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 June 30, 2013
 
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.)
  
   
3505 West Sam Houston Parkway North 
Suite 400 
Houston, Texas
(Address of principal executive offices)
 
 
77043
(Zip Code)
 
(281) 618–0400 
(Registrant's telephone number, including area code)
 
400 North Sam Houston Parkway East, Suite 400, Houston, Texas 77060
(Former address of principal executive offices)
 
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, a non-accelerated filer or a smaller reporting company.  See the definitions of “large accelerated filer,” “accelerated filer“ and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
       
       
Large accelerated filer [ √ ]
Accelerated filer [   ]
Non-accelerated filer [   ]
Smaller reporting company [   ]
   
(Do not check if a smaller reporting company)
 
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 July 19, 2013, 105,754,091 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)
 
   
June 30,
 
December 31,
   
2013
 
2012
   
(Unaudited)
         
ASSETS
Current assets:
               
Cash and cash equivalents
 
$
 513,527
   
$
 437,100
 
Accounts receivable:
               
Trade, net of allowance for uncollectible accounts of $4,000 and $5,152, respectively
   
163,486
     
152,233
 
Unbilled revenue
   
32,020
     
26,992
 
Costs in excess of billing
   
1,508
     
6,848
 
Other current assets
   
63,579
     
96,934
 
Current assets of discontinued operations
   
 
     
84,000
 
Total current assets
   
774,120
     
804,107
 
Property and equipment
   
1,858,537
     
2,051,796
 
Less accumulated depreciation
   
(432,170
   
(565,921
Property and equipment, net
   
1,426,367
     
1,485,875
 
Other assets:
               
Equity investments
   
162,839
     
167,599
 
Goodwill
   
61,750
     
62,935
 
Other assets, net
   
49,673
     
49,837
 
Non-current assets of discontinued operations
   
     
816,227
 
Total assets
 
$
2,474,749
   
$
3,386,580
 
                 
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
               
Accounts payable
 
$
91,836
   
$
92,398
 
Accrued liabilities
   
100,091
     
161,514
 
Current maturities of long-term debt
   
5,247
     
16,607
 
Current liabilities of discontinued operations
   
     
182,527
 
Total current liabilities
   
197,174
     
453,046
 
Long-term debt
   
543,341
     
1,002,621
 
Deferred tax liabilities
   
288,596
     
359,237
 
Other non-current liabilities
   
19,838
     
5,025
 
Non-current liabilities of discontinued operations
   
     
147,237
 
Total liabilities
   
1,048,949
     
1,967,166
 
                 
Commitments and contingencies
               
Shareholders' equity:
               
Common stock, no par, 240,000 shares authorized, 105,754 and 105,763 shares issued, respectively
   
932,899
     
932,742
 
Retained earnings
   
505,136
     
476,310
 
Accumulated other comprehensive loss
   
(37,797
   
(15,667
Total controlling interest shareholders' equity
   
1,400,238
     
1,393,385
 
Noncontrolling interest
   
25,562
     
26,029
 
Total equity
   
1,425,800
     
1,419,414
 
Total liabilities and shareholders' equity
 
$
2,474,749
   
$
3,386,580
 
 
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
 
   
June 30,
 
   
2013
   
2012
 
             
Net revenues
  $ 232,178     $ 197,461  
                 
Cost of sales:
               
Cost of sales
    164,681       147,491  
Impairments
          21,532  
Cost of sales
    164,681       169,023  
                 
Gross profit
    67,497       28,438  
                 
Loss on sale of assets
    (1,085 )      
Selling, general and administrative expenses
    (19,215 )     (21,569 )
Income from operations
    47,197       6,869  
Equity in earnings of investments
    683       5,748  
Net interest expense
    (11,344 )     (11,645 )
Loss on early extinguishment of long-term debt
    (646 )      
Other expense, net
    (566 )     (1,711 )
Other income – oil and gas
    1,282        
Income before income taxes
    36,606       (739 )
Income tax provision (benefit)
    8,577       (3,953 )
Income from continuing operations
    28,029       3,214  
Income (loss) from discontinued operations, net of tax
    (29 )     42,216  
Net income, including noncontrolling interests
    28,000       45,430  
Less net income applicable to noncontrolling interests
    (789 )     (789 )
Net income applicable to Helix
  $ 27,211     $ 44,641  
                 
                 
Basic earnings per share of common stock:
               
Continuing operations
  $ 0.26     $ 0.02  
Discontinued operations
    0.00       0.40  
Net income per common share
  $ 0.26     $ 0.42  
                 
Diluted earnings per share of common stock:
               
Continuing operations
  $ 0.26     $ 0.02  
Discontinued operations
    0.00       0.40  
Net income per common share
  $ 0.26     $ 0.42  
                 
Weighted average common shares outstanding:
               
Basic
    105,046       104,563  
Diluted
    105,133       105,042  
 
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)
 
   
Six Months Ended
 
   
June 30,
 
   
2013
   
2012
 
             
Net revenues
  $ 429,607     $ 427,303  
                 
Cost of sales:
               
Cost of sales
    307,943       304,850  
Impairments
    1,600       21,532  
Cost of sales
    309,543       326,382  
                 
Gross profit
    120,064       100,921  
                 
Loss on commodity derivative contracts
    (14,113 )      
Loss on sale of assets
    (1,085 )      
Selling, general and administrative expenses
    (42,431 )     (43,984 )
Income from operations
    62,435       56,937  
Equity in earnings of investments
    1,293       6,155  
Net interest expense
    (21,667 )     (26,122 )
Loss on early extinguishment of long-term debt
    (3,528 )     (17,127 )
Other expense, net
    (4,250 )     (1,641 )
Other income – oil and gas
    4,100        
Income before income taxes
    38,383       18,202  
Income tax provision (benefit)
    9,020       (2,675 )
Income from continuing operations
    29,363       20,877  
Income from discontinued operations, net of tax
    1,029       91,069  
Net income, including noncontrolling interests
    30,392       111,946  
Less net income applicable to noncontrolling interests
    (1,566 )     (1,578 )
Net income applicable to Helix
  $ 28,826     $ 110,368  
                 
                 
Basic earnings per share of common stock:
               
Continuing operations
  $ 0.26     $ 0.18  
Discontinued operations
    0.01       0.87  
Net income per common share
  $ 0.27     $ 1.05  
                 
Diluted earnings per share of common stock:
               
Continuing operations
  $ 0.26     $ 0.18  
Discontinued operations
    0.01       0.87  
Net income per common share
  $ 0.27     $ 1.05  
                 
Weighted average common shares outstanding:
               
Basic
    105,039       104,547  
Diluted
    105,141       105,012  
 
The accompanying notes are an integral part of these condensed consolidated financial statements.
 
 
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(UNAUDITED)
(in thousands)
 
   
Three Months Ended
 
   
June 30,
 
   
2013
   
2012
 
             
Net income, including noncontrolling interests
  $ 28,000     $ 45,430  
Other comprehensive income (loss), net of tax:
               
Unrealized gain (loss) on hedges arising during the period
    (5,882 )     27,411  
Reclassification adjustments for (gain) loss included in net income
    354       (7,903 )
Income taxes on unrealized (gain) loss on hedges
    1,935       (6,828 )
Unrealized gain (loss) on hedges, net of tax
    (3,593 )     12,680  
Foreign currency translation loss
    (218 )     (2,838 )
Other comprehensive loss, net of tax
    (3,811 )     9,842  
Comprehensive income (loss)
    24,189       55,272  
Less comprehensive income applicable to noncontrolling interests
    (789 )     (789 )
Comprehensive income (loss) applicable to Helix
  $ 23,400     $ 54,483  
 
 
   
Six Months Ended
 
   
June 30,
 
   
2013
   
2012
 
             
Net income, including noncontrolling interests
  $ 30,392     $ 111,946  
Other comprehensive income (loss), net of tax:
               
Unrealized gain (loss) on hedges arising during the period
    (17,167 )     6,093  
Reclassification adjustments for (gain) loss included in net income
    504       (7,819 )
Income taxes on unrealized loss on hedges
    5,832       604  
Unrealized loss on hedges, net of tax
    (10,831 )     (1,122 )
Foreign currency translation gain (loss)
    (11,299 )     1,314  
Other comprehensive loss, net of tax
    (22,130 )     192  
Comprehensive income (loss)
    8,262       112,138  
Less comprehensive income applicable to noncontrolling interests
    (1,566 )     (1,578 )
Comprehensive income (loss) applicable to Helix
  $ 6,696     $ 110,560  
 
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)
 
   
Six Months Ended
 
   
June 30,
 
   
2013
   
2012
 
Cash flows from operating activities:
           
Net income, including noncontrolling interests
  $ 30,392     $ 111,946  
Adjustments to reconcile net income, including noncontrolling interests to net cash provided by operating activities:
               
Income from discontinued operations
    (1,029 )     (91,069 )
Depreciation and amortization
    49,692       47,388  
Asset impairment charge
          14,590  
Amortization of deferred financing costs
    2,824       3,292  
Stock-based compensation expense
    5,473       3,658  
Amortization of debt discount
    2,557       4,776  
Deferred income taxes
    16,058       21,624  
Excess tax from stock-based compensation
    (383 )     657  
Loss on sale of assets
    1,085        
Loss on early extinguishment of debt
    3,528       17,127  
Unrealized loss and ineffectiveness on derivative contracts, net
    638       149  
Changes in operating assets and liabilities:
               
Accounts receivable, net
    (19,702 )     64,420  
Other current assets
    15,479       (19,571 )
Income tax payable
    (56,454 )     1,083  
Accounts payable and accrued liabilities
    (35,081 )     (22,072 )
Oil and gas asset retirement costs
    (5,950 )     (19,241 )
Other noncurrent, net
    (7,117 )     (19,940 )
Net cash provided by (used in) operating activities
    2,010       118,817  
Net cash provided by (used in) discontinued operations
    (30,503 )     102,203  
Net cash provided by (used in) operating activities
    (28,493 )     221,020  
                 
Cash flows from investing activities:
               
Capital expenditures
    (102,383 )     (115,779 )
Distributions from equity investments, net
    4,567       2,045  
Proceeds from sale of assets
    108,250        
Net cash provided by (used in) investing activities
    10,434       (113,734 )
Net cash provided by (used in) discontinued operations
    582,965       (31,668 )
Net cash provided by (used in) investing activities
    593,399       (145,402 )
                 
Cash flows from financing activities:
               
Early extinguishment of Senior Unsecured Notes
          (209,500 )
Borrowings under revolving credit facility
    47,617       100,000  
Repayment of revolving credit facility
    (147,617 )      
Issuance of Convertible Senior Notes due 2032
          200,000  
Repurchase of Convertible Senior Notes due 2025
    (3,487 )     (143,945 )
Proceeds from term loan
          100,000  
Repayment of term loans
    (367,181 )     (2,750 )
Repayment of MARAD borrowings
    (2,529 )     (2,409 )
Deferred financing costs
    (10,932 )     (6,485 )
Distributions to noncontrolling interest
    (2,033 )      
Repurchases of common stock
    (5,562 )     (7,510 )
Excess tax from stock-based compensation
    383       (657 )
Exercise of stock options, net and other
    (186 )     372  
Net cash provided by (used in) financing activities
    (491,527 )     27,116  
                 
Effect of exchange rate changes on cash and cash equivalents
    3,048       304  
Net increase in cash and cash equivalents
    76,427       103,038  
Cash and cash equivalents:
               
Balance, beginning of year
    437,100       546,465  
Balance, end of period
  $ 513,527     $ 649,503  
 
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 and Recent Accounting Standards 
 
The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its wholly- and 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 wholly- and majority-owned subsidiaries.  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 (the “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 (“U.S. GAAP”) and are consistent in all material respects with those applied in our 2012 Annual Report on Form 10-K (“2012 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, statements of operations, statements of comprehensive income (loss), and statements of cash flows, as applicable.  The operating results for the three- and six-month periods ended June 30, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013.  Our balance sheet as of December 31, 2012 included herein has been derived from the audited balance sheet as of December 31, 2012 included in our 2012 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 2012 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.  The most significant of these reclassifications are associated with our discontinued operations.  As noted in Note 2, we exited our oil and gas business in February 2013 upon the sale of our former wholly-owned subsidiary, Energy Resource Technology GOM, Inc. (“ERT”).
 
In February 2013, the FASB issued ASU No. 2013-02, Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income (“ASU 2013-02”).  ASU 2013-02 requires companies to provide information about the amounts that are reclassified out of accumulated other comprehensive income either by the respective line items of net income or by cross-reference to other required disclosures.  This guidance is effective prospectively for fiscal years beginning after December 15, 2012.  We adopted ASU 2013-02 on January 1, 2013.  The adoption of this guidance did not have any material impact on our consolidated financial statements.  We have presented the information required by the guidance in Note 16.
 
Note 2 — Company Overview 
 
Contracting Services Operations
 
We are an international offshore energy company that provides specialty services to the offshore energy industry, with a focus on growing our well intervention and robotics operations.  We seek to provide services and methodologies that we believe are critical to developing offshore reservoirs and maximizing production economics.  Our “life of field” services are segregated into four disciplines: well intervention, robotics, subsea construction and production facilities.  We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities.  Our Contracting Services segment includes well intervention, robotics and subsea construction operations (see below for disclosure regarding the dispositions of our remaining subsea construction vessels and related assets).  Our Production Facilities business includes our majority ownership of the Helix Producer I (“HP I”) vessel as well as our equity investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”) (Note 6).  It also includes the Helix Fast Response System (“HFRS”), which includes access to our Q4000 and HP I vessels.
 
 
In October 2012, we entered into an agreement to sell our two remaining pipelay vessels, the Caesar and Express, and other related pipelay equipment for a total sales price of $238.3 million.  In June 2013, we completed the sale of the Caesar and related equipment for $138.3 million which included $30 million of funds deposited with us at the time the agreement was entered into (Note 3).  We used $80.1 million of the after-tax proceeds from the sale of the Caesar to reduce our indebtedness under our former credit agreement (Note 7) and we are investing the remainder in our continuing operations, including supporting the expansion of our well intervention and robotics operations.  This sale resulted in a loss of $1.1 million that is reflected in “Loss on sale of assets” in the accompanying condensed consolidated statement of operations.  In July 2013, we completed the sale of the Express for $100 million, including the remaining $20 million of deposited funds.  A gain of approximately $15.5 million will be recorded on the sale of the Express in the third quarter of 2013.  We also entered into an agreement to sell our spoolbase and adjoining property at Ingleside, Texas to the same group of companies that purchased the Caesar and Express.  The facility and adjoining property is being leased to the purchaser during the second half of 2013 and the sale is expected to close in January 2014.  The total sales price is $45 million, payable over 3.5 years.  At the time the agreement was signed, we received a $5 million deposit which is only refundable under limited circumstances.
 
Discontinued Operations
 
In December 2012, we announced a definitive agreement for the sale of ERT.  On February 6, 2013, we sold ERT for $624 million plus consideration in the form of overriding royalty interests in ERT’s Wang well and certain other of its future exploration prospects.  As a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying condensed consolidated financial statements.  See Note 4 for additional information regarding our discontinued oil and gas operations and Note 7 regarding the use of a portion of the sale proceeds to reduce our indebtedness under our former credit agreement.
 
Note 3 — Details of Certain Accounts 
 
Other current assets consist of the following (in thousands): 
 
   
June 30,
   
December 31,
 
   
2013
   
2012
 
             
Other receivables
  $ 1,810     $ 1,086  
Prepaid insurance
    351       11,999  
Other prepaids
    11,832       11,751  
Spare parts inventory
    4,694       2,480  
Income tax receivable
    158       14,201  
Current deferred tax assets
    35,533       43,942  
Derivative assets
          5,946  
Other
    9,201       5,529  
Total other current assets
  $ 63,579     $ 96,934  
 
Other assets, net, consist of the following (in thousands): 
 
   
June 30,
   
December 31,
 
   
2013
   
2012
 
             
Deferred dry dock expenses, net
  $ 18,418     $ 22,704  
Deferred financing costs, net
    28,610       24,338  
Intangible assets with finite lives, net
    514       491  
Other
    2,131       2,304  
Total other assets, net
  $ 49,673     $ 49,837  
 
 
Accrued liabilities consist of the following (in thousands): 
 
   
June 30,
   
December 31,
 
   
2013
   
2012
 
             
Accrued payroll and related benefits
  $ 37,346     $ 51,561  
Current asset retirement obligations
    2,739       2,898  
Unearned revenue
    8,326       6,137  
Billing in excess of cost
    2,126       6,445  
Accrued interest
    16,424       17,451  
Derivative liability (Note 16)
    2,376       16,266  
Taxes payable excluding income tax payable
    6,080       5,164  
Pipelay assets sale deposit (Note 2)
    20,000       50,000  
Other
    4,674       5,592  
Total accrued liabilities
  $ 100,091     $ 161,514  
 
Note 4 — Oil and Gas Properties 
 
Results of Discontinued Operations 
 
The following summarized financial information relates to ERT, which is reported as “Income from discontinued operations, net of tax” in the accompanying condensed consolidated statements of operations:
 
   
Periods Ended June 30,
 
   
Six Months
   
Three Months
   
Six Months
 
   
2013 (1)
   
2012
   
2012
 
                   
Revenues
  $ 48,847     $ 149,933     $ 328,018  
Costs:
                       
Production (lifting) costs
    16,017       40,247       77,269  
Exploration expenses
    3,514       1,092       1,846  
Depreciation, depletion, amortization and accretion
    1,226       39,730       87,572  
Proved property impairment and abandonment
    (152 )     4,077       7,317  
Loss on sale of oil and gas properties
          236       1,714  
Gain on commodity derivative contracts
          (10,069 )     (7,730 )
Selling, general and administrative expenses
    1,229       3,002       6,283  
Net interest expense and other (2)
    2,732       6,973       14,250  
Total costs
    24,566       85,288       188,521  
Pretax income from discontinued operations
    24,281       64,645       139,497  
Income tax provision
    8,499       22,429       48,428  
Income from operations of discontinued operations
    15,782       42,216       91,069  
Loss on sale of business, net of tax
    (14,753 )            
Income from discontinued operations, net of tax
  $ 1,029     $ 42,216     $ 91,069  
 
(1)
Results for 2013 primarily reflect the operating results from January 1, 2013 through February 6, 2013 when ERT was sold.  There were no material results of operations for ERT during the three-month period ended June 30, 2013.
 
(2)
Net interest expense of $2.7 million for the six-month period ended June 30, 2013, and $6.8 million and $14.0 million for the three- and six-month periods ended June 30, 2012, respectively, was allocated to ERT primarily based on interest associated with indebtedness directly attributed to the substantial oil and gas acquisition made in 2006.  This includes interest related to debt required to be paid upon the disposition of ERT.
 
 
Note 5 — Statement of Cash Flow Information
 
We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less.  The following table provides supplemental cash flow information (in thousands): 
 
   
Six Months Ended
 
   
June 30,
 
   
2013
   
2012
 
             
Interest paid, net of interest capitalized
  $ 20,403     $ 39,259  
Income taxes paid
  $ 49,981     $ 23,054  
 
Total non-cash investing activities for the six-month periods ended June 30, 2013 and 2012 included $10.7 million and $37.8 million, respectively, of accruals for property and equipment capital expenditures.
 
Note 6 — Equity Investments
 
As of June 30, 2013, we had two investments that we account for using the equity method of accounting: Deepwater Gateway and Independence Hub, both of which are included in our Production Facilities segment. 
 
Deepwater Gateway, L.L.C.  In June 2002, we, along with Enterprise Products Partners L.P. (”Enterprise”), formed Deepwater Gateway, each with a 50% interest, to design, construct, install, own and operate a tension leg platform production hub primarily for Anadarko Petroleum Corporation's Marco Polo field in the Deepwater Gulf of Mexico.  Our investment in Deepwater Gateway totaled $88.5 million and $91.4 million as of June 30, 2013 and December 31, 2012, respectively (including capitalized interest of $1.3 million at June 30, 2013 and December 31, 2012). 
 
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.  Our investment in Independence Hub was $74.4 million and $76.2 million as of June 30, 2013 and December 31, 2012, respectively (including capitalized interest of $4.4 million and $4.6 million at June 30, 2013 and December 31, 2012, respectively). 
 
We received the following distributions from our equity investments (in thousands):
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Deepwater Gateway
  $ 2,000     $ 1,250     $ 3,500     $ 3,400  
Independence Hub
    1,200       600       2,360       4,800  
Total
  $ 3,200     $ 1,850     $ 5,860     $ 8,200  
 
As disclosed in our 2012 Form 10-K, in the first quarter of 2012, we recorded losses totaling $3.8 million associated with our investment in an Australian joint venture, including a $3.0 million fee paid in connection with our exit from the joint venture.  In April 2012, we paid this fee and received approximately $3.7 million of proceeds for our pro rata portion (50%) of the value of certain of the net assets on hand at the time of our exit.  These proceeds were recorded as income in our equity in earnings in the accompanying condensed consolidated statements of operations.  We are no longer a participant in this joint venture.
 
 
Note 7 — Long-Term Debt
 
Scheduled maturities of long-term debt outstanding as of June 30, 2013 are as follows (in thousands):
 
   
Senior Unsecured Notes (1)
   
MARAD
Debt
   
2032
Notes (2)
   
Total
 
                         
Less than one year
  $     $ 5,247     $     $ 5,247  
One to two years
          5,508             5,508  
Two to three years
    274,960       5,783             280,743  
Three to four years
          6,072             6,072  
Four to five years
          6,375             6,375  
Over five years
          73,774       200,000       273,774  
Total debt
    274,960       102,759       200,000       577,719  
Current maturities
          (5,247 )           (5,247 )
Long-term debt, less current maturities
    274,960       97,512       200,000       572,472  
Unamortized debt discount (3)
                (29,131 )     (29,131 )
Long-term debt
  $ 274,960     $ 97,512     $ 170,869     $ 543,341  
 
 
(1)
In June 2013, we elected to redeem the remaining Senior Unsecured Notes on July 22, 2013, and we redeemed these notes in full on that date.  See Senior Unsecured Notes below for additional disclosures regarding the early extinguishment of this debt.
 
(2)
Beginning in March 2018, the holders of the Convertible Senior Notes due 2032 may require us to repurchase these notes or we may at our own option elect to repurchase notes. These notes will mature in March 2032.
 
(3)
The Convertible Senior Notes due 2032 will increase to their principal amount through accretion of non-cash interest charges through March 2018.
 
Included below is a summary of certain components of our indebtedness.  For additional information regarding our debt, see Note 7 of our 2012 Form 10-K.
 
Credit Agreement
 
In June 2013, we entered into a Credit Agreement (the “Credit Agreement”) with a group of lenders pursuant to which we may borrow up to $300 million in a term loan (the “Term Loan”) and may borrow revolving loans (the “Revolving Loans”) under a revolving credit facility up to an outstanding amount of $600 million (the “Revolving Credit Facility”).  The Revolving Credit Facility also permits us to obtain letters of credit up to the full amount of the Revolving Credit Facility.  Subject to customary conditions, we may request an increase of up to $200 million in aggregate commitments with respect to the Revolving Credit Facility, additional term loans or a combination thereof.  Upon closing of the Credit Agreement, we borrowed approximately $81.5 million under the Revolving Credit Facility to repay existing outstanding amounts under our former revolving credit facility, and to cover fees and expenses associated with the Credit Agreement.  This borrowing was fully repaid as of June 30, 2013.  In July 2013, we borrowed $300 million under the Term Loan in connection with the early redemption of our remaining $275 million Senior Unsecured Notes (see “Senior Unsecured Notes” below).
 
The Term Loan and the Revolving Loans (together, the “Loans”) will, at our election, bear interest either in relation to Bank of America’s base rate or to a LIBOR rate, provided that all Swing Line Loans (as defined in the Credit Agreement) will be base rate loans.  The Term Loan currently bears interest at the LIBOR Rate plus 2.75%.
 
The Loans or portions thereof bearing interest at the base rate will bear interest at a per annum rate equal to the base rate plus a margin ranging from 1.00% to 2.00%.  The Loans or portions thereof bearing interest at a LIBOR rate will bear interest at the LIBOR rate selected by us plus a margin ranging from 2.00% to 3.00%.  A letter of credit fee is payable by us equal to our applicable margin for LIBOR rate Loans
 
 
multiplied by the daily amount available to be drawn under outstanding letters of credit.  Margins on the Loans will vary in relation to the consolidated coverage ratio provided for in the Credit Agreement.  We also pay a fixed commitment fee of 0.5% on the unused portion of our Revolving Credit Facility.  At June 30, 2013, our availability under the Revolving Credit Facility totaled $579.4 million, net of $20.6 million of letters of credit issued.
 
The Term Loan is repayable in scheduled installments of principal reduction of 5% in each of the initial two loan years ($15 million per year), and 10% in each of the remaining three loan years ($30 million per year), payable quarterly, with a balloon payment at maturity.  These installment amounts are subject to adjustment for any prepayments on the Term Loan.  We may elect to prepay amounts outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid.  We may prepay amounts outstanding under the Revolving Loans without premium or penalty, and may reborrow any amounts paid up to the amount of the Revolving Credit Facility.  The Loans mature on June 19, 2018.  In certain circumstances, we will be required to prepay the Loans.
 
The Credit Agreement and the other documents entered into in connection with the Credit Agreement (together, the “Loan Documents”) include terms and conditions, including covenants, which we consider customary for this type of transaction.  The covenants include restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and incur capital expenditures.  In addition, the Credit Agreement obligates us to meet minimum financial requirements of EBITDA (as defined in the Credit Agreement) to interest charges, and funded debt to EBITDA.  We may designate one of our existing foreign subsidiaries, and any newly established foreign subsidiaries, as subsidiaries that are not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided we meet certain liquidity requirements, in which case the EBITDA of the Unrestricted Subsidiaries is not included in the calculations of our financial covenants.  Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited.  Our obligations under the Credit Agreement, and of guarantors under their guarantee, are secured by most of our assets and assets of the guarantors and Canyon Offshore Limited, plus pledges of up to 2/3 of the shares of certain foreign subsidiaries.
 
Former Credit Agreement
 
Our former credit agreement also contained both term loan and revolving loan components within the credit facility.  This credit agreement was scheduled to mature on July 1, 2015.  As of March 31, 2013, the amount of our former term loan debt was $72.3 million, which reflected the repayment of $293.9 million with the after-tax proceeds from the sale of ERT in February 2013.  Our former credit agreement also provided for $600 million in borrowing capacity under its revolving credit facility.  We had $78.1 million drawn on the former revolving credit facility at March 31, 2013, which reflected the repayment of $24.5 million with the after-tax proceeds from the sale of ERT.  In connection with the repayment of debt in February 2013, we recorded a $2.9 million charge to accelerate a pro rata portion of the deferred financing costs associated with our former term loan debt.  This charge is reflected as a component of “Loss on early extinguishment of long-term debt” in the accompanying condensed consolidated statements of operations. 
 
In June 2013, we fully repaid the remaining $70.3 million of outstanding indebtedness under our former credit agreement.  Prior to that repayment, the principal amounts outstanding at March 31, 2013 were reduced by repayments of $80.1 million of the after-tax proceeds from the sale of the Caesar (Note 2) in June 2013.  Following the repayment of indebtedness, our former credit agreement was terminated.  In connection with the repayment and termination of our former credit agreement, we recorded a $0.6 million charge to accelerate the remaining deferred financings costs associated with our indebtedness under the term loan component of our former credit agreement.  This charge is also a component of “Loss on early extinguishment of long-term debt” in the accompanying condensed consolidated statements of operations. 
 
 
Senior Unsecured Notes 
 
In December 2007, we issued $550 million of 9.5% Senior Unsecured Notes due 2016 (the “Senior Unsecured Notes”).  Interest on the Senior Unsecured Notes was payable semi-annually in arrears on each January 15 and July 15, commencing July 15, 2008.  The Senior Unsecured Notes were 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 were required to guarantee the Senior Unsecured Notes.  Our foreign subsidiaries were not guarantors of the notes.  The Indenture governing the Senior Unsecured Notes provided that, prior to their stated maturity, we may redeem all or a portion of the Senior Unsecured Notes on no less than 30 days’ and no more than 60 days’ prior notice at the redemption prices (expressed as percentages of the principal amount) set forth below, plus accrued and unpaid interest thereon, if any, to the applicable redemption date. 
 
Year
 
Redemption Price
     
2013
 
102.375%
2014 and thereafter
 
100.000%
 
In June 2013, we elected to redeem the remaining Senior Unsecured Notes on July 22, 2013.  On that date, we paid $282.0 million to fully redeem the Senior Unsecured Notes, including $275.0 million with respect to the outstanding principal amount, $6.5 million of call premium and $0.5 million in accrued and unpaid interest.  Our third-quarter 2013 results of operations will include a loss on early extinguishment of debt charge totaling $8.6 million, which reflects the $6.5 million call premium and $2.1 million to accelerate the remaining deferred financing costs associated with the original issuance of the Senior Unsecured Notes.
 
In March 2012, we purchased a portion of these Senior Unsecured Notes, which resulted in an early extinguishment of $200.0 million of our outstanding balance.  For the purchase, we paid a total of $213.5 million, including $200.0 million in principal, a $9.5 million call premium and $4.0 million of accrued and unpaid interest.  We also recorded a $2.0 million charge to accelerate a pro rata portion of the deferred financing costs associated with the issuance of the Senior Unsecured Notes.  The loss on this early extinguishment of these notes totaled $11.5 million and is reflected as a component of “Loss on early extinguishment of long-term debt” in the accompanying condensed consolidated statements of operations.
 
Convertible Senior Notes Due 2032 
 
In March 2012, we completed the public offering and sale of $200.0 million in aggregate principal amount of 3.25% Convertible Senior Notes due 2032 (the “2032 Notes”).  The net proceeds from the issuance of the 2032 Notes were $195.0 million, after deducting the underwriter’s discounts and commissions and offering expenses.  We used the net proceeds to repurchase and retire $142.2 million of aggregate principal amount of the 2025 Notes (see below) in separate, privately negotiated transactions.  The remaining net proceeds were used for general corporate purposes, including the repayment of other indebtedness. 
 
The 2032 Notes bear interest at a rate of 3.25% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012.  The 2032 Notes will mature on March 15, 2032, unless earlier converted, redeemed or repurchased.  The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752 shares of common stock per $1,000 principal amount of the 2032 Notes (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the indenture governing the 2032 Notes.  The initial conversion price represents a conversion premium of 35.0% over the closing price of our common stock on March 6, 2012, which was $18.53 per share. 
 
 
Prior to March 20, 2018, the 2032 Notes will not be redeemable.  On or after March 20, 2018, we may, at our option, redeem some or all of the 2032 Notes in cash, at any time, upon at least 30 days’ notice at a price equal to 100% of the principal amount plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date.  Holders may require us to purchase in cash some or all of their 2032 Notes at a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a fundamental change (as defined in the governing indenture). 
 
In connection with the issuance of the 2032 Notes, we recorded a discount of $35.4 million as required under existing accounting rules.  To arrive at this discount amount, we estimated the fair value of the liability component of the 2032 Notes as of the date of their issuance (March 12, 2012) using an income approach.  To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of issuance and an expected life of 6.0 years.  In selecting the expected life, we selected the earliest date that the holders could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018).  The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception. 
 
MARAD Debt
 
This U.S. government guaranteed financing (the "MARAD Debt") is pursuant to Title XI of the Merchant Marine Act of 1936 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 beginning in August 2002 and matures 25 years from such date.  The MARAD Debt is collateralized by the Q4000, is guaranteed 50% by us, and initially bore interest at a floating rate that approximated AAA Commercial Paper yields plus 20 basis points.  As provided for in the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date (February 2027). 
 
Convertible Senior Notes Due 2025 
 
In March 2005, we issued $300 million of 3.25% Convertible Senior Notes due 2025 at 100% of the principal amount to certain qualified institutional buyers (the “2025 Notes”). 
 
In March 2012, we repurchased $142.2 million in aggregate principal of the 2025 Notes.  In these repurchase transactions we paid an aggregate amount of $145.1 million, representing principal plus $1.8 million of premium and $1.1 million of accrued interest.  The loss on the early extinguishment of the 2025 Notes totaled $5.6 million and is reflected as a component of “Loss on early extinguishment of long-term debt” in the accompanying condensed consolidated statements of operations.  The loss on early extinguishment includes the acceleration of $3.5 million of unamortized discount associated with the 2025 Notes, the $1.8 million premium paid in connection with the repurchase of a portion of the 2025 Notes and a $0.3 million charge to accelerate a pro rata portion of the deferred financing costs associated with the original issuance of the 2025 Notes.  The remainder of the 2025 Notes was extinguished when the holders exercised their option for us to repurchase their notes in December 2012 ($154.3 million) and in February 2013 when we repurchased the remaining $3.5 million of the 2025 Notes that were not put to us by the holders in December 2012. 
 
Other 
 
In accordance with our Credit Agreement, Senior Unsecured Notes, 2032 Notes and MARAD Debt agreements, we are required to comply with certain covenants, including the maintenance of minimum net worth, working capital and debt-to-equity requirements, and restrictions that limit our ability to incur certain types of additional indebtedness.  As of June 30, 2013, we were in compliance with these covenants and restrictions. 
 
 
Unamortized deferred financing costs are included in “Other assets, net” in the accompanying condensed consolidated balance sheets and are being amortized over the life of the respective debt agreements.  The following table reflects the components of our deferred financing costs (in thousands):
 
   
June 30, 2013
   
December 31, 2012
 
   
Gross Carrying Amount
   
Accumulated Amortization
   
Net
   
Gross Carrying Amount
   
Accumulated Amortization
   
Net
 
                                     
Term Loans (mature July 2015) (1)
  $     $     $     $ 15,318     $ (11,595 )   $ 3,723  
Revolving Credit Facility (matures July 2015) (1)
                      20,021       (12,466 )     7,555  
Term Loan (matures June 2018) (2)
    3,630             3,630                    
Revolving Credit Facility (matures June 2018) (2)
    13,261             13,261                    
2025 Notes (mature December 2025)
                      8,189       (8,189 )      
2032 Notes (mature March 2032)
    3,759       (840 )     2,919       4,251       (534 )     3,717  
Senior Unsecured Notes (mature January 2016) (3)
    10,643       (8,551 )     2,092       10,643       (8,252 )     2,391  
MARAD Debt (matures February 2027)
    12,200       (5,492 )     6,708       12,200       (5,248 )     6,952  
Total deferred financing costs
  $ 43,493     $ (14,883 )   $ 28,610     $ 70,622     $ (46,284 )   $ 24,338  
 
(1)
Relates to the term loans and revolving credit facility under our former credit agreement, which was terminated in June 2013.
 
(2)
Relates to amounts allocated to the Term Loan and Revolving Credit Facility under our new Credit Agreement, which was entered into in June 2013.
 
(3)
In June 2013, we elected to redeem the remaining Senior Unsecured Notes on July 22, 2013, and we redeemed these notes in full on that date.  In July 2013, we recorded a charge of $2.1 million to accelerate the remaining deferred financing costs associated with the original issuance of this debt.
 
The following table details our interest expense and capitalized interest (in thousands): 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Interest expense (1)
  $ 13,977     $ 12,696     $ 26,555     $ 27,940  
Interest income
    (316 )     (53 )     (632 )     (341 )
Capitalized interest
    (2,317 )     (998 )     (4,256 )     (1,477 )
Interest expense, net
  $ 11,344     $ 11,645     $ 21,667     $ 26,122  
 
(1)
Interest expense of $2.8 million for the six-month period ended June 30, 2013, and $7.0 million and $14.6 million for the three- and six-month periods ended June 30, 2012, respectively, was allocated to ERT and is included in discontinued operations.  We no longer allocate interest expense to ERT following the sale of ERT in February 2013.
 
Note 8 — Income Taxes 
 
The effective tax rates for the three- and six-month periods ended June 30, 2013 were 23.4% and 23.5%, respectively.  This was less favorable than the tax benefits recorded for the three- and six-month periods ended June 30, 2012.  The variance is primarily attributable to projected year over year increases in profitability in the United States. 
 
 
We believe our recorded assets and liabilities are reasonable; however, tax laws and regulations are subject to interpretation and tax litigation is inherently uncertain, and therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.  Income taxes have been provided based on the U.S. statutory rate of 35% and at the local statutory rate for each foreign jurisdiction adjusted for items that are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes.  The primary differences between the statutory rate and our effective rate from continuing operations are as follows: 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Statutory rate
    35.0 %     35.0 %     35.0 %     35.0 %
Foreign provision
    (10.6 )     491.4       (11.1 )     (47.5 )
Other
    (1.0 )     8.5       (0.4 )     (2.2 )
Effective rate
    23.4 %     534.9 %     23.5 %     (14.7 ) %
 
Note 9 — Accumulated Other Comprehensive Loss
 
The components of accumulated other comprehensive loss are as follows (in thousands): 
 
   
June 30,
   
December 31,
 
   
2013
   
2012
 
             
Cumulative foreign currency translation adjustment
  $ (26,966 )   $ (15,667 )
Unrealized loss on hedges, net (1)
    (10,831 )      
Accumulated other comprehensive loss
  $ (37,797 )   $ (15,667 )
 
(1)
Amount at June 30, 2013 is related to foreign currency hedges for the Grand Canyon, Grand Canyon II and Grand Canyon III, and is net of deferred income taxes totaling $5.8 million (Note 16). 
 
Note 10 — Earnings Per Share 
 
We have shares of restricted stock issued and outstanding, some of which remain subject to 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 applicable accounting 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.  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. 
 
The presentation of basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing the net income applicable to Helix 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 computations of  the numerator (Income) and denominator (Shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands)
 
 
   
Three Months Ended
   
Three Months Ended
 
   
June 30, 2013
   
June 30, 2012
 
   
Income
   
Shares
   
Income
   
Shares
 
Basic:
                       
Continuing operations:
                       
Net income applicable to Helix
  $ 27,211           $ 44,641        
Less: (Income) loss from discontinued operations, net of tax
    29             (42,216 )      
Income from continuing operations
    27,240             2,425        
Less: Undistributed income allocable to participating securities – continuing operations
    (203 )           (24 )      
Income applicable to common shareholders – continuing operations
  $ 27,037    
 105,046 
    $ 2,401    
 104,563 
 
 
Discontinued operations:
                       
Income (loss) from discontinued operations, net of tax
  $ (29 )         $ 42,216        
Less: Undistributed income allocable to participating securities – discontinued operations
                (424 )      
Income (loss) applicable to common shareholders – discontinued operations
  $ (29 )     105,046     $ 41,792       104,563  
 
Diluted:
                       
Continuing operations:
                       
Income applicable to common shareholders – continuing operations
  $ 27,037       105,046     $ 2,401       104,563  
Effect of dilutive securities:
                               
Share-based awards other than participating securities
          87             118  
Convertible preferred stock
                10       361  
Income applicable to common shareholders – continuing operations
  $ 27,037       105,133     $ 2,411       105,042  
                                 
Discontinued operations:
                               
Income from discontinued operations, net of tax
  $ (29 )     105,133     $ 42,216       105,042  
 
 
   
Six Months Ended
   
Six Months Ended
 
   
June 30, 2013
   
June 30, 2012
 
   
Income
   
Shares
   
Income
   
Shares
 
Basic:
                       
Continuing operations:
                       
Net income applicable to Helix
  $ 28,826           $ 110,368        
Less: Income from discontinued operations, net of tax
    (1,029 )           (91,069 )      
Income from continuing operations
    27,797             19,299        
Less: Undistributed income allocable to participating securities – continuing operations
    (201 )           (194 )      
Income applicable to common shareholders – continuing operations
  $ 27,596    
 105,039 
    $ 19,105    
 104,547 
 
 
 
   
Six Months Ended
   
Six Months Ended
 
   
June 30, 2013
   
June 30, 2012
 
   
Income
   
Shares
   
Income
   
Shares
 
Discontinued operations:
                       
Income from discontinued operations, net of tax
  $ 1,029           $ 91,069        
Less: Undistributed income allocable to participating securities – discontinued operations
    (7 )           (917 )      
Income applicable to common shareholders – discontinued operations
  $ 1,022    
 105,039 
    $ 90,152    
 104,547 
 
 
Diluted:
                       
Continuing operations:
                       
Income applicable to common shareholders – continuing operations
  $ 27,596       105,039     $ 19,105       104,547  
Effect of dilutive securities:
                               
Share-based awards other than participating securities
          102             104  
Undistributed income reallocated to participating securities
    1             1        
Convertible preferred stock
                20       361  
Income applicable to common shareholders – continuing operations
  $ 27,597       105,141     $ 19,126       105,012  
                                 
Discontinued operations:
                               
Income from discontinued operations, net of tax
  $ 1,029       105,141     $ 91,069       105,012  
 
No diluted shares were included for the 2032 Notes for the three- and six-month periods ended June 30, 2013 and 2012 as the conversion trigger of $32.53 per share was not met, and because we have the right to settle any such future conversions in cash at our sole discretion (Note 7).
 
Note 11 — Employee Benefit Plans 
 
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 and restated effective May 9, 2012 (the “2005 Incentive Plan”).  As of June 30, 2013, there were 6.5 million shares available for issuance under the 2005 Incentive Plan, which includes a maximum of 2.0 million shares that may be granted as incentive stock options.  There were no stock option grants in the three- and six-month periods ended June 30, 2013 and 2012.  During the six-month period ended June 30, 2013, the following grants of share-based awards were made to executive officers and non-employee members of our Board of Directors under the 2005 Incentive Plan: 
 
Date of Grant
   
Shares
   
Grant Date Fair Value Per Share
   
Vesting Period
                   
January 2, 2013 (1)
   
89,329
 
$
20.64
   
33% per year over three years
January 2, 2013 (2)
   
89,329
   
30.96
   
100% on January 1, 2016
January 2, 2013 (3)
   
1,620
   
20.64
   
100% on January 1, 2015
April 1, 2013 (3)
   
2,814
   
22.88
   
100% on January 1, 2015
 
 
(1) Reflects the grant of restricted shares to our executive officers.
 
 
(2) Reflects the grant of performance share units (“PSUs”) to our executive officers.  The estimated fair value of the PSUs on grant date was determined using a Monte Carlo simulation model.  The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum award being 200% of the original awarded PSUs and the minimum amount being zero.  The vested PSUs will be settled in an equivalent number of shares of our common stock unless the Compensation Committee of our Board of Directors elects to pay in cash.
 
 
 
(3) Reflects the grant of restricted shares to certain members of our Board of Directors.
 
Compensation cost is recognized over the respective vesting periods on a straight-line basis.  For the three- and six-month periods ended June 30, 2013, $1.9 million and $5.1 million, respectively, were recognized as stock-based compensation expense related to share-based awards as compared with $1.8 million and $3.7 million for the three- and six-month periods ended June 30, 2012.  Additionally, for the first quarter of 2013, $1.3 million of stock-based compensation expense was reflected within our discontinued operations as a component of “Loss on sale of business, net of tax” (Note 4).
 
Long-Term Incentive Cash Plan 
 
The 2005 Incentive Plan and the 2009 Long-Term Incentive Cash Plan (the “LTI Plans”) provide long-term cash-based compensation to eligible employees.  Cash awards historically have been both fixed sum amounts payable (for non-executive management only) as well as cash awards indexed to our common stock with the payment amount at each vesting date fluctuating based on the performance of our common stock (for both executive and non-executive management).  These are measured based on the performance of our stock price over the applicable award period compared to a base price determined by the Compensation Committee of our Board of Directors at the time of the award.  Cash award payments under the LTI Plans are made each year on the anniversary date of the award.  Cash awards granted prior to 2012 have a vesting period of five years and cash awards granted in 2012 and 2013 have a vesting period of three years.  This share-based component is considered a liability plan and as such is re-measured to fair value each reporting period with corresponding changes being recorded as a charge to earnings as deemed appropriate. 
 
The cash awards made under the LTI Plans totaled $5.9 million in 2013 and $4.2 million in 2012.  Such awards were made to our executive officers and selected management employees in 2013 and to our executive officers in 2012.  No cash awards were given to non-executive employees in 2012.  Total compensation expense associated with the cash awards issued pursuant to the LTI Plans was $1.7 million ($0.8 million related to our executive officers) and $4.2 million ($2.4 million related to our executive officers) for the three- and six-month periods ended June 30, 2013, respectively.  For the three- and six-month periods ended June 30, 2012, total compensation expense associated with the cash awards issued pursuant to the LTI Plans was $1.2 million ($0.8 million related to our executive officers) and $3.6 million ($2.9 million related to our executive officers), respectively.  The liability balance for the cash awards issued under the LTI Plans was $9.9 million at June 30, 2013 and $13.0 million at December 31, 2012, including $8.1 million at June 30, 2013 and $11.7 million at December 31, 2012 associated with the variable portion of the cash awards issued under the LTI plans.
 
Employee Stock Purchase Plan 
 
In May 2012, our shareholders approved the Helix Energy Solutions Group, Inc. Employee Stock Purchase Plan (the “ESPP”).  The ESPP has 1.5 million authorized shares of our common stock, of which 1.4 million shares were available for issuance as of June 30, 2013.  Eligible employees who participate in the ESPP may purchase shares of our common stock through payroll deductions on an after-tax basis over a four-month period beginning on January 1, May 1, and September 1 of each year during the term of the ESPP, subject to certain restrictions and limitations established by the Compensation Committee of our Board of Directors and Section 423 of the Internal Revenue Code.  The per share price of common stock purchased under the ESPP is equal to 85% of the lesser of (i) its fair market value on the first trading day of the purchase period or (ii) its fair market value on the last trading day of the purchase period.  The first purchase period under the ESPP began on September 1, 2012.  The total value of the ESPP awards is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock.  Share-based compensation expense with respect to the ESPP was $0.2 million and $0.4 million for the three- and six-month periods ended June 30, 2013.
 
For more information regarding our employee benefit plans, including our stock-based compensation plans, our long-term incentive cash plan and our employee stock purchase plan, see Note 9 of our 2012 Form 10-K.
 
 
Note 12 — Business Segment Information 
 
In 2012, our operations were conducted through the following lines of business: contracting services and oil and gas.  We have disaggregated our contracting services operations into two reportable segments: Contracting Services and Production Facilities.  Our Contracting Services segment includes well intervention, robotics and subsea construction operations (see Note 2 for disclosures regarding the dispositions of our remaining subsea construction vessels and related assets).  The Production Facilities segment includes our consolidated investment in the HP I and Kommandor LLC as well as our equity investments in Deepwater Gateway and Independence Hub that are accounted for under the equity method.  All material intercompany transactions between the segments have been eliminated.  In February 2013, we sold ERT and as a result, we have presented the assets and liabilities included in the sale of ERT and the historical operating results of our former Oil and Gas segment as discontinued operations in the accompanying condensed consolidated financial statements.  See Note 4 for additional information regarding our discontinued operations. 
 
We evaluate our performance based on operating income and income before income taxes of each segment.  Segment assets are comprised of all assets attributable to the reportable segment.  Certain financial data by reportable segment are summarized as follows (in thousands): 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
Revenues —
                       
Contracting Services
  $ 225,356     $ 209,557     $ 423,410     $ 454,101  
Production Facilities
    24,174       19,963       44,567       39,985  
Intercompany elimination
    (17,352 )     (32,059 )     (38,370 )     (66,783 )
Total
  $ 232,178     $ 197,461     $ 429,607     $ 427,303  
                                 
Income (loss) from operations —
                               
Contracting Services
  $ 47,600     $ 19,223     $ 86,904     $ 78,347  
Production Facilities
    14,643       9,882       25,828       19,931  
Corporate
    (14,207 )     (22,334 )     (47,738 )     (38,419 )
Intercompany elimination
    (839 )     98       (2,559 )     (2,922 )
Total
  $ 47,197     $ 6,869     $ 62,435     $ 56,937  
                                 
Equity in earnings of equity investments
  $ 683     $ 5,748     $ 1,293     $ 6,155  
 
Intercompany segment revenues are as follows (in thousands): 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Contracting Services
    17,352       20,538     $ 33,697     $ 43,739  
Production Facilities
          11,521       4,673       23,044  
Total
  $ 17,352     $ 32,059     $ 38,370     $ 66,783  
 
Intercompany segment profits (losses) (which only relate to intercompany capital projects) are as follows (in thousands): 
 
   
Three Months Ended
   
Six Months Ended
 
   
June 30,
   
June 30,
 
   
2013
   
2012
   
2013
   
2012
 
                         
Contracting Services
    883       (55 )   $ 2,647     $ 3,009  
Production Facilities
    (44 )     (43 )     (88 )     (87 )
Total
  $ 839     $ (98 )   $ 2,559     $ 2,922  
 
 
Segment assets are comprised of all assets attributable to each reportable segment.  The following table reflected total assets by reportable segment (in thousands): 
 
   
June 30,
   
December 31,
 
   
2013
   
2012
 
             
Contracting Services
  $ 1,957,299     $ 1,974,763  
Production Facilities
    490,772       503,531  
Corporate and Other
    26,678       8,059  
Discontinued Operations
          900,227  
Total
  $ 2,474,749     $ 3,386,580  
 
Note 13 — Related Party Transactions 
 
In April 2000, ERT acquired a 20% working interest in Gunnison, a deepwater Gulf of Mexico prospect, from a third party.  Financing for the exploratory costs of approximately $20 million was provided by an investment partnership, OKCD Investments, Ltd. (“OKCD”), the investors of which include current and former Helix management, in exchange for a revenue interest that is an overriding royalty interest of 25% of ERT’s 20% working interest.  Production began in December 2003.  Payments to OKCD during the period in which Helix owned ERT totaled $0.6 million in the three-month period ended March 31, 2013, and $2.2 million and $3.9 million, respectively, in the three- and six-month periods ended June 30, 2012.  Our Chief Executive Officer, Owen Kratz, through Class A limited partnership interests in OKCD, personally owns approximately 84% of the partnership.  Payments to OKCD by Helix ceased with the sale of ERT in February 2013, when the royalty agreement with OKCD was transferred to a third party along with ERT (and all of its assets and obligations).
 
Note 14 — Commitments and Contingencies and Other Matters 
 
Commitments 
 
In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semi-submersible well intervention vessel, the Q5000.  This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of the Q5000.  Under the terms of this contract, payments are made in a fixed percentage of the contract price, together with any variations, on contractually scheduled dates.  At June 30, 2013, our total investment in the Q5000 was $146.0 million, including $115.9 million of scheduled payments made to the shipyard. 
 
In July 2012, we contracted to charter the Skandi Constructor for use in our North Sea well intervention operations.  The vessel was delivered to us on April 1, 2013.  The initial term of the charter will expire in March 2016. 
 
In August 2012, we acquired the Discoverer 534 drillship from a subsidiary of Transocean Ltd. for $85 million.  The vessel, renamed the Helix 534, is currently undergoing upgrades and modifications to render it suitable for use as a well intervention vessel.  At June 30, 2013, our investment in the acquisition and subsequent upgrades to and modifications of the Helix 534 totaled $164.6 million, including related well control equipment. 
 
In January 2013, we contracted to charter the Rem Installer for use in our robotics operations.  The term of the charter will be three years from the delivery date.  The vessel was delivered to us in July 2013. 
 
In February 2013, we contracted to charter the Grand Canyon II and Grand Canyon III for use in our robotics operations.  The terms of the charters will be five years from the respective delivery dates, which are expected to be in 2014 and 2015. 
 
 
Contingencies and Claims 
 
Under terms of the equity purchase agreement for the sale of ERT, we required the buyer to provide bonding in a sufficient amount as determined by the Bureau of Ocean Energy Management (“BOEM”) to cover the decommissioning costs of ERT’s lease properties and thus to replace and allow for a full discharge of our existing guaranty to the BOEM for ERT’s lease obligations.  We further agreed in the equity purchase agreement that to the extent that the buyer is required to post bonding collateral in an amount greater than $100 million to obtain bonds in the aggregate amount required by the BOEM in order for the BOEM to release our guaranty of ERT’s lease obligations, that we would provide incremental collateral above that amount, if and to the extent required, to the surety/ies providing bonding for ERT’s deepwater properties (the Bushwood and Phoenix fields) in the form of letter(s) of credit, up to the next $50 million of required collateral, for a period not to exceed one year from issuance of the letter(s) of credit, after which the buyer would then be required to provide all collateral associated with the bonding requirements with respect to our former oil and gas properties.  Because the collateral required for bonding the full amount of the current decommissioning assessments for ERT’s lease properties did not exceed the $100 million threshold, we were not required to provide any collateral for the sureties to issue the requisite bonding.
 
In 2007, we were subcontracted to perform development work for a large gas field offshore India.  Work commenced in the fourth quarter of 2007 and we completed our scope of work in the third quarter of 2009.  To date we have collected approximately $303 million related to this project with an amount of trade receivables yet to be collected.  We have requested arbitration in India pursuant to the terms of the subcontract to pursue our claims and the prime contractor has also requested arbitration and has asserted certain counterclaims against us.  If we are not successful in resolving these matters through ongoing discussions with the prime contractor, then arbitration in India remains a potential remedy.  Based on a number of factors associated with the ongoing negotiations with the prime contractor, in 2010 we established a $4 million allowance against our trade receivable balance that reduces its balance to an amount we believe is ultimately realizable ($17.5 million).  At the time of this filing no final commercial resolution of this matter has been reached. 
 
We have received value added tax (VAT) assessments from the State of Andhra Pradesh, India (the “State”) in the amount of approximately $28 million for the tax years 2010, 2009, 2008 and 2007 related to an Indian subsea construction and diving contract that we entered into in December 2006.  The State claims that we owe unpaid taxes related to products consumed by us during the period of the contract.  We are of the opinion that the State has arbitrarily made these assessments and has no foundation for them.  We believe that we have complied with all rules and regulations as related to VAT in the State.  We also believe that our position is supported by law and intend to vigorously defend our position.  However, the ultimate outcome of these assessments and our potential liability from them, if any, cannot be determined at this time.  If the current assessments are upheld, they may have a material negative effect on our consolidated results of operations while also impacting our financial position. 
 
Litigation 
 
On July 8, 2011, a shareholder derivative lawsuit styled City of Sterling Heights Police & Fire Retirement System v. Owen Kratz, et al. was filed in the United States District Court for the Southern District of Texas, Houston Division.  In the suit, the plaintiff makes claims against our Board of Directors, certain of our former directors, certain of our current and former executives, and the independent compensation consultant to the Compensation Committee of our Board of Directors, for breaches of the fiduciary duty of loyalty, unjust enrichment and aiding and abetting the alleged breaches of fiduciary duty relating to the long-term equity awards granted in 2010 to the Company’s then executive officers who are defendants.  The Company filed a motion to dismiss the claim asserting that the plaintiff has not (i) pled specific facts excusing its failure to make pre-suit demand on the Company’s Board of Directors as required by Minnesota law; (ii) filed proper verification; or (iii) stated a claim.  A ruling regarding the motion is pending.
 
On May 12, 2012, a shareholder derivative lawsuit styled Mark Lucas v. Owen Kratz, et al. was filed in the 270th Judicial District in the District Court of Harris County, Texas.  In the suit, the plaintiff makes claims against our Board of Directors, certain of our former directors, certain of our current and former executive officers and the independent compensation consultant to the Compensation Committee of our Board of Directors, for breaches of the fiduciary duties of candor, good faith and loyalty, unjust enrichment and aiding and abetting the alleged breaches of fiduciary duty relating to the long-term equity awards granted in 2010 to certain of our executive officers.  This case is essentially a “copycat” complaint asserting
 
 
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similar causes of action arising out of the same facts as set forth in the federal action described above.  The plaintiff is generally demanding disgorgement of the excessive compensation, restraint on the disposition/exercise of the alleged improperly awarded equity, implementation of additional internal controls, and attorney’s fees and costs of litigation.  We filed motions to stay and dismiss the proceeding, which motions were denied by the trial court judge.  We filed a petition for a writ of mandamus with the state appellate court, in which we requested that court to direct the district court to grant our motion to stay or dismiss the case.  The appellate court has not ruled on our petition at the time of this filing. 
 
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.
 
Note 15 — Fair Value Measurements
 
Certain of our financial assets and liabilities are measured and reported at fair value on a recurring basis as required under applicable accounting requirements.  These requirements establish 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 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 for 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 other financial instruments measured at fair value on a recurring basis at June 30, 2013 (in thousands): 
 
     
Level 1
     
Level 2 (1)
     
Level 3
     
Total
     
Valuation Technique
 
Liabilities:
                                       
Fair value of long-term debt (2)
   
534,709
     
114,371
     
     
649,080
     
(a)
 
Foreign exchange contracts
   
     
17,155
     
     
17,155
     
(c)
 
Total liability
 
$
534,709
   
$
131,526
   
$
   
$
666,235
         
 
(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 based on market data.  Our actual results may differ from our estimates, and these differences could be positive or negative. 
 
 
(2)
See Note 7 for additional information regarding our long-term debt.  The fair value of our debt is as follows: 
 
   
June 30, 2013
 
   
Carrying Value
   
Fair Value (c)
 
             
2032 Notes (mature March 2032) (a)
  $ 200,000     $ 251,500  
Senior Unsecured Notes (mature January 2016) (b)
    274,960       283,209  
MARAD Debt (matures February 2027)
    102,759       114,371  
Total debt
  $ 577,719     $ 649,080  
 
    (a)
Carrying value excludes the related unamortized debt discount of $29.1 million at June 30, 2013.
    (b)
In June 2013, we elected to redeem the remaining Senior Unsecured Notes on July 22, 2013, and we redeemed these notes in full on that date. 
    (c)
The estimated fair value of all debt, other than the MARAD debt, 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 marketplace with similar terms.  The fair value of the MARAD Debt was estimated using Level 2 fair value inputs using the market approach.
 
Note 16 — Derivative Instruments and Hedging Activities
 
Our continuing operations are exposed to market risk associated with interest rates and foreign currency exchange rates.  Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates.  All derivatives are reflected in the accompanying condensed consolidated balance sheets at fair value, unless otherwise noted.
 
We engage solely 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 the hedges are effective.  These fair value changes are recorded as a component of accumulated other comprehensive income or loss (a component of shareholders’ equity) until the hedged transactions occur and are recognized in earnings.  The ineffective portion of changes in the fair value of cash flow hedges 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.
 
For additional information regarding our accounting for derivatives, see Notes 2 and 17 of our 2012 Form 10-K. 
 
Interest Rate Risk
 
We historically entered into interest rate swaps to stabilize cash flows related to our long-term debt subject to variable interest rates.  We de-designated all of our interest rate swaps outstanding as hedging instruments in December 2012 following the announcement of the sale of ERT.  We cash settled all outstanding interest rate swap contracts in February 2013.  We had no debt outstanding with variable interest rates at June 30, 2013. 
 
Foreign Currency Exchange Rate Risk
 
Because we operate in various regions in the world, we conduct a portion of our business in currencies other than the U.S. dollar.  We entered into various foreign currency forwards to stabilize expected cash outflows relating to certain vessel charters that are denominated in British pounds and Norwegian kroner.
 
 
In January 2013, we entered into foreign currency exchange contracts to hedge the foreign currency exposure to potential variability in cash flows associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million), through September 2017.  In February 2013, we entered into similar foreign currency exchange contracts for the Grand Canyon II and Grand Canyon III charter payments ($100.4 million and $98.8 million) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million), through July 2019 and February 2020, respectively.  These contracts currently qualify for hedge accounting treatment.  All of our remaining foreign exchange contracts are not accounted for as hedge contracts and changes in their fair value are being marked-to-market each reporting period.
 
Quantitative Disclosures Related to Derivative Instruments 
 
As a result of the announcement in December 2012 of the sale of ERT, we de-designated all of our remaining oil and natural gas derivative contracts as hedging instruments.  In addition, under the terms of our former credit agreement (Note 7), we were required to use a portion of the after-tax proceeds from the sales of ERT, the Caesar and Express to make payments to reduce our indebtedness.  Because of the probability that the former term loan debt would be totally repaid before the expiration of our interest rate swaps, we also concluded that the swaps no longer qualified as cash flow hedges.  In February 2013, we settled all of our outstanding commodity derivative contracts and interest rate swap contracts for approximately $22.5 million and $0.6 million, respectively.
 
The following table presents the fair value and balance sheet classification of our derivative instruments that were not designated as hedging instruments (in thousands): 
 
   
As of June 30, 2013
 
As of December 31, 2012
 
   
Balance Sheet
 
Fair
 
Balance Sheet
 
Fair
 
   
Location
 
Value
 
Location
 
Value
 
Asset Derivatives:
                 
Oil contracts
 
Other current assets
$
 
Other current assets
$
 5,800
 
Foreign exchange contracts
 
Other current assets
 
 
Other current assets
 
 146
 
     
$
   
$
 5,946
 
                   
Liability Derivatives:
                 
Oil contracts
 
Accrued liabilities
$
 
Accrued liabilities
$
 15,777
 
Interest rate swaps
 
Accrued liabilities
 
 
Accrued liabilities
 
 489
 
Foreign exchange contracts
 
Accrued liabilities
 
 492
 
Accrued liabilities
 
 
Interest rate swaps
 
Other long-term liabilities
 
 
Other long-term liabilities
 
 32
 
     
$
 492
   
$
 16,298
 
 
As of June 30, 2013, our only derivative instruments designated as cash flow hedges were foreign currency exchange contracts related to the Grand Canyon, Grand Canyon II and Grand Canyon III charter payments.  The fair value of these hedging instruments as of June 30, 2013 totaled $16.7 million, $1.9 million of which is reflected in “Accrued liabilities” and the remaining $14.8 million of which is reflected in “Other long-term liabilities” in the accompanying condensed consolidated balance sheet.  The last of these contracts will settle in February 2020.
 
 
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