 2009, we sold approximately 13.6 million shares of Cal Dive common stock to Cal Dive for $86 million.  This transaction constituted a single transaction and was not part of any planned set of transactions that would result in us having a noncontrolling interest in Cal Dive, and reduced our ownership in Cal Dive to approximately 51%.  Because we retained control of CDI immediately after the transaction, the loss of approximately $2.9 million on this sale was treated as a reduction of our equity.
 
In June 2009, we sold 22.6 million shares of Cal Dive common stock held by us pursuant to a secondary public offering (“Offering”) and Cal Dive repurchased an additional 1.6 million shares from us of its common stock.  Following the closing of these two transactions, our ownership of Cal Dive common stock was reduced to approximately 26%.   Since we no longer held a controlling interest in Cal Dive, we ceased consolidating Cal Dive effective June 10, 2009, and subsequently accounted for our remaining ownership interest in Cal Dive under the equity method of accounting until September 2009, when we sold substantially all our remaining interest in Cal Dive.
 
We continue to own 0.5 million shares of Cal Dive common stock, representing  less than 1% of the total outstanding shares of Cal Dive.  Accordingly we now classify our remaining interest in Cal Dive as an investment available for sale pursuant to ASC Topic No. 320  “Investment  - Debt and Equity Securities.”  As an investment available for sale, the value of our remaining interest will be marked-to-market at each period end with the corresponding change in value being reported as a component of other comprehensive income (loss) in the accompanying condensed consolidated balance sheets (Note 11).   The value of our remaining investment in Cal Dive as of March 31, 2010 has decreas ed $0.1 million since December 31, 2009 and $1.3 million since our Cal Dive sales transaction in September 2009.
 
See Note 3 of our 2009 Form 10-K for additional information regarding our sale transactions involving Cal Dive common stock in 2009.


 
Note 5 – Convertible Preferred Stock
 
In January 2009, Fletcher International, Ltd. (“Fletcher”) issued a redemption notice with respect to its $30 million of the Series A-2 Cumulative Convertible Preferred Stock, and, pursuant to such redemption, we issued and delivered 5,938,776 shares of our common stock to Fletcher.  Accordingly, in the first quarter of 2009 we recognized a $29.3 million charge to reflect the terms this redemption, which was recorded as a reduction in our net income applicable to common shareholders.  This beneficial conversion charge reflected the value associated with the additional 3,974,718 shares delivered over the original 1,964,058 shares that would have been contractually required to be issued upon a conversion but was limited to the $29.3 million of net proceeds we received from the issuance of the Series A-2 Cumulative Con vertible Preferred Stock in June 2004.
 
In February 2009, the price of our common stock fell below $2.767 per share.  Under terms of the agreement governing the issuance of the cumulative convertible  preferred stock, we provided notice to Fletcher that with respect to the $25 million of Series A-1 Cumulative Convertible Preferred Stock the conversion price was reset to $2.767, the established minimum price per the agreement, and that Fletcher shall have no further rights to redeem the shares, and we have no further right to pay dividends in common stock.  As a result of the reset of the conversion price, Fletcher would receive an aggregate of 9,035,056 shares in future conversion(s) into our common stock. In the event we elect to settle any future conversion in cash, Fletcher would receive cash in an amount approximately equal to the value of the shares it would receive upon a conversion, which could be substantially greater than the original face amount of the Series A-1 Cumulative Convertible Preferred Stock, and which would result in additional beneficial conversion charges in our statement of operations. Under the existing terms of our Senior Credit Facilities (Note 9) we are not permitted to deliver cash to the holder upon a conversion of the Convertible Preferred Stock.
 
In connection with the reset of the conversion price of the Series A-1 Cumulative Convertible Preferred Stock to $2.767, we were required to recognize a $24.1 million charge to reflect the value associated with the additional 7,368,388 shares that will be required to be delivered upon any future conversion(s) over the 1,666,668 shares that were to be delivered under the original contractual terms.  This $24.1 million charge was recorded as a beneficial conversion charge reducing our net income applicable to common shareholders.  The beneficial conversion charge for the Series A-1 Cumulative Convertible Preferred Stock is limited to the $24.1 million of net proceeds received upon its issuance in January 2003.
 
In the third quarter of 2009, Fletcher converted $19 million of its Series A-1 Cumulative Convertible Preferred Stock into 6,866,641 shares of our common stock.   The remaining $6 million of the Series A-1 Cumulative Convertible Preferred Stock, which is convertible into 2,168,413 shares of our common stock, maintains its mezzanine presentation below liabilities but is not included as component of shareholders’ equity, because we may, under certain instances be required to settle any future conversions in cash.   Prior to any future conversion(s), the common shares issuable will be assessed for inclusion in our diluted earnings per share computations using the if converted method based on the applicable conversion price of $2.767 per share, meaning that for all periods in which we have positive earnings from con tinuing operations and our average stock price exceeds $2.767 per share we will have an assumed conversion of convertible preferred stock and the 2,168,413 shares will be included in our diluted shares outstanding amount.
 
Note 6 – Oil and Gas Properties
 
In March 2010, we announced that we engaged advisors to assist us with evaluating potential alternatives for the complete disposition of our oil and gas business.   At the time of the filing of this Current Report on Form 10-Q we do not have an approved or definitive plan for such disposition of our oil and gas business.
 
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 charged to expense in the period in which the drilling is determined to be unsuccessful.
 
 
 
Depletion expense is determined on a field-by-field basis using the units-of-production method, with depletion rates for leasehold acquisition costs based on estimated total remaining proved reserves.  Depletion rates for well and related facility costs are based on estimated total remaining proved developed reserves associated with each individual field.  The depletion rates are changed whenever there is an indication of the need for a revision but, at a minimum, are evaluated annually.  Any such revisions are accounted for prospectively as a change in accounting estimate.
 
Exploration and Other
 
As of March 31, 2010, we capitalized approximately $3.2 million of 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 details the components of exploration expense for the three months ended March 31, 2010 and 2009:
 
     
Three Months Ended
 
     
March 31,
 
     
2010
     
2009
 
     
(in thousands)
 
Delay rental and geological and geophysical costs
 
$
346
   
$
472
 
Dry hole expense
   
(180
)
   
4
 
     Total exploration expense
 
$
166
   
$
476
 
 
Impairments
 
In the first quarter of 2010, we recorded $7.0 million of impairment charges primarily resulting from natural gas price declines since year end 2009.   The three affected U.S. Gulf of Mexico properties comprising our impairment expense produce primarily natural gas.   Separately, we also recorded a $4.1 million impairment charge for our only non-domestic oil and gas property (see “United Kingdom Property” below).  There were no impairment charges in the first quarter of 2009.   Impairment expense is recorded as a component of depletion expense, which is reflected as cost of sales in the accompanying condensed consolidated statements of operations.
 
MMS Royalty Claims
 
We and other industry participants were involved in a dispute with the U.S. Department of the Interior Minerals Management Service (“MMS”) over royalties associated with production from certain deepwater oil and gas leases.   As a result of this dispute, we recorded reserves for the disputed royalties (and any other royalties that may be claimed for production during 2005, 2006, 2007 and 2008) plus interest at 5% for our portion the MMS claim, which affected our Garden Banks Blocks 667, 668 and 669 (“Gunnison”) leases.  The result of accruing these reserves since 2005 had reduced our oil and gas revenues.  In the first quarter of 2009, following the decision of the United States Court of Appeals for the Fifth Circuit Court affirming the district court’s previous ruling in f avor of the plaintiffs in that case, we reversed our previously accrued royalties ($73.5 million) to oil and gas revenues.  On October 5, 2009, the United States Supreme Court denied the government’s petition for a writ of certiorari, and, based on this the MMS subsequently withdrew its orders to pay the royalty.
 
For additional information regarding our MMS royalty dispute and related litigation see Note 17 of our 2009 Form 10-K.
 
United Kingdom Property
 
Since 2006, we have maintained an ownership interest in the Camelot field, located offshore in the North Sea.   In 2007, we sold half of our 100% working interest in Camelot to a third party with whom we agreed to jointly pursue future development and production of the field.   In February 2010, we acquired this third-party by agreeing to assume the obligations, most notably the asset retirement obligation, related to its 50% working interest in the field.   The following table contains the fair value of
 
 
8

 
the assets acquired and liabilities assumed in our acquisition of this third party and its 50% working interest in the Camelot field (in thousands):
 
Cash (a)                                                                               
 
$
10,156
 
Deferred tax asset                                                                               
   
2,083
 
Accrued liabilities                                                                               
   
(438
)
Accrued reclamation obligation                                                                               
   
(5,841
)
Gain on acquisition of assets                                                                                
 
$
5,960
 
 
a)  
At March 31, 2010, $10.0 million of this amount remains held in an escrow account and is restricted for future use to fund the asset retirement costs associated with Camelot field.  This amount is reflected in other current assets in the accompanying condensed consolidated balance sheet (Note 3).  The current classification of both the restricted funds and the related asset retirement reflect the probable near-term of these activities occurring.
 
In connection with the valuation of assets acquired and liabilities assumed in this acquisition, we reassessed the fair value associated with our original 50% interest in the field.    Based on these evaluations, it was concluded that Camelot was impaired based on the unlikely probability of our further expending  the capital necessary to further develop the field and our plans are to abandon the field over the near term.  As a result, we recorded a $4.1 million impairment charge to fully impair the property.   Accordingly, in our future estimates of proved reserves we will no longer consider the reserves associated with this field as proved but rather deem them as probable reserves.
 
Property Sales
 
In the first quarter of 2009, we sold our interest in East Cameron Block 316 for gross proceeds of approximately $18 million.   We recorded an approximate $0.7 million gain from the sale of East Cameron Block 316 which was partially offset by the loss on the sale of the remaining 10% of our interest in the Bass Lite field at Atwater Block 426 in January 2009.
 
Asset retirement obligations
 
The following table describes the changes in our asset retirement obligations (both long term and current) since December 31, 2009 (in thousands):
 
Asset retirement obligation at December 31, 2009
 
$
248,128
 
Liability incurred during the period (a)                                                                               
   
5,907
 
Liability settled during the period                                                                               
   
(4,495
)
Revision in estimated cash flows                                                                               
   
1,704
 
Accretion expense (included in depreciation and amortization)
   
3,931
 
Asset retirement obligations at March 31 2010
 
$
255,175
 
 
a)  
Amount primarily associated with the acquisition of the remaining 50% working interest in the Camelot field in February 2010 (see “United Kingdom Property” above).
 
Insurance
 
In September 2008, we sustained damage to certain of our oil and gas production facilities from Hurricanes Gustav and Ike.  While we sustained some damage to our own production facilities from Hurricane Ike, the larger issue in terms of production recovery involved damage to third party pipelines and onshore processing facilities.  We carried comprehensive insurance on all of our operated and non-operated producing and non-producing properties.  We record our hurricane-related costs as incurred. Insurance reimbursements were recorded when th e realization of the claim for recovery of a loss is deemed probable.  In the first quarter of 2010, we incurred $2.1 million of hurricane-related repair costs compared to $12.7 million in the first quarter of 2009.   The first quarter of 2009 costs were partially offset by reimbursements or approved reimbursements of $3.1 million.    See Note 4 of our 2009 Form 10-K for information regarding our settlement with the insurance underwriters in June 2009.


 
Note 7 – 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.  We had restricted cash totaling $45.4 million at March 31, 2010 and $35.4 million at December 31, 2009.  The $10.0 million increase in our restricted cash from the year end 2009 amount reflects the escrowed funds we acquired in the Camelot acquisition in February 2010 (Note 6).  This amount is reflected in other current assets in the accompanying condensed consolidated balance sheet at March 31, 2010.  The remaining $35.4 million of restricted cash relates entirely to funds required to be escrowed to cover the future asset retirement obl igations associated with our South Marsh Island 130 field.  We have fully satisfied the escrow requirements under this agreement and may use the restricted cash for the future asset retirement costs of the related field.  These amounts are reflected in other assets, net in the accompanying condensed consolidated balance sheets.
 
The following table provides supplemental cash flow information for the three months ended March 31, 2010 and 2009 (in thousands):
 
     
Three Months Ended
 
     
March 31,
 
     
2010
     
2009
 
                 
Interest paid, net of capitalized interest(1)
 
$
23,737
   
$
33,372
 
Income taxes paid
 
$
4,357
   
$
30,928
 
 
 
Non-cash investing activities for the three-month periods ended March 31, 2010 and 2009 included $48.2 million and $88.4 million, respectively, of accruals for capital expenditures.  The accruals have been reflected in the condensed consolidated balance sheet as an increase in property and equipment and accounts payable.
 
Note 8 – Equity Investments
    
As of March 31, 2010, we have the following material investments, both of which are included within our Production Facilities segment and 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 $102.1 million and $103.3 million as of March 31, 2010 and December 31, 2009, respectively (including capitalized interest of $1.5 million at March 31, 2010 and Decemb er 31, 2009).  Distributions from Deepwater Gateway, net to our interest, totaled $2.3 million in the first quarter of 2010.
 
·  
Independence Hub, LLC.  In December 2004, we acquired a 20% interest in Independence Hub, an affiliate of Enterprise.  Independence Hub owns the "Independence Hub" platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet.  First production through the facility commenced in July 2007.  Our investment in Independence Hub was $86.2 million and $86.1 million as of March 31, 2010 and December 31, 2009, respectively (including capitalized interest of $5.5 million and $5.6 million at March 31, 2010 and December 31, 2009, respectively).  Distributions from Independence Hub, net to our interest, totaled $4.9 million in the first quarter of 2010.


 
The following presents selected summarized unaudited operating results for our Deepwater Gateway and Independence Hub equity investments for the three month periods ended March 31, 2010 and 2009
 
   
Deepwater Gateway
   
Independence Hub
   
Combined
 
   
2010
   
2009
   
2010
   
2009
   
2010
   
2009
 
Revenues
  $ 4,318     $ 6,642     $ 29,182     $ 33,616     $ 33,500     $ 40,258  
Operating income
    2,238       3,623       25,610       30,025       27,848       33,648  
Net income
    2,238       3,631       25,610       30,037       27,848       33,668  
                                                 
Equity in earnings
  $ 1,119     $ 1,816     $ 5,122     $ 6,007     $ 6,241     $ 7,823  
 
See Note 16 for information about our consolidated Kommandor LLC joint venture, which represents the remainder of our Production Facilities segment.
 
In February 2010, we announced the formation of a joint venture with Australian-based engineering and construction company, Clough Projects Australia Pty Ltd (“Clough”), to provide a range of subsea services to offshore operators in the Asia Pacific region. Services provided by the joint venture, named Clough Helix JV Co., will include subsea well intervention and well abandonment, SURF (subsea infrastructure, umbilical, riser and flowline installation), saturation and air diving and subsea inspection, repair and maintenance services. The Clough Helix joint venture will integrate our well intervention equipment with Clough’s new 12 man saturation diving system, to enable both to be deployed from the 118 meter long DP2 multiservice vessel, Normand Clough, outfitted with a 250 ton active heave compensated crane.   We recorded a $1.4 million loss associated with our 50% interest in the joint venture in the first quarter of 2010.   The loss primarily represented the mobilization costs of transporting the Normand Clough from the Gulf of Mexico to Singapore where it is being prepared for the joint venture’s initial project.  This joint venture is part of our Contracting Services segment.
 
 
Note 9 – Long-Term Debt
 
Scheduled maturities of long-term debt and capital lease obligations outstanding as of March 31, 2010 were as follows (in thousands):
 
     
Helix Term Loan
   
Helix Revolving Loans
   
Senior Unsecured Notes
   
Convertible Senior Notes (1)
   
MARAD Debt
   
Other(2)
   
Total
 
                                             
Less than one year
 
$
4,326
 
$
 
$
 
$
 
$
4,533
 
$
2,975
 
$
11,834
 
One to two years
   
4,326
   
   
   
   
4,760
   
   
9,086
 
Two to three years
   
4,326
   
   
   
   
4,997
   
   
9,323
 
Three to four years
   
400,707
   
   
   
   
5,247
   
   
405,954
 
Four to five years
   
   
   
   
   
5,508
   
   
5,508
 
Over five years
   
   
   
550,000
   
300,000
   
92,005
   
   
942,005
 
Total debt
   
413,685
   
   
550,000
   
300,000
   
117,050
   
2,975
   
1,383,710
 
Current maturities
   
(4,326
)
 
   
   
   
(4,533
)
 
(2,975
)
 
(11,834
)
Long-term debt, less
   current maturities
 
$
409,359
 
$
 
$
550,000
 
$
300,000
 
$
112,517
 
 
$
 
 
$
1,371,876
 
Unamortized debt discount (3)
   
   
   
   
(24,869
)
 
   
   
(24,869
)
Long-term debt
 
$
409,359
 
$
 
$
550,000
 
$
275,131
 
$
112,517
 
 
$
 
 
$
1,347,007
 
                                             
(1)  
Beginning in December 2012, the holders may require us to repurchase the notes or we may at our own option elect to repurchase notes. Notes will not mature until March 2025.
(2)  
Represents the balance of the loan provided by Kommandor RØMØ to Kommandor LLC as March 31, 2010.
(3)  
Reflects debt discount resulting from adoption of new provisions of ASC Topic No. 470-20 “Convertible Debt and Other Options” on January 1, 2009.  The notes will increase to $300 million face amount through accretion of non-cash interest charges through 2012.


 
At March 31, 2010, unsecured letters of credit issued totaled approximately $49.5 million (see “Credit Agreement” below).  These letters of credit primarily guaranty various contract bidding, contractual performance, including asset retirement obligations, and insurance activities.  The following table details our interest expense and capitalized interest for the three months ended March 31, 2010 and 2009:
 
     
Three Months Ended
 
     
March 31,
 
     
2010
     
2009
 
     
(in thousands)
 
Interest expense
 
$
26,057
   
$
29,850
 
Interest income
   
(1,906
)
   
(264
)
Capitalized interest
   
(8,516
)
   
(7,620
)
     Interest expense, net
 
$
15,635
   
$
21,966
 
 
Included below is a summary of certain components of our indebtedness. At March 31, 2010 and December 31, 2009, we were in compliance with all debt covenants.  For additional information regarding our debt see Note 10 of our 2009 Form 10-K.
 
Senior Unsecured Notes
 
In December 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 Cal Dive I-Title XI, Inc.  In addition, any future restricted domestic subsidiaries that guarantee any of our indebtedness and/or our restricted subsidiaries’ indebtedness are required to guarantee the Senior Unsecured Notes.  Our foreign subsidiaries are not guarantors.  We used the proceeds from the Senior Unsecured Notes to repay outstanding indebtedness under our Credit Agreement (see below) .
 
Credit Agreement
 
In July 2006, we entered into a credit agreement (the “Credit Agreement”) under which we borrowed $835 million in a term loan (the “Term Loan”) and were initially able to borrow up to $300 million (the “Revolving Loans”) under a revolving credit facility (the “Revolving Credit Facility”).  The Term Loan is scheduled to mature in July 1, 2013.  The proceeds from the Term Loan were used to fund the cash portion of the acquisition of Remington Oil and Gas Corporation in July 2006. The original maturity date of the Credit Agreement was July 1, 2011. The Term Loan currently bears interest either at the one-, three- or six-month LIBOR at our election plus a margin of between 2.25% and 2.5% depending on current leverage ratios.  Our average interest rate on the Term Loan f or the three months ended March 31, 2010 and 2009 was approximately 2.8% and 5.0%, respectively, including the effects of our interest rate swaps.
 
 As of December 31, 2009, the Credit Agreement had been amended twice since its inception, with the most recent amendment occurring in October 2009.  Borrowing availability under the Revolving Credit facility was $435 million at December 31, 2009 (decreasing to $410 million beginning July 1, 2011 through November 30, 2012).  The October amendment extended the maturity of the Revolving Credit Facility to November 30, 2012.   The full amount of the Revolving Credit Facility may be used for issuances of letters of credit.  At March 31, 2010, we had no amounts drawn on the Revolving Credit Facility and our availability under the Revolving Credit Facility totaled $385.5 million, net of $49.5 million of unsecured letters of credit issued.  The Revolving Loans bear interest based on one-, three- or six-month LIBOR rates or on Base Rates at our election plus an applicable margin. The margin ranges from 1.0% to 4.5%, depending on our consolidated leverage ratio and on whether the lender to whom interest is payable has extended the maturity of its portion of the Revolving Credit Facility to November 30, 2012. We did not have any borrowings under our Revolving Loans in the three months ended March 31, 2010.  Our average interest rate on the Revolving Loans for the three months ended March 31, 2009 was approximately 3.4%.


 
In February 2010, we again amended our Credit Agreement.  This amendment:
 
·  
changed the consolidated leverage ratio that we are required to comply with. Through December 31, 2009, the maximum permitted leverage was 3.50 to 1.00. Beginning with the quarter ending March 31, 2010, the ratio is now as follows:
 
o  
March 31, 2010 – 5.00 to 1.00
 
o  
June 30, 2010 – 5.50 to 1.00
 
o  
September 30, 2010 – 5.00 to 1.00
 
o  
December 31, 2010 – 4.50 to 1.00
 
o  
March 31, 2011 and thereafter – 4.00 to 1.00
 
·  
added a new Credit Agreement leverage ratio we are required to comply with beginning with the quarter ending March 31, 2010. This ratio is a measure of our senior funded indebtedness that is secured by a lien on our property against consolidated EBITDA for the trailing four quarters.  The ratio will be as follows:
 
o  
March 31 and June 30, 2010 – 2.50 to 1.00
 
o  
September 30, 2010 – 2.25 to 1.00
 
o  
December 31, 2010 and thereafter – 2.00 to 1.00
 
·  
increased the margin on Revolving Loans by 0.50% should our consolidated leverage ratio equal or exceed  4.50 to 1.00, and increased the margin on the Term Loan by 0.25% if our consolidated leverage ratio is less than 4.50 to 1.00 and by 0.50% if the consolidated leverage ratio is equal to or greater than 4.50 to 1.00.
 
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.  In January 2010, we entered into $200 million, two-year interest rate swaps to stabilize cash flows relating to a portion of our interest payments on our Term Loan (Note 18).

Convertible Senior Notes
 
In March 2005, we issued $300 million of our Convertible Senior Notes at 100% of the principal amount to certain qualified institutional buyers.  The Convertible Senior Notes are convertible into cash and, if applicable, shares of our common stock based on the specified conversion rate, subject to adjustment.
 
The Convertible Senior Notes can be converted prior to the stated maturity (March 2025) 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.  No conversion triggers were met during the three-month period ended March 31, 2010. The first dates for early redemption of the Convertible Senior Notes are in December 2012, with the holders of the Convertible Senior Notes being able to put them to us on December 15, 2012 and our being able to call the Convertible Senior Notes at any time after December 20, 2012 (see Note 10 of our 2009 Form 10-K).   Effective January 1, 2009 we adopted cert ain new required standards within ASC Topic No. 470-20 “Debt with Conversion and Other Options”, which required us to discount the principal amount of our Convertible Senior Notes (see Note 2 of our 2009 Form 10-K). Following adoption of these standards, the effective interest rate for the Convertible Senior Notes is 6.6%.
 
Our average share price for the both the first quarter of 2010 and 2009 was below the $32.14 per share conversion price.  As a result of our share price being lower than the $32.14 per share conversion price for these periods there are no shares included in our diluted earnings per share calculation associated with the assumed conversion of our Convertible Senior Notes.  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 Convertible Senior Notes are convertible into a maximum 13,303,770 shares of our common stock.

MARAD Debt
 
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 and was used to finance the  construction of the Q4000. 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 yield s 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).
 
Other
 
In accordance with our Credit Agreement and our Senior Unsecured Notes, Convertible Senior Notes and MARAD Debt agreements, we are required to comply with certain covenants and restrictions, including the maintenance of minimum net worth, working capital and debt-to-equity requirements.  As of March 31, 2010, we were in compliance with these covenants and restrictions.  The Senior Unsecured Notes and Credit Agreement contain provisions that limit our ability to incur certain types of additional indebtedness.
 
Deferred financing costs of $31.2 million and $30.1 million are included in other assets, net as of March 31, 2010 and December 31, 2009, respectively, and are being amortized over the life of the respective loan agreements.
 
Note 10 – Income Taxes
 
     The effective tax rate for the three months ended March 31, 2010 was 30.8% compared with 36.0% for the three months ended March 31, 2009. The effective tax rate for the first quarter of 2010 decreased as a result of the deconsolidation of CDI in 2009 and the increased benefit derived from the effect of lower tax rates in certain 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.
 
Note 11 – Comprehensive Income
 
The components of total comprehensive income for the three months ended March 31, 2010 and 2009 were as follows (in thousands):
 
   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
             
Net income (loss), including noncontrolling interests
  $ (17,002 )   $ 112,755  
Other accumulated  comprehensive income (loss),
    net of tax
               
     Foreign currency translation loss
    (10,702 )     (3,619 )
     Unrealized gain (loss) on hedges, net
    14,040       (4,464 )
     Unrealized loss on investment available for sale
    (75 )  
 
Total  accumulated comprehensive income (loss)
    (13,739     104,672  
Less: Other accumulated comprehensive income (loss) applicable to noncontrolling interest
 
      (5,546 )
Total accumulated comprehensive income (loss) applicable to Helix
  $ (13,739 )   $ 99,126  
 


 
The components of accumulated other comprehensive loss were as follows (in thousands):
 
   
March 31,
 
December 31,
   
2010
 
2009
                 
Cumulative foreign currency translation adjustment
 
$
(22,959
)
 
$
(12,257
)
Unrealized gain (loss) on hedges, net
   
4,943
     
(9,097
)
Unrealized loss on investment available for sale
   
(962
)
   
(887
)
     Accumulated other comprehensive loss
 
$
(18,978
)
 
$
(22,241
)
 
Note 12 – Earnings Per Share
 
We have shares of restricted stock issued and outstanding, some of which remain subject to certain vesting requirements.   Holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding common stock and are thus considered participating securities.   Under this applicable guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and holders of any participating securities as if earnings for the respective periods had been distributed. & #160; Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis.  Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings from continuing operations.  For periods in which we have a net loss we do not use the two class method as holders of our restricted shares are not contractually obligated to share in such losses.
 
Basic 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, 2010 and 2009 follows (in thousands):
 
     
Three Months Ended
     
Three Months Ended
 
     
March 31, 2010
     
March 31, 2009
 
     
Income
     
Shares
     
Income
     
Shares
 
Basic:
                               
Net income (loss) applicable to common shareholders
 
$
(17,891
)
         
$
53,450
         
Less: Undistributed net income allocable to participating securities
   
             
(884
)
       
Undistributed net income (loss)  applicable to common shareholders
   
(17,891
)
           
52,566
         
(Income) loss from discontinued operations
   
27
             
2,554
         
Income (loss) per common share – continuing operations
 
$
(17,864
)
   
103,090
   
$
55,120
     
95,052
 
 
     
Three Months Ended
March 31, 2010
     
Three Months Ended
March 31, 2009
 
             
     
Income
     
Shares
     
Income
     
Shares
 
Diluted:
                               
Net  income (loss) per common share –
continuing operations – Basic
 
$
(17,864
)
         
$
55,120
     
95,052
 
Effect of dilutive securities:
                               
Stock options                                                                
   
     
     
     
 
Undistributed earnings reallocated to participating securities
                   
89
     
 
Convertible Senior Notes                                                                
   
     
     
     
 
Convertible preferred stock                                                                
   
     
     
313
     
10,811
 
Income  (loss) per common share ─
continuing operations                                                                
   
(17,864
)
           
55,522
         
Income (loss) per common share ─ discontinued operations
   
(27
)
           
(2,554
)
       
Net income (loss) per common share
 
$
(17,891
)
   
103,090
   
$
52,968
     
105,863
 
                                 
 
We had a net loss from continuing operations during the three-month period ended March 31, 2010.  Accordingly, we had no dilutive securities during this reporting period as their inclusion would have an anti-dilutive effect on our EPS calculation, meaning it would increase our reported EPS amount. The following table provides the effect the excluded securities would have had on our diluted shares calculation for the three months ended March 31, 2010 assuming we had earnings from continuing operations (in thousands):
 
Diluted shares (as reported)
   
103,090
 
Stock options
   
194
 
Convertible preferred stock
   
2,168
 
Total
 
$
105,452
 
 
There were no dilutive stock options in the three months ended March 31, 2009 as the option strike price was below the average market price for the period ($5.22 per share).   The diluted EPS amount included the $0.1 million and $0.3 million of dividends and related costs associated with the assumed conversion of the convertible preferred stock for the three months ended March 31, 2010 and 2009, respectively.   The cumulative $53.4 million of beneficial conversion charges that were realized and recorded during the first quarter of 2009 following the transaction affecting our convertible preferred stock (Note 5) are not included as a positive adjustment to earnings applicable to common stock for our diluted earnings per share calculation.
 
Note 13 – Stock-Based Compensation Plans
 
We have two stock-based compensation plans: the 1995 Long-Term Incentive Plan, as amended (the “1995 Incentive Plan”) and the 2005 Long-Term Incentive Plan, as amended (the “2005 Incentive Plan”).  As of March 31, 2010, there were approximately 1.3 million shares available for grant under our 2005 Incentive Plan.
 
During the three months ended March 31, 2010, 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:
 
Date of Grant
 
Type
   
Shares
   
Market Value Per Share
 
Vesting Period
                     
January 4, 2010
    (1 )     452,849     $ 11.75  
20% per year over five years
January 4, 2010
    (2 )     23,569       11.75  
20% per year over five years
January 4, 2010
    (1 )     1,197       11.75  
100% on January 1, 2012
 
(1)  
Restricted shares
(2)  
Restricted stock units
 
There were no stock option grants in the three months ended March 31, 2010 and 2009.
 
Compensation cost is recognized over the respective vesting periods on a straight-line basis.  There was no compensation cost associated with stock options for the three months ended March 31, 2010 as all outstanding stock options have vested.   We recorded $0.1 million of compensation expense related to stock options in first quarter of 2009.   For the three months ended March 31, 2010, $2.5 million was recognized as compensation expense related to restricted shares as compared with $4.0 million during the three months ended March 31, 2009, including $1.7 million related to CDI and its compensation plans.
 
In January 2009, we adopted the 2009 Long-Term Incentive Cash Plan (the “2009 LTI Plan”) to provide long term cash based compensation to eligible employees.  Under the terms of the 2009 LTI Plan, the majority of the cash awards are fixed sum amounts payable over a five year vesting period.  However, some of the cash awards are indexed to our Company common stock and the payment amount will fluctuate based on the common stock’s performance. This share based component is considered a liability plan under the guidance of ACS Topic No. 718 “Compensation – Stock


 
Compensation” and as such is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as appropriate.
 
The total awards made under the 2009 LTI Plan totaled $14.7 million in 2009, including $8.1 million for our executive officers, which vest over a five year period.  In January 2010, $10.1 million was awarded under the 2009 LTI Plan to eligible employees, including $6.0 million to our executive officers and other members of senior management.  Total compensation under 2009 the LTI plan totaled $1.9 million and $0.7 million for the three months ended March 31, 2010 and 2009, respectively.
 
For more information regarding our stock-based compensation plans, including our 2009 LTI Plan see Note 13 of our 2009 Form 10-K.
 
Note 14 – Business Segment Information
 
Our operations are conducted through the following lines of business: contracting services operations and oil and gas operations. We have disaggregated our contracting services operations into two continuing reportable segments in accordance with ASC Topic No  280 “Segment Reporting”: Contracting Services and Production Facilities.  As a result, our reportable segments consisted of the following: Contracting Services and Oil and Gas and Production Facilities. Contracting Services operations include deepwater pipelay, well operations and robotics.  Formerly, we had a third contracti ng services business, Shelf Contracting, which consisted of CDI’s operations, and which included all assets deployed primarily for diving-related activities and shallow water construction. On June 10, 2009, we ceased consolidating CDI when our remaining ownership interest decreased to below 50% following the sale of a portion of CDI common stock held by us (Note 4).  We continued to disclose the results of Shelf Contracting business as a segment up to and through June 10, 2009.  All material intercompany transactions between the segments have been eliminated.
 
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 (Deepwater Gateway and Independence Hub) is accounted for under the equity method of accounting. We consolidate our investment in Kommandor and its results are included within our Production Facilities segment.
 
   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
   
(in thousands)
 
Revenues ─
           
      Contracting Services
  $ 154,200     $ 230,855  
      Shelf Contracting
 
      207,053  
      Oil and Gas (1) 
    90,715       160,181  
      Production Facilities
    1,320    
 
      Intercompany elimination
    (44,665 )     (27,114 )
            Total
  $ 201,570     $ 570,975  
 
   
Three Months Ended
 
   
March 31,
 
   
2010
     
2009
 
   
(in thousands)
 
Income (loss) from operations ─
             
      Contracting Services
$
27,486
   
$
39,748
 
      Shelf Contracting
 
     
20,932
 
      Production Facilities equity investments(2)
 
(37
)
   
(134
)
      Oil and Gas (1) 
 
(664
)
   
145,183
 
      Corporate (3) 
 
(22,878
)
   
(10,519
)
      Intercompany elimination
 
(12,305
)
   
(290
)
            Total
$
(8,398
)
 
$
194,920
 
               
Equity in earnings of equity investments
$
5,055
   
$
7,503
 
 
 
17

 
(1)  
Included $73.5 million of disputed accrued royalty payments that we reversed in first quarter of 2009 following a favorable court ruling (Note 6).
(2)  
Included selling and administrative expense of Production Facilities incurred by us.
(3)  
Includes $13.8 million settlement of third party claim against us in March 2010 (Note 16).
 
 
   
March 31,
2010
 
December 31,
2009
     
(in thousands)
 
Identifiable Assets ─
               
      Contracting Services                                                                           
 
$
1,669,228
   
$
1,738,005
 
      Production Facilities                                                                           
   
523,136
     
499,497
 
      Oil and Gas                                                                           
   
1,537,754
     
1,541,153
 
      Assets of discontinued operations                                                                        
   
829
     
878
 
            Total                                                                           
 
$
3,730,947
   
$
3,779,533
 
 
Intercompany segment revenues during the three months ended March 31, 2010 and 2009 were as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
   
(in thousands)
 
Contracting Services
  $ 43,741     $ 23,903  
Production Facilities
    924    
 
Shelf Contracting
 
      3,211  
            Total
  $ 44,665     $ 27,114  
 
Intercompany segment profits during the three months ended March 31, 2010 and 2009 were as follows:
 
   
Three Months Ended
 
   
March 31,
 
   
2010
   
2009
 
   
(in thousands)
 
Contracting Services
  $ 11,442     $ (104 )
Production Facilities
    880    
 
Shelf Contracting
 
      394  
            Total
  $ 12,322     $ 290  
 
 
Note 15 – Related Party Transactions
 
In April 2000, we acquired a 20% working interest in Gunnison, a Deepwater Gulf of Mexico prospect.  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 80.4% of the partnership. In 2000, OKCD also awarded Class B income participations to key Helix employees.  Production began in December 2003. Our paymen ts to OKCD totaled $3.0 million and $2.7 million for the three months ended March 31, 2010 and 2009, respectively.
 
Note 16 – Commitments and Contingencies
 
Commitments
 
We completed the conversion of the Caesar (acquired in January 2006 for $27.5 million in cash) into a deepwater pipelay vessel. We are completing the final capital upgrades to the vessel.  Total capitalized  costs for the vessel when complete are estimated to range between $290 million and $300 million (including capitalized interest of approximately $25 million), of which approximately $273.1 million had been incurred, with an additional $4.9 million committed, at March 31, 2010.  The Caesar is expected to join our fleet in the second quarter of 2010.
 
 
Further, we, along with Kommandor Rømø, a Danish corporation, formed a joint venture company called Kommandor and converted a ferry vessel into a floating production unit, the Helix Producer I. The total cost of the ferry and the conversion was approximately $150 million. We provided $98.9 million in interim construction financing to the joint venture.  During 2009, $58.8 million of this amount was converted to equity in our investment in Kommandor.  Kommandor Rømø provided a $5.0 million loan to Kommandor, the remaining balance of which was $3.0 million at March 31, 2010.
 
Upon completion of the initial conversion, which occurred in April 2009, we chartered the Helix Producer I from Kommandor, and have installed, at 100% our cost, processing facilities and a disconnectable fluid transfer system on the Helix Producer I for use on our Phoenix field. The cost of these additional facilities is estimated to range between $200 million and $210 million (including capitalized interest of $17 million) and the work is expected to be completed in the second quarter of 2010.  As of March 31, 2010, approximately $338 million of costs related to the purchase of the Helix Producer I ($20 million), conversion of the Helix Producer I and construction of the additional facilities had been incurred, with an additional $8.3 million committed.  The total estimated cost of the vessel, initial conversion and the additional facilities will range approximately between $350 million and $360 million.  We have consolidated Kommandor in all periods presented in the accompanying consolidated financial statements.  The results of Kommandor are included within our Production Facilities segment.
 
As of March 31, 2010, we planned to spend approximately $16 million for additional capital improvements to the newly constructed Well Enhancer vessel and have committed to spend $67.0 million in 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.
 
Litigation and Claims
 
In March 2009, we were notified of a third party’s intention to terminate an international construction contract based on a claimed breach of that contract by one of our subsidiaries.  Under the terms of the contract, our potential liability was generally capped for actual damages at approximately $27 million Australian dollars (“AUD”) (approximately $24.3 million US dollars at December 31, 2009) and for liquidated damages at approximately $5 million AUD (approximately $4.5 million US dollars at December 31, 2009).  We asserted a counterclaim that in the aggregate approximates $12 million U.S. dollars.  On March 30, 2010, an out of court settlement of these claims was negotiated.  On April 19, 2010, pursuant to the terms of the agreement, we paid the third party $15 million A UD to settle all their damage claims against us.   We also agreed not to seek any further payment of our counter claims against them.   Our results for the three months ended March 31, 2010 included approximately $17.5 million in expenses associated with this settlement agreement, including $13.8 million for the litigation settlement payment and $3.7 million to write off our remaining trade receivable from the third party.  These amounts were recorded as general and administrative expenses in the accompanying condensed consolidated statements of operations.
 
See Note 6 for information updating the litigation involving certain disputed royalty payments, which were recognized as oil and gas revenues in the first quarter of 2009.
 
Note 17 – Fair Value Measurements and Recent Accounting Standards
 
Fair Value Measurements
 
We follow the provisions of the ASC 820, Fair Value Measurements and Disclosures, for financial assets and liabilities that are measured and reported at fair value on a recurring basis. ASC 820 establishes a hierarchy for inputs used in measuring fair value. The fair value is to be calculated based on assumptions that market participants would use in pricing assets and liabilities and not on assumptions
 
 
19

 
specific to the entity. The statement requires that each asset and liability carried at fair value be classified into one of the following categories:
 
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 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, 2010 (in thousands):
 
   
Level 1
   
Level 2 (1)
   
Level 3
   
Total
 
Valuation Technique
                           
Assets:
                         
   Gas swaps and collars
  $     $ 30,491     $     $ 30,491  
(c)
   Interest rate swaps                                           
          536               536  
(c)
   Investment in Cal Dive
    3,665                   3,665  
(a)
                                   
Liabilities:
                                 
   Oil swaps and collars                                           
          22,449             22,449  
(c)
   Fair value of long term debt(2) 
    1,239,196       122,434               1,361,630  
(a), (b)
   Foreign currency forwards
          833             833  
(c)
   Interest rate swaps                                           
          1,538             1,538  
(c)
     Total net liability                                           
  $ 1,235,531     $ 116,227     $     $ 1,351,758    
 
(1)  
Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity. Our actual results may differ from our estimates, and these differences can be positive or negative.
 
(2)  
See Note 9 for additional information regarding our long term debt.   The fair value of our long term debt at March 31. 2010 is as follows:
 
   
Fair Value
   
Carrying Value
 
Term Loan (matures July 2013)
  $ 403,343     $ 413,685  
Revolving Credit Facility (matures November 2012)
 
   
 
Convertible Senior Notes (matures March 2025)
    271,878       275,131  
Senior Unsecured Notes (matures January 2016)
    561,000       550,000  
MARAD Debt (matures August 2027) (a) 
    122,434       117,050  
Loan Notes(b) 
    2,975       2,975  
  Total
  $ 1,361,630     $ 1,358,841  
                 
 
 
 
 
(a)  
 The estimated fair value of all debt, other than MARAD Debt and Loan Notes, was determined using level 1 inputs using the market approach.   The fair value of the MARAD debt was determined using a third party evaluation of the remaining average life and outstanding principal balance of the MARAD indebtedness as compared to other governmental obligations in the market place with similar terms.   The fair value of the MARAD debt was estimated using level 2 fair value inputs using the cost approach.
 
(b)  
The carrying value of the loan notes approximates fair value as the maturing of the notes is current.
 
We account for long-lived assets in accordance with ASC 360-10-35, Impairment of Disposal of Long Lived Assets, and review long lived assets for impairment whenever events occur or changes in circumstances indicate that the carrying amount of assets may not be recoverable.   In such evaluation, the estimated future undiscounted cash flows to be generated by the asset are compared with the carrying value of the asset to determine if an impairment may be required.  For our oil and gas properties, the estimated future undiscounted cash flows are based on estimated crude oil and natural gas proved and probable reserves and published future market commodity prices, estimated operating costs and estimates of future capital expenditures.   If the estimated undiscounted cash flows for a particular asset are not sufficient to cover the carrying value of the asset the asset is impaired and its carrying value is reduced to the current fair value.  The fair value of these assets is determined using an income approach by calculating present value of future cash flows attributable to the asset based on market information (such as forward commodity prices), estimates of future costs and estimated proved and probable reserve quantities.  These fair value measurements fall within Level 3 of the fair value hierarchy. In the first quarter of 2010, we impaired three of our natural gas producing properties following a significant drop in natural gas prices during the period (Note 6).  The total amount of the impairment charges were $7.0 million, which reduced these properties to their aggregate fair value of $28.2 million.
 
Recent Accounting Pronouncements
 
In January 2010, the Financial Accounting Standard Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Improving Disclosures about Fair Value Measurements” an amendment to ASC Topic 820.  This amendment requires an entity to: (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reason for the transfers and (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements.   This amendment is effective interim and annual reporting periods beginning after December 15, 2009.  We adopted this ASU effective January 1, 2010.
 
In June 2009, the FASB issued ASC Topic 810 (originally issued as Statement of Financial Accounting Standards No. 167, “Amendments to FASB Interpretation No. (“FIN”) 46(R)”).  Among other items, ASC 810 responds to concerns about an enterprise’s application of certain key provisions of FIN 46(R), including those regarding the transparency of the enterprise’s involvement with variable interest entities.  ASC 810 is effective for calendar year-end companies beginning on January 1, 2010.  We  adopted the standard for the interim period ended March 31, 2010.  There was no impact on the our financial position, results of operations, cash flows, or disclosures.
 
Note 18 – Derivative Instruments and 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 involve 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 exchange currency fluctuations. All derivatives are reflected in our balance sheet at fair value unless otherwise noted, and do not contain credit-risk related or other contingent features that could cause accelerated payments when our derivative liabilities are in net liability positions.
 
We engage only in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the derivative fair values that are designated as cash flow hedges are deferred to the extent that they are effective and are recorded as a component of accumulated other comprehensive income, a component of shareholders’ equity, until the hedged transactions occur and are recognized in
 
 
 
21

 
earnings. The ineffective portion of a cash flow hedge’s change in fair value is recognized immediately in earnings. In addition, any change in the fair value of a derivative that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.  Further, when we have obligations and receivables with the same counterparty, the fair value of the derivative liability and asset are presented at net value.
 
For additional information regarding our accounting for derivatives see Notes 2 and 22 of our 2009 Form 10-K.
 
Commodity Price Risks
 
We currently manage commodity price risks through various financial costless collars and swap instruments covering a portion of our anticipated oil and natural gas production for 2010.  In the past, we have also utilized forward sales contracts that require physical delivery of oil and natural gas.  All of our current commodity derivative contracts qualify for hedge accounting.   However, due to disruptions in our production as a result of damages caused by the hurricanes in third quarter 2008, most of our financial commodity contracts in place at March 31, 2009 no longer qualified for hedge accounting.  Our forward sales contracts were not within the scope of SFAS No. 133 as they qualified for the normal purchases and sales scope exception.  However, due to disruptions in our production as a result of damages caused by the hurricanes, as mentioned above, they no longer qualified for the scope exception.   As a result, both our oil and natural gas commodity contracts and our natural gas  normal purchase and sale contracts were required to be mark-to-market effective March 31, 2009.  At that time, there were no contracts related to 2010 anticipated production and no contracts related to 2010 anticipated production have been subject to mark-to-market adjustments as they have been effective since their inception.
 
As of March 31, 2010, we have the following volumes under derivative contracts related to our oil and gas producing activities totaling approximately 3.0 MMBbl of oil and 18.6 Bcf of natural gas:
 
 
 
Production Period
 
 
Instrument Type
 
 
Average
Monthly Volumes
 
Weighted Average
Price
Crude Oil:
         
(per barrel)
April  2010 — December 2010
 
Collar
 
  100     MBbl
 
$62.50-$80.73
April 2010 — December 2010
 
Swap
 
    99.4  MBbl
 
$77.12
April 2010 — June 2010
 
Swap
 
    50     MBbl
 
$71.08
July 2010  —  December 2010
 
Swap
 
  175     MBbl
 
$80.80
             
Natural Gas:
         
(per Mcf)
April 2010 — December 2010
 
Swap
 
1,061.1 Mmcf
 
$5.82
April 2010 — December 2010
 
Collar
 
1,008.3 Mmcf
 
$6.00 — $6.70
 
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.
 
Variable Interest Rate Risks
 
As some of our long-term debt are subject to market influences and have variable interest rates, in January 2010 we entered into various interest rate swaps to stabilize cash flows relating to interest payments for $200 million of our Term Loan debt under our Credit Agreement (Note 9).  These monthly contracts will mature in January 2012.  Changes in the interest rate swap fair value are deferred to the extent the swap is effective and are recorded as a component of accumulated other comprehensive income until the anticipated interest payments occur and are recognized in interest expense.  The ineffective portion of the interest rate swap, if any, will be recognized immediately in earnings within the line titled net interest expense and other.


 
Foreign Currency Exchange Risks
 
Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar.  We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain shipyard contracts where the contractual payments are denominated in Euros and expected cash outflows relating to certain vessel charters denominated in British pounds.
 
Quantitative Disclosures Related to Derivative Instruments
 
The following tables present the fair value and balance sheet classification of our derivative instruments as of March 31, 2010 and December 31, 2009.  As required by ASC Topic No. 815 “Derivatives and Hedging”, the fair value amounts below are presented on a gross basis and do not reflect the netting of asset and liability positions permitted under the terms of our master netting arrangements.  As a result, the amounts below may not agree with the amounts presented on our condensed consolidated balance sheet and the fair value information presented for our derivative instruments (Note 17).
 
Derivatives designated as hedging instruments under ASC Topic No. 815:
 
 
As of March 31, 2010
 
As of December 31, 2009
 
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
 
(in thousands)
 
Asset Derivatives:
               
   Oil contracts
Other current assets
  $  
Other current assets
  $  
   Natural gas contracts
Other current assets
    30,491  
Other current assets
    5,071  
   Interest rate swaps
Other assets, net
    536  
Other assets, net
     
      $ 31,027       $ 5,071  
 
 
 
As of March 31, 2010
 
As of December 31, 2009
 
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
 
(in thousands)
 
Liability Derivatives:
               
   Oil contracts
Accrued liabilities
  $ 22,449  
Accrued liabilities
  $ 19,477  
   Natural gas contracts
Accrued liabilities
     
Accrued liabilities
    59  
   Interest rate swaps
Accrued liabilities
    1,538  
Accrued liabilities
     
      $ 23,987       $ 19,536  
 
Derivatives that were not designated as hedging instruments (in thousands):
 
 
As of March 31, 2010
 
As of December 31, 2009
 
 
Balance Sheet Location
 
Fair Value
 
Balance Sheet Location
 
Fair Value
 
 
(in thousands)
 
Asset Derivatives:
               
   Natural gas contracts
Other current assets
  $  
Other current assets
  $  
   Foreign exchange forwards
Other current assets
     
Other current assets
    1,143  
   Foreign exchange forwards
Other assets, net
     
Other assets, net
    931  
      $       $ 2,074  
                     
Liability Derivatives:
                   
   Foreign exchange forwards
Accrued liabilities
    502  
Accrued liabilities
     
   Foreign exchange forwards
Other liabilities
    331  
Other liabilities
     
      $ 833       $  
 
The following tables present the impact the impact that derivative instruments designated as cash flow hedges had on our accumulated comprehensive income and our consolidated statements of operations for the three month periods ended March 31, 2010 and 2009.


 
     
Gain (Loss) Recognized in Accumulated OCI
on Derivatives
 
     
2010
     
2009
 
     
(in thousands)
 
Oil and natural gas commodity contracts
 
$
14,630
   
$
(4,267
)
Foreign exchange forwards
   
     
(581
)
Interest rate swaps
   
(590
)
   
384
 
   
$
14,040
   
$
(4,464
)
 
1)  
All unrealized gains (losses) related to our derivatives are expected to be reclassified into earnings within the next 12 months, except for amounts related to our interest swap contracts.
 
 
Location of Gain (Loss) Reclassified from Accumulated OCI into Income
   
Gain (Loss) Recognized from Accumulated OCI into Income
 
     
2010
     
2009
 
       
(in thousands)
 
Oil and natural gas commodity contracts
 
Oil and gas revenue
 
 
$
 
802
   
 
$
 
9,586
 
Foreign exchange forwards
Net interest expense and other
   
     
 
Interest rate swaps
Net interest expense and other
   
(418
)
   
(654
)
     
$
384
   
$
8,932
 
 
The following tables present the impact that derivative instruments not designated as hedges had on our condensed consolidated income statement for the three months ended March 31, 2010 and 2009:
 
   
Location of Gain (Loss) Recognized in Income on Derivatives
   
Gain (Loss) Recognized in Income on Derivatives
 
       
2010
     
2009
 
         
(in thousands)
 
 
Natural gas contracts
 
Gain on oil and gas derivative contracts
 
 
$
 
   
 
$
 
74,609
 
Foreign exchange forwards
 
Net interest expense and other
   
(2,907
)
   
646
 
Interest rate swaps
 
Net interest expense and other
   
     
(12
)
       
$
(2,907
)
 
$
75,243
 
                     
 
 
Note 19 – 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 I-Title XI, Inc. (Cal Dive and its subsidies were never guarantors of the Senior Unsecured Notes).  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 guaranty arrangements, we are required to present the following condensed consolidating financial information.  The accompanying guarantor financial information is presented on the equity method of acco unting 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.


 
 
HELIX ENERGY SOLUTIONS GROUP, INC.
CONDENSED CONSOLIDATING BALANCE SHEETS
(in thousands)
(Unaudited)
 
 
As of March 31, 2010
   
Helix
   
Guarantors
   
Non-Guarantors
   
Consolidating Entries
   
Consolidated
 
ASSETS
                             
Current assets:
                             
     Cash and cash equivalents
$
197,601
 
$
3,600
 
$
10,977
 
$
 
$
212,178
 
     Accounts receivable, net
 
60,293
   
85,238
   
14,173
   
   
159,704
 
     Unbilled revenue
 
8,970
   
261
   
18,180
   
   
27,411
 
     Income taxes receivable
 
49,662
   
   
20,658
   
(53,119
)
 
17,201
 
     Other current assets
 
43,226
   
65,876
   
24,487
   
(21,300
)
 
112,289
 
          Total current assets
 
359,752
   
154,975
   
88,475
   
(74,419
)
 
528,783
 
Intercompany
 
45,543
   
188,541
   
(167,317
)
 
(66,767
)
 
 
Property and equipment, net
 
245,233
   
1,906,769
   
704,709
   
(5,196
)
 
2,851,515
 
Other assets:
                             
     Equity investments
 
2,148,100
   
29,142
   
186,944
   
(2,177,242
)
 
186,944
 
     Goodwill
 
   
45,107
   
32,664
   
   
77,771
 
     Other assets, net
 
50,403
   
40,097
   
29,175
   
(33,741
)
 
85,934
 
     Due from subsidiaries/parent
 
118,639
   
49,880
   
   
(168,519
)
 
 
 
$
2,967,670
 
$
2,414,511
 
$
874,650
 
$
(2,525,884
)
$
3,730,947
 
                               
LIABILITIES AND SHAREHOLDERS’ EQUITY
                             
Current liabilities:
                             
     Accounts payable
$
64,111
 
$
53,380
 
$
18,494
 
$
 
$
135,985
 
     Accrued liabilities
 
68,796
   
111,037
   
22,683
   
(35
)
 
202,481
 
     Income taxes payable
 
   
66,903
   
   
(66,903
)
 
 
     Current maturities of long-term debt
 
4,326
   
   
28,395
   
(20,887
)
 
11,834
 
          Total current liabilities
 
137,233
   
231,320
   
69,572
   
(87,825
)
 
350,300
 
Long-term debt