UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
Form 10-Q
þ☑ Quarterly report pursuant to SectionQUARTERLY REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended September 30, 20182019
or
¨☐ Transition report pursuant to SectionTRANSITION REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from__________ to__________
Commission File Number Number: 001-32936
logo.jpghlxlogo.jpg
 
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
Minnesota
95-3409686
(State or other jurisdiction
of incorporation or organization)
 
95–3409686
(I.R.S. Employer
Identification No.)
    
3505 West Sam Houston Parkway North
Suite 400 
HoustonTexas
77043
(Address of principal executive offices) 
77043
(Zip Code)
(281) (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)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common StockHLXNew York Stock Exchange
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. þ☑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). þ☑Yes¨☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company.  See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
Large accelerated filerþ
☑
Accelerated filer ☐
Accelerated filer ¨
Non-accelerated filer ¨☐
Smaller reporting company¨
☐
Emerging growth company¨
(Do not check if a smaller reporting company)☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨☐ Yes þ☑ No
As of October 19, 2018, 148,152,67218, 2019, 148,809,467 shares of common stock were outstanding.
 






TABLE OF CONTENTS
PART I. FINANCIAL INFORMATIONPAGE
    
Item 1. Financial Statements: 
    
  
Condensed Consolidated Balance Sheets –
September 30, 20182019 (Unaudited) and December 31, 20172018
3
    
  
Condensed Consolidated Statements of Operations (Unaudited) –
Three and nine months ended September 30, 20182019 and 20172018
4
    
  
Condensed Consolidated Statements of OperationsComprehensive Income (Unaudited) –
NineThree and nine months ended September 30, 20182019 and 20172018
5
    
  
Condensed Consolidated Statements of Comprehensive Income (Loss)Shareholders’ Equity (Unaudited) –
Three and nine months ended September 30, 20182019 and 20172018
6
    
  
Condensed Consolidated Statements of Cash FlowsShareholders’ Equity (Unaudited) –
Nine months ended September 30, 20182019 and 20172018
7
    
  
Condensed Consolidated Statements of Cash Flows (Unaudited) –
Nine months ended September 30, 2019 and 2018
8
Notes to Condensed Consolidated Financial Statements (Unaudited)
89
    
Item 2. 
Management’s Discussion and Analysis of Financial Condition and Results of Operations
3031
    
Item 3. 
Quantitative and Qualitative Disclosures About Market Risk
45
    
Item 4. 
Controls and Procedures
45
    
PART II. OTHER INFORMATION 
    
Item 1. 
Legal Proceedings
4645
    
Item 2. 
Unregistered Sales of Equity Securities and Use of Proceeds
46
    
Item 6. 
Exhibits
46
    
  
Signatures
47


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PART I.  FINANCIAL INFORMATION
Item 1.Financial Statements
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
September 30,
2018		 December 31,
2017		September 30,
2019		 December 31,
2018
(Unaudited)  (Unaudited)  
ASSETS
Current assets:      
Cash and cash equivalents$325,092
 $266,592
$286,340
 $279,459
Accounts receivable:      
Trade, net of allowance for uncollectible accounts of $2,75291,001
 113,336
Trade, net of allowance for uncollectible accounts of $091,707
 67,932
Unbilled and other66,396
 29,947
72,548
 51,943
Other current assets47,450
 41,768
61,751
 51,594
Total current assets529,939
 451,643
512,346
 450,928
Property and equipment2,727,760
 2,695,772
2,819,932
 2,785,778
Less accumulated depreciation(956,209) (889,783)(1,022,138) (959,033)
Property and equipment, net1,771,551
 1,805,989
1,797,794
 1,826,745
Operating lease right-of-use assets213,048
 —
Other assets, net76,985
 105,205
90,323
 70,057
Total assets$2,378,475
 $2,362,837
$2,613,511
 $2,347,730
      
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:      
Accounts payable$62,844
 $81,299
$79,122
 $54,813
Accrued liabilities84,431
 71,680
71,982
 85,594
Income tax payable5,859
 2,799
—
 3,829
Current maturities of long-term debt46,784
 109,861
108,468
 47,252
Current operating lease liabilities52,840
 —
Total current liabilities199,918
 265,639
312,412
 191,488
Long-term debt401,265
 385,766
304,932
 393,063
Operating lease liabilities164,761
 —
Deferred tax liabilities102,742
 103,349
110,118
 105,862
Other non-current liabilities42,382
 40,690
39,008
 39,538
Total liabilities746,307
 795,444
931,231
 729,951


 

Redeemable noncontrolling interests3,257
 —
Shareholders’ equity:
      
Common stock, no par, 240,000 shares authorized, 148,147 and 147,740 shares issued, respectively1,306,703
 1,284,274
Common stock, no par, 240,000 shares authorized, 148,802 and 148,203 shares issued, respectively1,316,805
 1,308,709
Retained earnings396,781
 352,906
437,418
 383,034
Accumulated other comprehensive loss(71,316) (69,787)(75,200) (73,964)
Total shareholders’ equity
1,632,168
 1,567,393
1,679,023
 1,617,779
Total liabilities and shareholders’ equity
$2,378,475
 $2,362,837
Total liabilities, redeemable noncontrolling interests and shareholders’ equity
$2,613,511
 $2,347,730
The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
(in thousands, except per share amounts)
Three Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2018 20172019 2018 2019 2018
          
Net revenues$212,575
 $163,260
$212,609
 $212,575
 $581,160
 $581,462
Cost of sales160,582
 142,119
157,535
 160,582
 469,898
 473,589
Gross profit51,993
 21,141
55,074
 51,993
 111,262
 107,873
Gain on disposition of assets, net146
 —
—
 146
 —
 146
Selling, general and administrative expenses(20,762) (16,374)(16,076) (20,762) (48,923) (52,986)
Income from operations31,377
 4,767
38,998
 31,377
 62,339
 55,033
Equity in losses of investment(107) (153)(13) (107) (82) (378)
Net interest expense(3,249) (3,615)(1,901) (3,249) (6,204) (10,744)
Loss on extinguishment of long-term debt(2) —
—
 (2) (18) (1,183)
Other expense, net(709) (551)(2,285) (709) (2,430) (3,225)
Other income – oil and gas652
 303
Royalty income and other362
 652
 2,897
 4,068
Income before income taxes27,962
 751
35,161
 27,962
 56,502
 43,571
Income tax provision (benefit)841
 (1,539)
Income tax provision3,539
 841
 6,739
 1,226
Net income$27,121
 $2,290
31,622
 27,121
 49,763
 42,345
Net loss attributable to redeemable noncontrolling interests(73) —
 (104) —
Net income attributable to common shareholders$31,695
 $27,121
 $49,867
 $42,345
          
Earnings per share of common stock:          
Basic$0.18
 $0.02
$0.21
 $0.18
 $0.33
 $0.29
Diluted$0.18
 $0.02
$0.21
 $0.18
 $0.33
 $0.29
          
Weighted average common shares outstanding:          
Basic146,700
 145,958
147,575
 146,700
 147,506
 146,679
Diluted146,964
 145,958
148,354
 146,964
 148,086
 146,761
The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONSCOMPREHENSIVE INCOME
(UNAUDITED)
(in thousands, except per share amounts)thousands)
 Nine Months Ended
September 30,
 2018 2017
    
Net revenues$581,462
 $418,117
Cost of sales473,589
 379,434
Gross profit107,873
 38,683
Gain (loss) on disposition of assets, net146
 (39)
Selling, general and administrative expenses(52,986) (46,532)
Income (loss) from operations55,033
 (7,888)
Equity in losses of investment(378) (457)
Net interest expense(10,744) (15,480)
Loss on extinguishment of long-term debt(1,183) (397)
Other expense, net(3,225) (619)
Other income – oil and gas4,068
 3,196
Income (loss) before income taxes43,571
 (21,645)
Income tax provision (benefit)1,226
 (1,117)
Net income (loss)$42,345
 $(20,528)
    
Earnings (loss) per share of common stock:   
Basic$0.29
 $(0.14)
Diluted$0.29
 $(0.14)
    
Weighted average common shares outstanding:   
Basic146,679
 145,057
Diluted146,761
 145,057
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
        
Net income$31,622
 $27,121
 $49,763
 $42,345
Other comprehensive loss, net of tax:       
Net unrealized gain (loss) on hedges arising during the period(274) (88) (701) 839
Reclassifications to net income1,046
 1,799
 4,867
 5,233
Income taxes on hedges(156) (357) (838) (1,298)
Net change in hedges, net of tax616
 1,354
 3,328
 4,774
Unrealized loss on note receivable arising during the period—
 —
 —
 (629)
Income taxes on note receivable—
 —
 —
 132
Unrealized loss on note receivable, net of tax—
 —
 —
 (497)
Foreign currency translation loss(4,301) (1,421) (4,564) (4,277)
Other comprehensive loss, net of tax(3,685) (67) (1,236) —
Comprehensive income27,937
 27,054
 48,527
 42,345
Less comprehensive loss attributable to redeemable noncontrolling interests:       
Net loss(73) —
 (104) —
Foreign currency translation loss(78) —
 (78) —
Comprehensive loss attributable to redeemable noncontrolling interests(151) —
 (182) —
Comprehensive income attributable to common shareholders$28,088
 $27,054
 $48,709
 $42,345
The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)SHAREHOLDERS’ EQUITY
(UNAUDITED)
(in thousands)
 Three Months Ended
September 30,
 2018 2017
    
Net income$27,121
 $2,290
Other comprehensive income (loss), net of tax:   
Net unrealized gain (loss) on hedges arising during the period(88) 2,297
Reclassifications to net income1,799
 3,383
Income taxes on hedges(357) (1,992)
Net change in hedges, net of tax1,354
 3,688
Foreign currency translation gain (loss)(1,421) 5,513
Other comprehensive income (loss), net of tax(67) 9,201
Comprehensive income$27,054
 $11,491
 Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
 Shares Amount    
            
Balance, June 30, 2019148,759
 $1,314,163
 $405,748
 $(71,515) $1,648,396
 $3,383
Net income (loss)—
 —
 31,695
 —
 31,695
 (73)
Foreign currency translation adjustments—
 —
 —
 (4,301) (4,301) (78)
Unrealized gain on hedges, net of tax—
 —
 —
 616
 616
 —
Accretion of redeemable noncontrolling interests—
 —
 (25) —
 (25) 25
Activity in company stock plans, net and other43
 214
 —
 —
 214
 —
Share-based compensation—
 2,428
 —
 —
 2,428
 —
Balance, September 30, 2019148,802
 $1,316,805
 $437,418
 $(75,200) $1,679,023
 $3,257
 Nine Months Ended
September 30,
 2018 2017
    
Net income (loss)$42,345
 $(20,528)
Other comprehensive income, net of tax:   
Net unrealized gain on hedges arising during the period839
 4,141
Reclassifications to net income (loss)5,233
 10,822
Income taxes on hedges(1,298) (5,256)
Net change in hedges, net of tax4,774
 9,707
Unrealized loss on note receivable arising during the period(629) —
Income taxes on note receivable132
 —
Unrealized loss on note receivable, net of tax(497) —
Foreign currency translation gain (loss)(4,277) 14,905
Other comprehensive income, net of tax—
 24,612
Comprehensive income$42,345
 $4,084
 Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
 Shares Amount    
            
Balance, June 30, 2018148,107
 $1,303,984
 $369,659
 $(71,249) $1,602,394
 $—
Net income—
 —
 27,121
 —
 27,121
 —
Foreign currency translation adjustments—
 —
 —
 (1,421) (1,421) —
Unrealized gain on hedges, net of tax—
 —
 —
 1,354
 1,354
 —
Equity component of debt discount on convertible senior notes—
 (2) —
 —
 (2) —
Activity in company stock plans, net and other40
 213
 —
 —
 213
 —
Share-based compensation—
 2,509
 —
 —
 2,509
 —
Balance, September 30, 2018148,147
 $1,306,703
 $396,781
 $(71,316) $1,632,168
 $—
The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(UNAUDITED)
(in thousands)
 Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
 Shares Amount    
            
Balance, December 31, 2018148,203
 $1,308,709
 $383,034
 $(73,964) $1,617,779
 $—
Net income (loss)—
 —
 49,867
 —
 49,867
 (104)
Reclassification of deferred gain from sale and leaseback transaction to retained earnings—
 —
 4,560
 —
 4,560
 —
Foreign currency translation adjustments—
 —
 —
 (4,564) (4,564) (78)
Unrealized gain on hedges, net of tax—
 —
 —
 3,328
 3,328
 —
Issuance of redeemable noncontrolling interests—
 —
 —
 —
 —
 3,396
Accretion of redeemable noncontrolling interests—
 —
 (43) —
 (43) 43
Activity in company stock plans, net and other599
 (765) —
 —
 (765) —
Share-based compensation—
 8,861
 —
 —
 8,861
 —
Balance, September 30, 2019148,802
 $1,316,805
 $437,418
 $(75,200) $1,679,023
 $3,257
 Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
 Shares Amount    
            
Balance, December 31, 2017147,740
 $1,284,274
 $352,906
 $(69,787) $1,567,393
 $—
Net income—
 —
 42,345
 —
 42,345
 —
Reclassification of stranded tax effect to retained earnings—
 —
 1,530
 (1,530) —
 —
Foreign currency translation adjustments—
 —
 —
 (4,277) (4,277) —
Unrealized gain on hedges, net of tax—
 —
 —
 4,774
 4,774
 —
Unrealized loss on note receivable, net of tax—
 —
 —
 (497) (497) —
Equity component of debt discount on convertible senior notes—
 15,411
 —
 —
 15,411
 —
Activity in company stock plans, net and other407
 (438) —
 —
 (438) —
Share-based compensation—
 7,456
 —
 —
 7,456
 —
Balance, September 30, 2018148,147
 $1,306,703
 $396,781
 $(71,316) $1,632,168
 $—
The accompanying notes are an integral part of these condensed consolidated financial statements.

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
(in thousands)
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2018 20172019 2018
Cash flows from operating activities:      
Net income (loss)$42,345
 $(20,528)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:   
Net income$49,763
 $42,345
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization83,339
 82,670
84,420
 83,339
Amortization of debt discount4,238
 3,487
Amortization of debt discounts4,642
 4,238
Amortization of debt issuance costs2,703
 5,238
2,752
 2,703
Share-based compensation7,569
 7,613
8,979
 7,569
Deferred income taxes(5,716) (3,019)2,347
 (5,716)
Equity in losses of investment378
 457
82
 378
(Gain) loss on disposition of assets, net(146) 39
Gain on disposition of assets, net—
 (146)
Loss on extinguishment of long-term debt1,183
 397
18
 1,183
Unrealized gain on derivative contracts, net(2,289) (4,291)(2,351) (2,289)
Changes in operating assets and liabilities:   
Changes in operating assets and liabilities, net of acquisitions:   
Accounts receivable, net(15,769) (21,709)(45,399) (15,769)
Other current assets(5,662) (12,145)12,215
 (5,662)
Income tax payable2,963
 2,742
Income tax payable, net of income tax receivable(3,143) 2,963
Accounts payable and accrued liabilities6,968
 30,675
(14,765) 6,968
Other non-current, net28,723
 (40,303)
Other, net(9,683) 28,723
Net cash provided by operating activities150,827
 31,323
89,877
 150,827
      
Cash flows from investing activities:      
Capital expenditures(55,431) (131,428)(45,636) (55,431)
STL acquisition, net(4,081) —
Proceeds from sale of assets25
 10,000
2,550
 25
Net cash used in investing activities(55,406) (121,428)(47,167) (55,406)
      
Cash flows from financing activities:      
Issuance of Convertible Senior Notes due 2023125,000
 —
—
 125,000
Repurchase of Convertible Senior Notes due 2032(60,365) —
—
 (60,365)
Proceeds from term loan—
 100,000
35,000
 —
Repayment of term loan(62,872) (193,508)(34,567) (62,872)
Repayment of Nordea Q5000 Loan(26,786) (26,786)(26,786) (26,786)
Repayment of MARAD Debt(6,532) (6,222)(6,858) (6,532)
Debt issuance costs(3,867) (3,694)(1,544) (3,867)
Net proceeds from issuance of common stock—
 219,504
Payments related to tax withholding for share-based compensation(1,058) (1,306)(1,345) (1,058)
Proceeds from issuance of ESPP shares506
 432
462
 506
Net cash provided by (used in) financing activities(35,974) 88,420
Net cash used in financing activities(35,638) (35,974)
      
Effect of exchange rate changes on cash and cash equivalents(947) 1,927
(191) (947)
Net increase in cash and cash equivalents58,500
 242
6,881
 58,500
Cash and cash equivalents:      
Balance, beginning of year266,592
 356,647
279,459
 266,592
Balance, end of period$325,092
 $356,889
$286,340
 $325,092
The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
Note 1 — Basis of Presentation and New Accounting Standards
 
The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, “Helix” or the “Company”)Helix). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its 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 (“GAAP”).
 
The accompanying condensed consolidated financial statements have been prepared in conformity with GAAP in U.S. dollars and are consistent in all material respects with those applied in our 20172018 Annual Report on Form 10-K (“20172018 Form 10-K”) with the exception of the impact of adopting the new lease accounting standard in 2019 (see below). 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. We have made all adjustments, (which werewhich, unless otherwise disclosed, are of normal recurring adjustments)nature, that we believe 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 nine-month periods ended September 30, 20182019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2018.2019. Our balance sheet as of December 31, 20172018 included herein has been derived from the audited balance sheet as of December 31, 20172018 included in our 20172018 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 20172018 Form 10-K.
 
Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format.
 
New accounting standards adopted
 
In May 2014,February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASC 606”). The FASB also issued several subsequent updates to promote more consistent interpretation and application of the principles outlined in the standard. ASC 606 provides a five-step approach to account for revenue arising from contracts with customers in order for an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
We adopted ASC 606 effective January 1, 2018 using the modified retrospective method by applying the five-step model to all contracts that were not completed as of the date of adoption. For contracts that were modified before the date of adoption, we have considered the modification guidance within the new standard and determined that the revenues recognized prior to adoption for such modified contracts were not impacted. We did not record any cumulative effect adjustment to the opening balance of our retained earnings as of January 1, 2018 as the adoption of ASC 606 had an insignificant impact on our prior year earnings. On our consolidated balance sheet, contract assets that were previously presented as “Other accounts receivable” are now a component of “Other current assets.” The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. ASC 606 requires additional disclosures with regard to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We do not expect the adoption of this guidance to have a material impact on the measurement or recognition of our revenues on an ongoing basis. The impact of ASC 606 for the three- and nine-month periods ended September 30, 2018, which primarily relates to the acceleration of lump sum demobilization fees (Note 9), was as follows (in thousands): 

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 September 30, 2018
 
As
Reported
 Pro Forma Without Adoption of ASC 606 Effect of Change
Balance Sheet     
Assets     
Unbilled and other$66,396
 $67,263
 $(867)
Other current assets47,450
 46,104
 1,346
Liabilities     
Accrued liabilities84,431
 84,705
 (274)
Deferred tax liabilities102,742
 102,584
 158
Equity     
Retained earnings396,781
 396,186
 595
 Three Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2018
 
As
Reported
 Pro Forma Without Adoption of ASC 606 Effect of Change 
As
Reported
 Pro Forma Without Adoption of ASC 606 Effect of Change
Statement of Operations           
Net revenues$212,575
 $212,965
 $(390) $581,462
 $580,709
 $753
Income from operations31,377
 31,767
 (390) 55,033
 54,280
 753
Income before income taxes27,962
 28,352
 (390) 43,571
 42,818
 753
Income tax provision841
 923
 (82) 1,226
 1,068
 158
Net income27,121
 27,429
 (308) 42,345
 41,750
 595
In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows a reclassification from accumulated other comprehensive income (loss) (“OCI”) to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) that was enacted on December 22, 2017. We adopted this guidance as of January 1, 2018 by making the election to reclassify $1.5 million of net stranded tax benefits from accumulated OCI to retained earnings (Note 8). On an ongoing basis, we release the income tax effects of individual items in accumulated OCI as those items are sold or settled at the applicable statutory rate.
New accounting standards issued but not yet effective
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842)” (“ASC 842”). The FASB also issued several, which was updated by subsequent updates to provide improvements to the new guidance.amendments. ASC 842 amends the existing accounting standards for leases to increase transparency and comparability among organizations. The new guidance requires a lessee to recognize a lease right-of-use asset and related lease liability for most leases, including those classified as operating leases under current GAAP.leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We are in the process of implementingadopted ASC 842. We have accumulated our lease contracts and are aggregating them into a lease software platform. We are also assessing non-lease contracts for inclusion of embedded leases, updating our policies and controls and establishing appropriate presentation and disclosure changes resulting from the new guidance. While our implementation plan is still ongoing, management’s assessment based on our current portfolio of leases, including vessel charters, is that our assets and liabilities will increase by a significant amount as we recognize right-of-use assets and lease liabilities on our balance sheet upon our adoption of ASC 842. We do not expect the new guidance to have any significant impact on our earnings or cash flows. We will adopt ASC 842 by applying the new guidance in the first quarter of 2019 using the modified retrospective method. We also elected the package of practical expedients permitted under the transition guidance that, among other things, allows companies to carry forward their historical lease classification. Our adoption of ASC 842 resulted in the recognition of operating lease liabilities of $259.0 million and recognizingcorresponding right-of-use (“ROU”) assets of $253.4 million (net of existing prepaid/deferred rent balances) as of January 1, 2019. In addition, we reclassified the remaining deferred gain of $4.6 million (net of deferred taxes of $0.9 million) on a cumulative-effect adjustment2016 sale and leaseback transaction to the opening balance of retained earnings. Subsequent to adoption, leases in foreign currencies will generate foreign currency gains and losses, and we will no longer amortize the deferred gain from the aforementioned sale and leaseback transaction. Aside from these changes, ASC 842 is not expected to have a material impact on our net earnings or cash flows.
New accounting standards issued but not yet effective
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets (including trade receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance will be effective for us as of January 1, 2020. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
 
We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.


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Note 2 — Company Overview
 
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our “life of field” services are segregated into three3 reportable business segments: Well Intervention, Robotics and Production Facilities (Note 12).
 
Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our Well Intervention segment also includes intervention riser systems (“IRSs”), some of which we provide on a stand-alone basis, and subsea intervention lubricators (“SILs”). Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and two2 chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. We also have a semi-submersible well intervention vessel under construction,completion, the Q7000. Our well intervention equipment includes intervention riser systems (“IRSs”) and subsea intervention lubricators (“SILs”), some of which we provide on a stand-alone basis.
 
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills,a ROVDrill, which are designed to complement offshore construction and well intervention services, and three ROV3 robotics support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III. We also utilize spot vessels as needed.needed, including the Ross Candies, which is under a flexible charter agreement.
 
Our Production Facilities segment includes the Helix ProducerI (the “HP I”), a ship-shaped dynamically positioned floating production vessel, and the Helix Fast Response System (the “HFRS”), which provides certain operators access to our Q4000 and HP I vessels in the event of a well control incident in the Gulf of Mexico. The HP I has been under contract to the Phoenix field operator since February 2013, currently under a fixed fee agreement through at least June 1, 2023. We are also party to an agreement providing various operators through March 31, 2019 with access to the HFRS for well control purposes. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 5)4), and several wells and related infrastructure associated with the Droshky Prospect that we acquired from Marathon Oil Corporation (“Marathon Oil”) on January 18, 2019. All of our current production facilities activities are located in the Gulf of Mexico.
On May 29, 2019, we acquired a 70% controlling interest in Subsea Technologies Group Limited (“STL”), a subsea engineering firm based in Aberdeen, Scotland, for $5.1 million, including $4.1 million in cash and $1.0 million that we loaned to STL in December 2018. The acquisition is expected to strengthen our supply of subsea intervention systems. The holders of the remaining 30% noncontrolling interest have the right to put their shares to us in June 2024. These redeemable noncontrolling interests have been recognized as temporary equity at their estimated fair value of $3.4 million at the acquisition date. We recognized $2.4 million of identifiable intangible assets and $6.9 million of goodwill, which are reflected in “Other assets” in the accompanying condensed consolidated balance sheet (Note 3). Goodwill is related to the synergies expected from the acquisition. The ultimate fair values of acquired assets, liabilities and noncontrolling interests are provisional and pending final assessment of the valuations. STL is included in our Well Intervention segment (Note 12) and its revenue and earnings are immaterial to our consolidated results.
Note 3 — Details of Certain Accounts
 
Other current assets consist of the following (in thousands):
 September 30,
2019		 December 31,
2018
    
Contract assets (Note 9)$580
 $5,829
Prepaids14,876
 10,306
Deferred costs (Note 9)26,424
 27,368
Other receivable (Note 13)13,000
 —
Other6,871
 8,091
Total other current assets$61,751
 $51,594
 September 30,
2018		 December 31,
2017
    
Contract assets (Note 9)$1,346
 $—
Prepaids13,275
 10,102
Deferred costs (Note 9)26,248
 27,204
Other6,581
 4,462
Total other current assets$47,450
 $41,768

 

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Other assets, net consist of the following (in thousands):
 September 30,
2019		 December 31,
2018
    
Prepaids$861
 $5,896
Deferred recertification and dry dock costs, net16,678
 8,525
Deferred costs (Note 9)20,695
 38,574
Charter deposit (1)
12,544
 12,544
Other receivable (Note 13)26,702
 —
Goodwill (Note 2)6,637
 —
Intangible assets with finite lives, net (Note 2)3,703
 1,402
Other2,503
 3,116
Total other assets, net$90,323
 $70,057
 September 30,
2018		 December 31,
2017
    
Note receivable (1)
$—
 $3,758
Prepaids6,342
 7,666
Deferred dry dock costs, net8,854
 12,368
Deferred costs (Note 9)44,964
 63,767
Charter fee deposit (2)
12,544
 12,544
Other4,281
 5,102
Total other assets, net$76,985
 $105,205

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(1)The
This amount at December 31, 2017 reflects the fair value of a note receivable that was issued to us by a customer as part of a payment forgiveness arrangement. On July 6, 2018, a third party acquired our note receivable for $2.0 million. During the nine-month period ended September 30, 2018, we reversed a $0.6 million unrealized gain previously recorded in Accumulated OCI and recorded a $1.1 million other than temporary loss to account for the reduction in the fair value of our note receivable.
(2)
This amountis deposited with the vessel owner is to be used to reduce our final charter payments forof the Siem Helix2. to offset certain payment obligations associated with the vessel at the end of the charter term.
 
Accrued liabilities consist of the following (in thousands):
 September 30,
2019		 December 31,
2018
    
Accrued payroll and related benefits$25,853
 $43,079
Investee losses in excess of investment (Note 4)7,638
 5,125
Deferred revenue (Note 9)10,814
 10,103
Asset retirement obligations (Note 13)11,556
 —
Derivative liability (Note 17)2,723
 9,311
Other13,398
 17,976
Total accrued liabilities$71,982
 $85,594
 September 30,
2018		 December 31,
2017
    
Accrued payroll and related benefits$42,496
 $30,685
Deferred revenue (Note 9)13,597
 12,609
Derivative liability (Note 15)9,160
 10,625
Other19,178
 17,761
Total accrued liabilities$84,431
 $71,680

 
Other non-current liabilities consist of the following (in thousands):
 September 30,
2019		 December 31,
2018
    
Investee losses in excess of investment (Note 4)$—
 $6,035
Deferred gain on sale of property (1)
—
 5,052
Deferred revenue (Note 9)9,196
 15,767
Asset retirement obligations (Note 13)27,564
 —
Derivative liability (Note 17)—
 884
Other2,248
 11,800
Total other non-current liabilities$39,008
 $39,538
 September 30,
2018		 December 31,
2017
    
Investee losses in excess of investment (Note 5)$5,965
 $7,567
Deferred gain on sale of property (1)
5,288
 5,838
Deferred revenue (Note 9)17,968
 8,744
Derivative liability (Note 15)1,822
 8,150
Other11,339
 10,391
Total other non-current liabilities$42,382
 $40,690

(1)Relates to the sale and lease-back in January 2016 of our office and warehouse property located in Aberdeen, Scotland. The deferred gain ishad been amortized over thea 15-year minimum lease term.term prior to our adoption of ASC 842 on January 1, 2019. See Note 1 for the effect of ASC 842 on this deferred gain.
Note 4 — 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): 
 Nine Months Ended
September 30,
 2018 2017
    
Interest paid, net of interest capitalized$6,620
 $9,002
Income taxes paid4,699
 3,967
Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $8.5 million as of September 30, 2018 and $16.9 million as of December 31, 2017.


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Note 54 — Equity Method Investments
 
We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in the U.S. Gulf of Mexico in a water depth of 8,000 feet. Since weWe are committed to providing our pro-rata portion of the necessary level of financial support for Independence Hub to pay its obligations as they become due, we recorded liabilitiesdue. The platform decommissioning process is currently underway and is expected to be substantially completed within the next 12 months. We had a liability of $8.2$7.6 million at September 30, 20182019 and $9.8$11.2 million at December 31, 20172018 for our share of theIndependence Hub’s estimated obligations, net of remaining working capital. These liabilities areThis liability is reflected in “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.
Note 5 — Leases
We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. We also sublease some of our facilities under non-cancelable sublease agreements.
Leases with a term greater than one year are recognized on our balance sheet as ROU assets and lease liabilities. We have elected to not recognize on our balance sheet leases with an initial term of one year or less. Lease liabilities and their corresponding ROU assets are recorded at the commencement date based on the present value of lease payments over the expected lease term. We use our incremental borrowing rate, which would be the rate incurred to borrow on a collateralized basis over a similar term in a similar economic environment, to calculate the present value of lease payments. ROU assets are adjusted for any initial direct costs paid or incentives received.
We separate our long-term vessel charters between their lease components and non-lease services. We estimate the lease component using the residual estimate approach by estimating the non-lease services, which are primarily crew, repair and maintenance, and regulatory certification costs. For all other leases, we have not separated the lease components and non-lease services. The lease term may include options to extend or terminate the lease when it is reasonably certain that we will exercise the option.
We recognize operating lease cost on a straight-line basis over the lease term for both (i) leases that are recognized on the balance sheet and (ii) short-term leases. We recognize lease cost related to variable lease payments that are not recognized on the balance sheet in the period in which the obligation is incurred. The following table details the components of our lease cost (in thousands):
 Three Months Ended Nine Months Ended
 September 30, 2019 September 30, 2019
    
Operating lease cost$18,002
 $54,191
Variable lease cost3,630
 9,927
Short-term lease cost5,587
 14,549
Sublease income(351) (1,077)
Net lease cost$26,868
 $77,590


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Maturities of our operating lease liabilities as of September 30, 2019 are as follows (in thousands):
 Vessels Facilities and Equipment Total
      
Remainder of 2019$15,416
 $1,717
 $17,133
202059,942
 6,391
 66,333
202154,481
 5,694
 60,175
202252,105
 5,103
 57,208
202334,580
 4,522
 39,102
Thereafter2,470
 10,163
 12,633
Total lease payments$218,994
 $33,590
 $252,584
Less: imputed interest(28,272) (6,711) (34,983)
Total operating lease liabilities$190,722
 $26,879
 $217,601
      
Current operating lease liabilities$47,914
 $4,926
 $52,840
Non-current operating lease liabilities142,808
 21,953
 164,761
Total operating lease liabilities$190,722
 $26,879
 $217,601

The following table presents the weighted average remaining lease term and discount rate:
September 30, 2019
Weighted average remaining lease term4.2 years
Weighted average discount rate7.54%

The following table presents other information related to our operating leases (in thousands):
 Nine Months Ended
 September 30, 2019
  
Cash paid for operating lease liabilities$54,538
ROU assets obtained in exchange for new operating lease obligations921

As previously disclosed in our 2018 Form 10-K and under the previous lease accounting standard, future minimum lease payments for our operating leases as of December 31, 2018 were as follows (in thousands):
 Vessels Facilities and Equipment Total
      
2019$116,620
 $5,881
 $122,501
202096,800
 5,340
 102,140
202189,216
 5,185
 94,401
202290,371
 5,064
 95,435
202351,266
 4,533
 55,799
Thereafter—
 10,448
 10,448
Total lease payments$444,273
 $36,451
 $480,724


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Note 6 —Long-Term Debt
 
Scheduled maturities of our long-term debt outstanding as of September 30, 20182019 are as follows (in thousands):
Term
Loan (1)
 
2022
Notes
 2023 Notes 
MARAD
Debt
 
Nordea
Q5000
Loan
 Total
Term
Loan (1)
 
2022
Notes
 2023 Notes 
MARAD
Debt
 
Nordea
Q5000
Loan
 Total
                      
Less than one year$4,212
 $—
 $—
 $6,858
 $35,714
 $46,784
$3,500
 $—
 $—
 $7,200
 $98,214
 $108,914
One to two years30,417
 —
 —
 7,200
 98,214
 135,831
3,500
 —
 —
 7,560
 —
 11,060
Two to three years—
 —
 —
 7,560
 —
 7,560
27,125
 125,000
 —
 7,937
 —
 160,062
Three to four years—
 125,000
 —
 7,937
 —
 132,937
—
 —
 125,000
 8,333
 —
 133,333
Four to five years—
 —
 125,000
 8,333
 —
 133,333
—
 —
 —
 8,749
 —
 8,749
Over five years—
 —
 —
 32,580
 —
 32,580
—
 —
 —
 23,831
 —
 23,831
Gross debt34,125
 125,000
 125,000
 63,610
 98,214
 445,949
Unamortized debt discounts (2)
—
 (8,784) (15,376) —
 —
 (24,160)
Unamortized debt issuance costs (3)
(438) (1,368) (2,478) (3,659) (446) (8,389)
Total debt34,629
 125,000
 125,000
 70,468
 133,928
 489,025
33,687
 114,848
 107,146
 59,951
 97,768
 413,400
Current maturities(4,212) —
 —
 (6,858) (35,714) (46,784)
Long-term debt, less current maturities30,417
 125,000
 125,000
 63,610
 98,214
 442,241
Unamortized debt discount (2)
—
 (11,772) (18,528) —
 —
 (30,300)
Unamortized debt issuance costs (3)
(434) (1,898) (2,986) (4,147) (1,211) (10,676)
Less: current maturities(3,500) —
 —
 (7,200) (97,768) (108,468)
Long-term debt$29,983
 $111,330
 $103,486
 $59,463
 $97,003
 $401,265
$30,187
 $114,848
 $107,146
 $52,751
 $—
 $304,932
(1)Term Loan borrowing pursuant to the Credit Agreement (as defined below) matures in June 2020. Scheduled principal repayments of the Term Loan have been adjusted to reflect prepayments made in March 2018.December 2021.
(2)Our Convertible Senior Notes due 2022 (the “2022 Notes”)and 2023 will increase to their face amountamounts through accretion of thetheir debt discountdiscounts to interest expense through May 2022. Our Convertible Senior Notes due2022 and September 2023, (the “2023 Notes”) will increase to their face amount through accretion of the debt discount through September 2023.respectively.
(3)Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.
 
Below is a summary of certain components of our indebtedness:
 
Credit Agreement
 
On June 30, 2017, we entered into an Amended and Restated Credit Agreement (the(and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). TheOn June 28, 2019, we amended and restated credit facility is comprised of a $100 millionour existing term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) under the Credit Agreement. The Credit Agreement is comprised of up to $150a $35 million (the “Revolving Loans”).Term Loan and a Revolving Credit Facility of $175 million. The Revolving Credit Facility permits us to obtain letters of credit up to a sublimit of $25 million. Pursuant to the Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may request aggregate commitments of up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans, or a combination thereof.Facility. As of September 30, 2018,2019, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the applicable leverage ratio covenant,ratios, totaled $146.7$172.6 million, net of $3.3$2.4 million of letters of credit issued under that facility.
 

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The Term Loan andBorrowings under the Revolving Loans (together, the “Loans”),Credit Agreement bear interest, at our election, bear interest in relation toat either Bank of America’s base rate, tothe LIBOR or a LIBORcomparable successor rate, or a combination thereof. The Term Loan bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin of 3.25%2.25%. The Term Loan bearing interest at a LIBOR rate will bear interest per annum at the LIBOR or a comparable successor rate selected by us plus a margin of 4.25%3.25%. The interest rate on the Term Loan was 6.49%5.29% as of September 30, 2018. The2019. Borrowings under the Revolving LoansCredit Facility bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin ranging from 1.75%1.50% to 3.25%2.50%. TheBorrowings under the Revolving LoansCredit Facility bearing interest at a LIBOR rate will bear interest per annum at the LIBOR or a comparable successor rate selected by us plus a margin ranging from 2.75%2.50% to 4.25%3.50%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate Loans timesloans multiplied by the daily amount available to be drawn under the applicable letter of credit. Margins on borrowings under the Revolving LoansCredit Facility will vary in relation to the Consolidated Total Leverage Ratio (as defined below) as provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of ourthe Revolving Credit Facility.

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The Term Loan principal is required to be repaid in quarterly installments totaling 5% inof 2.5% of the first loan year, 10% inaggregate principal amount of the second loan year and 15% in the third loan year,Term Loan, with a balloon payment at maturity. Installment amounts are subject to adjustment for any prepayments on the Term Loan. We may elect to prepay amountsindebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amountsindebtedness outstanding under the Revolving Credit Facility without premium or penalty, and may reborrow any amounts prepaid up to the amount of the Revolving Credit Facility. The LoansBorrowings under the Credit Agreement mature on June 30, 2020.December 31, 2021.
 
The Credit Agreement and the other loan documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which we consider customary for this type of facility.transaction. The covenants include certain restrictions on our and certain of our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum ratiosratio requirements of EBITDA to interest charges (“Consolidated(Consolidated Interest Coverage Ratio”) andRatio), funded debt to EBITDA (“Consolidated(Consolidated Total Leverage Ratio”),Ratio) and provided that if there are no Loans outstanding, thesecured funded debt ratio requirement permits us to offset a certain amount of cash against the funded debt used in the calculation (“Consolidated Net Leverage Ratio”). After the Term Loan is repaid in full, if there are any Loans outstanding, including unreimbursed draws under letters of credit issued under the Revolving Credit Facility, we also are required to ensure that the ratio of our total secured indebtedness to EBITDA (“Consolidated(Consolidated Secured Leverage Ratio”) does not exceed a maximum permitted ratio. The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness that is outstanding.Ratio).
 
We may from time to time designate one or more of our new foreign subsidiaries as subsidiaries not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”). The debt and EBITDA of thosethe Unrestricted Subsidiaries with the exception of Helix Q5000 Holdings, S.à r.l. (“Q5000 Holdings”), a wholly owned subsidiary incorporated in Luxembourg, are not included in the calculations of our financial covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”).covenants. Our obligations under the Credit Agreement, are guaranteed by our domestic subsidiaries (except Cal Dive I - Title XI, Inc.) and by Canyon Offshore Limited, a wholly owned Scottish subsidiary. Our obligations under the Credit Agreement, andthose of our subsidiary guarantors under their guarantee, are secured by (i) most of the assets of the parent company, (ii) the shares of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Helix Robotics Solutions Limited (formerly known as Canyon Offshore Limited,Limited) and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Canyon OffshoreHelix Robotics Solutions Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.
 
In March 2018, we prepaid $61 million of the Term Loanthen-existing term loan with a portion of the net proceeds from the 2023 Notes. We recognized a $0.9 million loss to write off the related unamortized debt issuance costs. In June 2019, in connection with the amendment of the Credit Agreement we wrote off the remaining unamortized debt issuance costs which loss isassociated with a lender exiting the Credit Agreement. These losses are presented as “Loss on extinguishment of long-term debt” in the accompanying condensed consolidated statementstatements of operations.
 

In January 2019, contemporaneously with our purchase from Marathon Oil of several wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, we amended the Credit Agreement to permit the issuance of certain security to third parties for required plug and abandonment (“P&A”) obligations and to make certain capital expenditures in connection with acquired assets (Notes 2 and 13).
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Convertible Senior Notes Due 2022 (“2022 Notes”)
 
On November 1, 2016, we completed thea public offering and sale of ourthe 2022 Notes in the aggregate principal amount of $125 million. The 2022 Notes bear interest at a rate of 4.25% per annum and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2022 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
 
Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, if certain conditions are met, we may redeem all or any portion of the 2022 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” (as defined in the indenture governing the 2022 Notes). Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2022 Notes).
 

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The indenture governing the 2022 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2022 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2022 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
 
The 2022 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million ($11.0 million net of tax) as a result of separating the equity component. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. For the three- and nine-month periods ended September 30, 2019, interest expense (including amortization of the debt discount) related to the 2022 Notes totaled $2.1 million and $6.2 million, respectively. For the three- and nine-month periods ended September 30, 2018, interest expense (including amortization of the debt discount) related to the 2022 Notes totaled $2.0 million and $6.1 million, respectively. The remaining unamortized amount of the debt discount of the 2022 Notes was $11.8$8.8 million at September 30, 20182019 and $13.9$11.0 million at December 31, 2017.2018.
 
Convertible Senior Notes Due 2023 (“2023 Notes”)
 
On March 20, 2018, we completed thea public offering and sale of ourthe 2023 Notes in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2023 Notes were approximately $121$121.0 million after deducting the underwriters’ discounts and commissions and estimated offering expenses. We used the net proceeds from the issuance of the 2023 Notes to fund the required repurchase by us of $59.3 million in principal of theConvertible Senior Notes due 2032 Notes(the “2032 Notes”) described below and to prepay $61$61.0 million of our Term Loan.the then-existing term loan.
 
The 2023 Notes bear interest at a rate of 4.125% per annum and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2018. The 2023 Notes mature on September 15, 2023 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2023 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $9.47 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
 
Prior to March 15, 2021, the 2023 Notes are not redeemable. On or after March 15, 2021, if certain conditions are met, we may redeem all or any portion of the 2023 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” (as defined in the indenture governing the 2023 Notes). Holders of the 2023 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2023 Notes).
 

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The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2023 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2023 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
 

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The 2023 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2023 Notes, we recorded a debt discount of $20.1 million ($15.9 million net of tax) as a result of separating the equity component. The effective interest rate for the 2023 Notes is 7.8% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2023 Notes at their inception. For the three- and nine-month periods ended September 30, 2019, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled $2.1 million and $6.3 million, respectively. For the three- and nine-month periods ended September 30, 2018, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled $2.1 million and $4.3 million, respectively. The remaining unamortized amount of the debt discount of the 2023 Notes was $18.5$15.4 million at September 30, 2019 and $17.8 million at December 31, 2018.
 
MARAD Debt
 
This U.S. government-guaranteed financing (the “MARAD Debt”), pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. The MARAD Debt is payable in equal semi-annual installments, matures in February 2027 and bears interest at a rate of 4.93%.
 
Nordea Credit Agreement
 
In September 2014, Q5000 Holdings entered into a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in an amount of up to $250 million. The Nordea Q5000 Loan was funded in the amount of $250 million in April 2015 at the time the Q5000 vessel was delivered to us. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.
 
The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. The remaining principal balance and unamortized debt issuance costs related to the Nordea Q5000 Loan are classified as current. Q5000 Holdings may elect to prepay amountsindebtedness outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Quarterly principal installments are subject to adjustment for any prepayments on this debt. In June 2015, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 15)17). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under ourthe Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.
 
The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.
 

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Convertible Senior Notes Due 2032 
 
In March 2012, we issued $200 million of 3.25% Convertible Senior Notes, which were originally scheduled to mature on March 15, 2032. In March 2018, we made a tender offer for the repurchase of the 2032 Notes outstanding on the first repurchase date as required by the indenture governing the 2032 Notes, and as a result we repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018. The total repurchase price was $59.5 million, including $0.2 million in fees. We recognized a $0.2 million loss in connection with the repurchase of the notes.2032 Notes. The loss is presented as “Loss on extinguishment of long-term debt” in the accompanying condensed consolidated statement of operations. On May 4, 2018, we redeemed the remaining $0.8 million in aggregate principal amount of the 2032 Notes.
 

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Other 
 
In accordance with ourthe Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio, a consolidated total leverage ratio and variousa consolidated secured leverage ratios,ratio, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. As of September 30, 2018,2019, we were in compliance with these covenants.
 
The following table details the components of our net interest expense (in thousands):
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
        
Interest expense$7,694
 $8,171
 $23,635
 $24,511
Interest income(652) (994) (2,085) (2,263)
Capitalized interest(5,141) (3,928) (15,346) (11,504)
Net interest expense$1,901
 $3,249
 $6,204
 $10,744
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
        
Interest expense$8,171
 $8,336
 $24,511
 $30,183
Interest income(994) (792) (2,263) (2,056)
Capitalized interest(3,928) (3,929) (11,504) (12,647)
Net interest expense$3,249
 $3,615
 $10,744
 $15,480

Note 7 — Income Taxes
On December 22, 2017, the 2017 Tax Act was enacted. The 2017 Tax Act is comprehensive tax reform legislation that contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate from 35% to 21%, a mandatory one-time tax on un-repatriated accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, and a shift from U.S. taxation on worldwide income of multinational corporations to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries).
We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118 (“SAB 118”), which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, to the 2017 Tax Act. SAB 118 allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. We believe the provisional amounts recorded during the fourth quarter of 2017 continue to represent a reasonable estimate of the accounting implications of the 2017 Tax Act. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated through September 30, 2018.
 
We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation, and the outcomes of tax disputes are inherently uncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.
 

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Our estimated annualThe effective tax rate, adjusted for discrete tax items, is applied to our pretax lossrates for the current interim period in 2018 as we previously made the determination that a return to the annualized effective tax rate method is appropriate for 2018. A year-to-date effective tax rate method was used for recording income taxes for the comparative interim period in 2017 based on expectations that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate.
three- and nine-month periods ended September 30, 2019 were 10.1% and 11.9%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, 2018 were 3.0% and 2.8%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, 2017increases were (204.9)% and 5.2%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, the reduction ofimprovements in profitability in the U.S. corporate income tax rate from 35% to 21% as a result of the 2017 Tax Act, and a tax charge in 2017 attributable to a change in tax position related to our foreign taxes.year over year.
 
Income taxes are provided based on the U.S. statutory rate 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 U.S. statutory rate and our effective rate are as follows:
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
        
U.S. statutory rate21.0 % 21.0 % 21.0 % 21.0 %
Foreign provision(10.1) (18.5) (9.7) (19.1)
Other(0.8) 0.5
 0.6
 0.9
Effective rate10.1 % 3.0 % 11.9 % 2.8 %


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 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
        
U.S. statutory rate21.0 % 35.0 % 21.0 % 35.0 %
Foreign provision(18.5) (241.5) (19.1) 2.8
Change in tax position (1)
—
 —
 —
 (29.3)
Other0.5
 1.6
 0.9
 (3.3)
Effective rate3.0 % (204.9)% 2.8 % 5.2 %
(1)As a result of a change in tax position related to our foreign taxes, we recorded a tax charge of $6.3 million in June 2017.
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Note 8 —Shareholders’ Equity
 
The components of Accumulated OCIaccumulated other comprehensive loss (“accumulated OCI”) are as follows (in thousands):
September 30,
2018		 December 31,
2017		September 30,
2019		 December 31,
2018
      
Cumulative foreign currency translation adjustment$(66,966) $(62,689)$(74,419) $(69,855)
Net unrealized loss on hedges, net of tax (1)
(4,350) (7,507)(781) (4,109)
Unrealized gain on note receivable, net of tax (2)
—
 409
Accumulated other comprehensive loss$(71,316) $(69,787)
Accumulated OCI$(75,200) $(73,964)
(1)
Relates to foreign currency hedges for the Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan (Note 15). Balance at September 30, 2018 was17) and is net of deferred income taxes totaling $1.1 million. Balance$0.2 million at September 30, 2019 and $1.0 million at December 31, 2017 was net of deferred income taxes of $4.0 million, $1.6 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 1).2018.
(2)Balance at December 31, 2017 was net of deferred income taxes of $0.2 million, $0.1 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 1).

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Note 9 —Revenue from Contracts with Customers
 
We generate revenue in our Well Intervention segment by supplying the vessels, personnel, and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the durationDisaggregation of the intervention services. We also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs, trenchers and ROVDrills to provide subsea construction, inspection, repair and maintenance services to oil and gas companies as well as subsea trenching and burial of pipelines and cables for the oil and gas and the renewable energy industries. We also provide integrated robotic services by supplying vessels that deploy the ROVs and trenchers. Our Production Facilities segment generates revenue by providing the personnel, vessel and equipment for oil and natural gas processing as well as well control response services.Revenue
 
Our revenues are derived primarily from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.
We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration for these activities as well as contract fulfillment activities is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer.
The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We do not generally provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. The estimated amount of variable consideration is constrained and is only included in the transaction price to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.
Dayrate Contracts.  Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g. operating rate, standby rate, repair rate). The invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.
Dayrate contracts also may contain fees charged to the customer for mobilizing and demobilizing equipment and personnel. Mobilization and demobilization fees are associated with contract fulfillment activities, and related revenue (subject to any constraint on estimates of variable consideration) is allocated to the single performance obligation and recognized ratably over the initial term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer. See further discussion on contract liabilities under “Contract balances” below.
We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.

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A dayrate contract modification involving an extension of the contract by adding additional days of services is generally accounted prospectively for as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.
Lump Sum Contracts.  Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.
We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue (either as an increase in or a reduction of revenue) on a cumulative catch-up basis.
Disaggregation of revenue
The following table provides information about disaggregated revenue by contract duration for the three- and nine-month periods ended September 30, 2018 (in thousands):
Well Intervention Robotics Production Facilities 
Intercompany Elimination (1)
 Total Revenue Well Intervention Robotics Production Facilities 
Intercompany Eliminations (1)
 Total Revenue
Three months ended September 30, 2019          
Short-termShort-term$53,018
 $26,809
 $—
 $—
 $79,827
Long-term (2)
Long-term (2)
117,188
 25,100
 13,777
 (23,283) 132,782
TotalTotal$170,206
 $51,909
 $13,777
 $(23,283) $212,609
          
Three months ended September 30, 2018Three months ended September 30, 2018                  
Short-termShort-term$39,548
 $29,877
 $—
 $—
 $69,425
Long-term (2)
Long-term (2)
114,893
 24,463
 15,877
 (12,083) 143,150
TotalTotal$154,441
 $54,340
 $15,877
 $(12,083) $212,575
          
          
Nine months ended September 30, 2019          
Short-term$39,548
 $29,877
 $—
 $—
 $69,425
Short-term$145,611
 $80,440
 $—
 $—
 $226,051
Long-term (2)
114,893
 24,463
 15,877
 (12,083) 143,150
Long-term (2)
305,900
 55,956
 44,651
 (51,398) 355,109
Total$154,441
 $54,340
 $15,877
 $(12,083) $212,575
Total$451,511
 $136,396
 $44,651
 $(51,398) $581,160
                   
Nine months ended September 30, 2018Nine months ended September 30, 2018                  
Short-term$143,510
 $74,050
 $—
 $—
 $217,560
Short-term$143,510
 $74,050
 $—
 $—
 $217,560
Long-term (2)
302,259
 46,519
 48,541
 (33,417) 363,902
Long-term (2)
302,259
 46,519
 48,541
 (33,417) 363,902
Total$445,769
 $120,569
 $48,541
 $(33,417) $581,462
Total$445,769
 $120,569
 $48,541
 $(33,417) $581,462

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(1)Intercompany revenues between Robotics and Well Interventionamong our business segments are under agreements that are considered long-term.
(2)Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.
 

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Contract balancesBalances
 
Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable that have been billed to customers are recorded as trade accounts receivable while accounts receivable that have not been billed to customers are recorded as unbilled accounts receivable.
 
Contract assets are rights to consideration in exchange for services that we have transferredprovided to a customer when that right is conditionalthose rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” on the accompanying condensed consolidated balance sheet.sheets (Note 3). Contract assets as of January 1, 2018 were immaterial while contract assets as of$0.6 million at September 30, 2018were $1.3 million. Impairment2019 and $5.8 million at December 31, 2018. We incurred no impairment losses recognized on our accounts receivable and contract assets were immaterial for the three- and nine-month periods ended September 30, 2019 and 2018.
 
Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to thea single performance obligation and recognized ratably over the contract term andand/or (ii) the amountamounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” on the accompanying condensed consolidated balance sheet.sheets (Note 3). Contract liabilities as of January 1, 2018 andtotaled $20.0 million at September 30, 2018 totaled $21.42019 and $25.9 million at December 31, 2018. Revenue recognized for the three- and nine-month periods ended September 30, 2019 included $4.0 million and $31.6$7.4 million, respectively.respectively, that were included in the contract liability balance at the beginning of each period. Revenue recognized for the three- and nine-month periods ended September 30, 2018 included $7.4 million and$10.8 $10.8 million, respectively, that were included in the contract liability balance at the beginning of each period.
 
We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.

Performance obligationsObligations
 
As of September 30, 2018, $1.2 billion2019, $833.8 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $118.0 million in 2018, $437.2$114.5 million in 2019, and $666.5$443.2 million in 2020 and $276.1 million in 2021 and thereafter. These amounts includedinclude fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms withinof our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at September 30, 2018.2019.
 
For the three- and nine-month periods ended September 30, 2019 and 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.
 

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Contract costsFulfillment Costs
 
Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which thesethe contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” on the accompanying condensed consolidated balance sheet.sheets (Note 3). Our deferred contract costs totaled $71.2$47.1 million as ofat September 30, 2019 and $65.9 million at December 31, 2018. For the three- and nine-month periods ended September 30, 2019, we recorded $7.7 million and $23.6 million, respectively, related to amortization of deferred contract costs existing at the beginning of each period. For the three- and nine-month periods ended September 30, 2018, we recorded $8.5 million and $25.6 million, respectively, related to amortization of deferred contract costs existing at the beginning of each period and thereperiod. There were no associated impairment losses.losses for any period presented.

20For additional information regarding revenue recognition, see Notes 2 and 10 to our 2018 Form 10-K.

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Note 10 — Earnings Per Share
 
We have shares of restricted stock issued and outstanding that are currently unvested. HoldersShares of restricted stock are considered participating securities because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock andstock. We are required to compute earnings per share (“EPS”) under the shares of restricted stock are thus considered participating securities.two-class method in periods in which we have earnings. Under applicable accounting guidance,the two-class method, the undistributed earnings for each period are allocated based on the participation rights of both common shareholders and the 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”) under the two class method in periods in which we have earnings. For periods in which we have a net loss we do not use the two classtwo-class method as holders of our restricted shares are not 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 net income or loss by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects 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 for the three- and nine-month periods ended September 30, 2018 are as follows (in thousands):
 Three Months Ended
September 30, 2019		 Three Months Ended
September 30, 2018
 Income Shares Income Shares
Basic:       
Net income attributable to common shareholders$31,695
   $27,121
  
Less: Undistributed earnings allocated to participating securities(261)   (260)  
Accretion of redeemable noncontrolling interests(25)   —
  
Net income available to common shareholders, basic$31,409
 147,575
 $26,861
 146,700
        
        
Diluted:       
Net income available to common shareholders, basic$31,409
 147,575
 $26,861
 146,700
Effect of dilutive securities:       
Share-based awards other than participating securities—
 779
 —
 264
Undistributed earnings reallocated to participating securities1
 —
 —
 —
Net income available to common shareholders, diluted$31,410
 148,354
 $26,861
 146,964

 Three Months Ended
September 30, 2018		 Three Months Ended
September 30, 2017
 Income Shares Income Shares
Basic:       
Net income$27,121
   $2,290
  
Less: Undistributed earnings allocated to participating securities(260)   (27)  
Undistributed earnings allocated to common shares$26,861
 146,700
 $2,263
 145,958
        
Diluted:       
Undistributed earnings allocated to common shares$26,861
 146,700
 $2,263
 145,958
Effect of dilutive securities:       
Share-based awards other than participating securities—
 264
 —
 —
Undistributed earnings reallocated to participating securities—
 —
 —
 —
Net income$26,861
 146,964
 $2,263
 145,958


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 Nine Months Ended
September 30, 2019		 Nine Months Ended
September 30, 2018
 Income Shares Income Shares
Basic:       
Net income attributable to common shareholders$49,867
   $42,345
  
Less: Undistributed earnings allocated to participating securities(435)   (407)  
Accretion of redeemable noncontrolling interests(43)   —
  
Net income available to common shareholders, basic$49,389
 147,506
 $41,938
 146,679
        
        
Diluted:       
Net income available to common shareholders, basic$49,389
 147,506
 $41,938
 146,679
Effect of dilutive securities:       
Share-based awards other than participating securities—
 580
 —
 82
Undistributed earnings reallocated to participating securities2
 —
 —
 —
Net income available to common shareholders, diluted$49,391
 148,086
 $41,938
 146,761
 Nine Months Ended
September 30, 2018		 Nine Months Ended
September 30, 2017
 Income Shares Income Shares
Basic:       
Net income (loss)$42,345
   $(20,528)  
Less: Undistributed earnings allocated to participating securities(407)   —
  
Undistributed earnings allocated to common shares$41,938
 146,679
 $(20,528) 145,057
        
Diluted:       
Undistributed earnings allocated to common shares$41,938
 146,679
 $(20,528) 145,057
Effect of dilutive securities:       
Share-based awards other than participating securities—
 82
 —
 —
Undistributed earnings reallocated to participating securities—
 —
 —
 —
Net income (loss)$41,938
 146,761
 $(20,528) 145,057

 
We had a net loss for the nine-month period ended September 30, 2017. Accordingly, our diluted EPS calculation for this period was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable period. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands): 
Nine Months Ended
September 30, 2017
Diluted shares (as reported)145,057
Share-based awards364
Total145,421
In addition, theThe following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2032 Notes were excluded from the diluted EPS calculation because we have the right and the intention to settle any such future conversions in cash (Note 6)as they were anti-dilutive (in thousands):
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
        
2022 Notes8,997
 8,997
 8,997
 8,997
2023 Notes13,202
 13,202
 13,202
 9,381
2032 Notes (1)
—
 —
 —
 701
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
        
2022 Notes8,997
 8,997
 8,997
 8,997
2023 Notes13,202
 —
 9,381
 —
2032 Notes (1)
—
 2,403
 701
 2,403

(1)The 2032 Notes were fully redeemed in May 2018.

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Note 11 — Employee Benefit Plans
 
Long-Term Incentive Plan 
 
We currently have 1 active long-term incentive plan: the 2005 Long-Term Incentive Plan, as amended and restated (the “2005 Incentive Plan”). On May 15, 2019, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan to: (i) authorize 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy, (ii) establish a maximum award limit applicable to independent members of our Board of Directors (our “Board”) under the 2005 Incentive Plan, (iii) require, subject to certain exceptions, that all awards under the 2005 Incentive Plan have a minimum vesting or restriction period of one year and (iv) remove certain requirements with respect to performance-based compensation under Section 162(m) of the Internal Revenue Code that were repealed by the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”). As of September 30, 2018,2019, there were 1.88.5 million shares of our common stock available for issuance under our long-term incentive plan, the 2005 Long-Term Incentive Plan, as amended and restated January 1, 2017 (the “2005 Incentive Plan”).Plan. During the nine-month period ended September 30, 2018,2019, the following grants of share-based awards were made under the 2005 Incentive Plan:

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Date of Grant  Shares / Units   
Grant Date
Fair Value
Per Share
  Vesting Period
           
January 2, 2018 (1)
  449,271
   $7.54
  33% per year over three years
January 2, 2018 (2)
  449,271
   10.44
  100% on January 2, 2021
January 2, 2018 (3)
  8,247
   7.54
  100% on January 1, 2020
April 2, 2018 (3)
  11,064
   5.79
  100% on January 1, 2020
July 2, 2018 (3)
  6,565
   8.33
  100% on January 1, 2020
August 21, 2018 (4)
  6,093
   8.97
  100% on August 21, 2019
Date of Grant  
Shares/
Units
   
Grant Date
Fair Value
Per Share/Unit
  Vesting Period
           
January 2, 2019 (1)
  688,540
   $5.41
  33% per year over three years
January 2, 2019 (2)
  688,540
   7.60
  100% on January 2, 2022
January 2, 2019 (3)
  11,841
   5.41
  100% on January 1, 2021
April 1, 2019 (3)
  7,625
   7.91
  100% on January 1, 2021
July 1, 2019 (3)
  8,727
   8.63
  100% on January 1, 2021
August 1, 2019 (4)
  7,151
   8.76
  100% on August 1, 2020
(1)Reflects grants of restricted stock to our executive officers.officers and select management employees.
(2)Reflects grants of performance share units (“PSUs”) to our executive officers.officers and select management employees. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original awarded PSUsPSU awards and the minimum amount being zero. These awards when vested can only be settled in shares of our common stock.0.
(3)Reflects grants of restricted stock to certain independent members of our Board of Directors (the “Board”) who have made an electionelected to take their quarterly fees in stock in lieu of cash.
(4)Reflects a grant of restricted stock made to a new independent member of our Board upon hisher joining our Board.
 
Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting periodsperiod on a straight-line basis. Forfeitures are recognized as they occur. For the three- and nine-month periods ended September 30, 2018, $1.52019, $1.2 million and $4.5$4.9 million respectively, were recognized as share-based compensation related to restricted stock. For the three- and nine-month periods ended September 30, 2017, $1.72018, $1.5 million and $5.4$4.5 million, respectively, were recognized as share-based compensation related to restricted stock.
 
The estimated fair value of PSUs is determined using a Monte Carlo simulation model. The PSUs granted prior to 2017 could be settled in either cash or shares of our common stock and were accounted for as liability awards. Beginning in 2017, PSUs granted are to be settled solely in shares of our common stock and 2018therefore are accounted for as equity awards whereas awards granted prior to 2017 are accounted for as liability awards. Compensation cost for PSUs that are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. PSUs that are accounted forbasis as liability awards are measured based onan increase to equity. For the estimated fair value at the balance sheet datethree- and changes in fair value of the awards arenine-month periods ended September 30, 2019, $1.2 million and $3.9 million, respectively, were recognized in earnings. Cumulativeas share-based compensation cost for vested liability PSU awards equals the actual payout value upon vesting.related to PSUs. For the three- and nine-month periods ended September 30, 2018, $6.3 million and $11.5 million, respectively, were recognized as share-based compensation related to PSUs. For the three- and nine-month periods ended September 30, 2017, $4.0 million and $5.8 million, respectively, were recognized as share-based compensation related to PSUs. The liability balance for previously unvested PSUs that are accounted for as liability awardsgranted in January 2016 was $18.8 million at September 30, 2018 and $11.1 million at December 31, 2017. We paid $0.9 million2018, which we settled in cash to settle the 2015 PSU awards when theythose PSUs vested in January 2018.2019.
 
Additionally in January2019 and 2018, we granted $5.0fixed-value cash awards of $4.6 million of fixed value cash awardsand $5.2 million, respectively, to select management employees under the 2005 Incentive Plan. The value of thesefixed value cash awards is recognized on a straight-line basis over a vesting period of three years. For the three- and nine-month periods ended September 30, 2019, $0.8 million and $2.4 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2018, $0.5 million and$1.3 $1.3 million, respectively, waswere recognized as compensation cost.
 

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Employee Stock Purchase Plan 
 
We have an employee stock purchase plan (the “ESPP”). TheOn May 15, 2019, our shareholders approved an amendment to and restatement of the ESPP has 1.5 millionto: (i) increase the shares authorized for issuance by 1.5 million shares and (ii) delegate to an internal administrator the authority to establish the maximum shares purchasable during a purchase period. As of which 0.5September 30, 2019, 2.0 million shares were available for issuance as of September 30, 2018.under the ESPP. The ESPP currently has a purchase limit of 130260 shares per employee per purchase period.
 
For more information regarding our employee benefit plans, including our long-term incentive stock-basedthe 2005 Incentive Plan and cash plans and our employee stock purchase plan,the ESPP, see Note 1112 to our 20172018 Form 10-K.

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Note 12 — Business Segment Information
 
We have three3 reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Intervention segment alsoEnhancer, and the chartered Siem Helix 1 and Siem Helix 2 vessels. Our well intervention equipment includes IRSs and SILs, some of which we provide on a stand-alone basis, and SILs. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer and the chartered Siem Helix 1 and Siem Helix 2 vessels.basis. Our Robotics segment includes ROVs, trenchers and ROVDrills,a ROVDrill, which are designed to complement offshore construction and well intervention services, and three ROV3 robotics support vessels under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III., and spot vessels, including the Ross Candies, which is under a flexible charter agreement. Our Production Facilities segment includes the HP I, the HFRS, and our investmentownership interest in Independence Hub (Note 4) and our ownership of certain oil and gas properties that is accounted for under the equity method.we acquired from Marathon Oil in January 2019 (Note 13). All material intercompany transactions between the segments have been eliminated.
 
We evaluate our performance primarily based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
Net revenues —       
Well Intervention$170,206
 $154,441
 $451,511
 $445,769
Robotics51,909
 54,340
 136,396
 120,569
Production Facilities13,777
 15,877
 44,651
 48,541
Intercompany eliminations(23,283) (12,083) (51,398) (33,417)
Total$212,609
 $212,575
 $581,160
 $581,462
        
Income (loss) from operations —       
Well Intervention$37,689
 $34,427
 $74,002
 $82,774
Robotics8,876
 5,601
 7,921
 (12,818)
Production Facilities3,050
 6,694
 11,907
 20,919
Segment operating income49,615
 46,722
 93,830
 90,875
Corporate, eliminations and other(10,617) (15,345) (31,491) (35,842)
Total$38,998
 $31,377
 $62,339
 $55,033
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
Net revenues —       
Well Intervention$154,441
 $111,522
 $445,769
 $299,219
Robotics54,340
 47,049
 120,569
 102,078
Production Facilities15,877
 16,380
 48,541
 47,965
Intercompany elimination(12,083) (11,691) (33,417) (31,145)
Total$212,575
 $163,260
 $581,462
 $418,117
        
Income (loss) from operations —       
Well Intervention$34,427
 $16,906
 $82,774
 $37,356
Robotics5,601
 (9,365) (12,818) (37,313)
Production Facilities6,694
 7,660
 20,919
 20,724
Corporate and other(15,567) (10,633) (36,507) (29,296)
Intercompany elimination222
 199
 665
 641
Total$31,377
 $4,767
 $55,033
 $(7,888)

 

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Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties. Intercompany segment revenues are as follows (in thousands):
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2019 2018 2019 2018
        
Well Intervention (1)
$15,318
 $4,379
 $28,355
 $10,546
Robotics7,965
 7,704
 23,043
 22,871
Total$23,283
 $12,083
 $51,398
 $33,417

(1)Amounts in the three- and nine-month periods ended September 30, 2019 included $10.6 million and $15.9 million, respectively, associated with P&A work on the Droshky wells for our Production Facilities segment (Notes 2 and 13). Upon completion of the P&A work Marathon Oil is contractually obligated to remit payment to us.

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 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
        
Well Intervention$4,379
 $3,765
 $10,546
 $8,033
Robotics7,704
 7,926
 22,871
 23,112
Total$12,083
 $11,691
 $33,417
 $31,145

 
Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business segments, most notably the majority of our cash and cash equivalents. The following table reflects total assets by reportable segment (in thousands):
 September 30,
2019		 December 31,
2018
    
Well Intervention$2,133,205
 $1,916,638
Robotics183,125
 147,602
Production Facilities159,225
 120,845
Corporate and other137,956
 162,645
Total$2,613,511
 $2,347,730
 September 30,
2018		 December 31,
2017
    
Well Intervention$1,912,197
 $1,830,733
Robotics161,079
 179,853
Production Facilities123,160
 138,292
Corporate and other182,039
 213,959
Total$2,378,475
 $2,362,837

Note 13 — Asset Retirement Obligations
Our asset retirement obligations (“AROs”) consist of estimated costs for subsea infrastructure P&A activities. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations.
The following table describes the changes in our AROs (both current and long-term) (in thousands):
AROs at January 1, 2019$—
Liability incurred during the period (1)
53,294
Liability settled during the period(15,944)
Accretion expense1,770
AROs at September 30, 2019$39,120
(1)In connection with the acquisition on January 18, 2019 of certain assets related to the Droshky Prospect (Note 2), we assumed the AROs for the required P&A of those assets in exchange for agreed-upon amounts to be paid by Marathon Oil as the P&A work is completed. We initially recognized $53.3 million of ARO liability, $50.8 million of receivables and $2.5 million of acquired property for this transaction.
Note 14 — Commitments and Contingencies and Other Matters
 
Commitments
 
We have long-term charter agreements with Siem Offshore AS (“Siem”) for the Siem Helix 1 and Siem Helix 2 vessels used in connection with our contracts with PetrobrasPetróleo Brasileiro S.A. (“Petrobras”) to perform well intervention work offshore Brazil. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates with options to extend. We have long-term charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The charter agreements expire in October 2019 for the Grand Canyon, in April 2021 for the Grand Canyon II and in May 2023 for the Grand Canyon III.
 

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In September 2013, we executedentered into a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract, in 2013, 20% was paid in each of 2016, 20% was paid in December 2017 and 2018, and the remaining 20% is to be paid on December31, 2018, and 20% is to be paiddue upon the delivery of the vessel, which at our option can be deferred until December31, 2019.vessel. We are also contractually committed to reimbursehave informed the shipyard for its costs in connection with the defermentof our intent to take delivery of the Q7000’s delivery beyond 2017.vessel in November 2019. At September 30, 2018,2019, our total investment in the Q7000 was $323.5$446.4 million, including $207.6$276.8 million of installment payments to the shipyard. Currently, equipmentThe vessel is being manufactured and installedcurrently in the final preparation phase for the completion of the vessel.work expected to commence in early 2020.
 
Contingencies and Claims
 
We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations orand cash flows.
 
Litigation
 
We are involved in various other legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence.Act. In addition, from time to time we incurreceive other claims, such as contract and employment-related disputes, in the normal course of business.

Note 15 — 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):
25
 Nine Months Ended
September 30,
 2019 2018
    
Interest paid, net of interest capitalized$2,404
 $6,620
Income taxes paid7,535
 4,699


Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $14.0 million at September 30, 2019 and $9.9 million at December 31, 2018.
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Note 1416 — Fair Value Measurements
 
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows: 
 
Level 1 — Observable inputs such as quoted prices in active markets;
Level 2 — Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
Level 3 — Unobservable inputs 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 approaches 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).

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Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and derivative instruments. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. The fair value of our derivative instruments (Note 15) and of our note receivable that is accounted for as an investment in available-for-sale debt securities (Note 3)17) 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, volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. The following tables provide additional information relating to those financial instruments measured at fair value on a recurring basis (in thousands):
Fair Value Measurements at
September 30, 2018 Using		   Fair Value at September 30, 2019 
Level 1 Level 2 Level 3 Total 
Valuation
Approach
Level 1 Level 2 Level 3 Total 
Valuation
Approach
Assets:                
Interest rate swaps$—
 $1,535
 $—
 $1,535
 (c)$—
 $108
 $—
 $108
 (c)
                
Liabilities:                
Foreign exchange contracts—
 10,982
 —
 10,982
 (c)
Foreign exchange contracts — hedging instruments—
 1,089
 —
 1,089
 (c)
Foreign exchange contracts — non-hedging instruments—
 1,634
 —
 1,634
 (c)
Total net liability$—
 $9,447
 $—
 $9,447
 $—
 $2,615
 $—
 $2,615
 
 

 Fair Value at December 31, 2018  
 Level 1 Level 2 Level 3 Total 
Valuation
Approach
Assets:         
Interest rate swaps$—
 $1,064
 $—
 $1,064
 (c)
          
Liabilities:         
Foreign exchange contracts — hedging instruments—
 6,211
 —
 6,211
 (c)
Foreign exchange contracts — non-hedging instruments—
 3,984
 —
 3,984
 (c)
Total net liability$—
 $9,131
 $—
 $9,131
  


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 Fair Value Measurements at
December 31, 2017 Using		    
 Level 1 Level 2 Level 3 Total 
Valuation
Approach
Assets:         
Note receivable$—
 $3,758
 $—
 $3,758
  
Interest rate swaps—
 966
 —
 966
 (c)
          
Liabilities:         
Foreign exchange contracts—
 12,467
 —
 12,467
 (c)
Total net liability$—
 $7,743
 $—
 $7,743
  

 
The principal amount and estimated fair value of our long-term debt are as follows (in thousands):
 September 30, 2019 December 31, 2018
 
Principal
Amount (1)
 
Fair
Value (2) (3)
 
Principal
Amount (1)
 
Fair
Value (2) (3)
        
Term Loan (previously scheduled to mature June 2020)$—
 $—
 $33,693
 $33,314
Term Loan (matures December 2021)34,125
 33,698
 —
 —
Nordea Q5000 Loan (matures April 2020)98,214
 98,214
 125,000
 122,500
MARAD Debt (matures February 2027)63,610
 68,972
 70,468
 74,406
2022 Notes (mature May 2022)125,000
 126,094
 125,000
 114,298
2023 Notes (mature September 2023)125,000
 146,719
 125,000
 114,688
Total debt$445,949
 $473,697
 $479,161
 $459,206
 September 30, 2018 December 31, 2017
 
Principal Amount (1)
 
Fair
Value (2) (3)
 
Principal Amount (1)
 
Fair
Value (2) (3)
        
Term Loan (matures June 2020)$34,629
 $34,802
 $97,500
 $98,231
Nordea Q5000 Loan (matures April 2020)133,928
 133,510
 160,714
 160,111
MARAD Debt (matures February 2027)70,468
 74,108
 77,000
 82,058
2022 Notes (mature May 2022)125,000
 133,281
 125,000
 124,219
2023 Notes (mature September 2023)125,000
 162,031
 —
 —
2032 Notes (redeemed May 2018)—
 —
 60,115
 60,040
Total debt$489,025
 $537,732
 $520,329
 $524,659

(1)Principal amount includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 6 for additional disclosures on our long-term debt.
(2)The estimated fair value of the 2022 Notes the 2023 Notes and the 20322023 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the Term Loan,term loans, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third partythird-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.
(3)The principal amount and estimated fair value of the convertible notes2022 Notes and the 2023 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.
Note 1517 — Derivative Instruments and Hedging Activities
 
Our business is exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedgemitigate the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative instruments are reflected in the accompanying condensed consolidated balance sheets at fair value.
 
We engage solely in cash flow hedges. Hedges of cashCash flow exposurehedges are entered into to hedge a forecasted transaction or the variability of cash flows related to a forecasted transaction or to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are reported in Accumulated OCI to the extent that the hedges are effective.OCI. These changes are subsequently reclassified into earnings when the hedged transactions settle. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately inaffect earnings. In addition, any changeChanges in the fair value of a derivative instrument that does not qualify for hedge accounting isare recorded in earnings in the period in which the change occurs.
 

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For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 1718 to our 20172018 Form 10-K.
 
Interest Rate Risk
 
From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into various interest rate swap contracts to fix the interest rate on $187.5 million of ourthe Nordea Q5000 Loan borrowings (Note 6). These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. Our interest rate swap contracts qualify for cash flow hedge accounting treatment. Changes in the fair value of interest rate swaps are reported in Accumulatedaccumulated OCI to the extent the swaps are effective.(net of tax). These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense. The ineffective portion

28

Table of the interest rate swaps, if any, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.Contents

Foreign Currency Exchange Rate Risk
 
Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. We enter into foreign currency exchange contracts from time to time to stabilize expected cash outflows related to our vessel charters that are denominated in foreign currencies.
 
In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand Canyon II and Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. Unrealized losses associated with the effective portion of our foreign currency exchange contracts that qualify for hedge accounting treatment are included in our Accumulatedaccumulated OCI (net of tax). Changes in unrealized losses associated with the foreign currency exchange contracts that are not designated as cash flow hedges are reflected in “Other income (expense),expense, net” in the accompanying condensed consolidated statements of operations. Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations. There were no gains or losses associated with hedge ineffectiveness for the three- and nine-month periods ended September 30, 2018 and 2017.
 
Quantitative Disclosures Relating to Derivative Instruments 
 
The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands):
 September 30, 2019 December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivative Instruments:       
Interest rate swapsOther current assets $108
 Other current assets $863
Interest rate swapsOther assets, net —
 Other assets, net 201
   $108
   $1,064
        
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $1,089
 Accrued liabilities $5,857
Foreign exchange contractsOther non-current liabilities —
 Other non-current liabilities 354
   $1,089
   $6,211
 September 30, 2018 December 31, 2017
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivative Instruments:       
Interest rate swapsOther current assets $972
 Other current assets $311
Interest rate swapsOther assets, net 563
 Other assets, net 655
   $1,535
   $966
        
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $6,235
 Accrued liabilities $7,492
Foreign exchange contractsOther non-current liabilities 729
 Other non-current liabilities 4,975
   $6,964
   $12,467

 

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The following table presents the balance sheet location and fair value of our derivative instruments that were not designated as hedging instruments (in thousands):
 September 30, 2019 December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $1,634
 Accrued liabilities $3,454
Foreign exchange contractsOther non-current liabilities —
 Other non-current liabilities 530
   $1,634
   $3,984


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 September 30, 2018 December 31, 2017
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $2,925
 Accrued liabilities $3,133
Foreign exchange contractsOther non-current liabilities 1,093
 Other non-current liabilities 3,175
   $4,018
   $6,308

The following tables present the impact that derivative instruments designated as hedging instruments had on our Accumulatedaccumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of September 30, 2018, $4.22019, $0.8 million of net losses in Accumulatedaccumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.
  Unrealized Gain (Loss) Recognized in OCI
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2019 2018 2019 2018
         
Foreign exchange contracts $(280) $(164) $(338) $(35)
Interest rate swaps 6
 76
 (363) 874
  $(274) $(88) $(701) $839
 
Unrealized Gain (Loss) Recognized in OCI
(Effective Portion)
 Three Months Ended
September 30,		 Nine Months Ended
September 30,
 2018 2017 2018 2017
        
Foreign exchange contracts$(164) $2,282
 $(35) $4,091
Interest rate swaps76
 15
 874
 50
 $(88) $2,297
 $839
 $4,141

 
 
Location of Gain (Loss) Reclassified from
Accumulated OCI into Earnings
 
Gain (Loss) Reclassified from
Accumulated OCI into Earnings
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2019 2018 2019 2018
          
Foreign exchange contractsCost of sales $(1,197) $(1,957) $(5,460) $(5,538)
Interest rate swapsNet interest expense 151
 158
 593
 305
   $(1,046) $(1,799) $(4,867) $(5,233)
 
Location of
Gain (Loss) Reclassified from
Accumulated OCI into Earnings
 
Gain (Loss) Reclassified from
Accumulated OCI into Earnings
(Effective Portion)
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2018 2017 2018 2017
          
Foreign exchange contractsCost of sales $(1,957) $(3,288) $(5,538) $(10,280)
Interest rate swapsNet interest expense 158
 (95) 305
 (542)
   $(1,799) $(3,383) $(5,233) $(10,822)

 
The following table presents the impact that derivative instruments not designated as hedging instruments had on our condensed consolidated statements of operations (in thousands):
 
Location of Loss
Recognized in Earnings
 Loss Recognized in Earnings
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2019 2018 2019 2018
          
Foreign exchange contractsOther expense, net $(371) $(83) $(413) $(26)
   $(371) $(83) $(413) $(26)

 
Location of Gain (Loss)
Recognized in Earnings
 Gain (Loss) Recognized in Earnings
  Three Months Ended
September 30,		 Nine Months Ended
September 30,
  2018 2017 2018 2017
          
Foreign exchange contractsOther income (expense), net $(83) $1,050
 $(26) $1,531
   $(83) $1,050
 $(26) $1,531


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Item 2.  Management’s Discussion and Analysis of Financial Condition andResults of Operations
FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS
 
This Quarterly Report on Form 10-Q contains or incorporates by reference various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning future events. This forward-looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act.Act of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated herein by reference that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking statements.statements although not all forward-looking statements contain such identifying words. Included in forward-looking statements are, among other things: 
 
statements regarding our business strategy orand any other business plans, forecasts or objectives, any or all of which are subject to change;
statements regarding projections of revenues, gross margins, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;
statements regarding our backlog and long-termcommercial contracts and rates thereunder;
statements regarding our ability to enter into and/or perform commercial contracts, including the scope, timing and outcome of those contracts;
statements regarding the acquisition, construction, upgrades or maintenance of vessels or equipment and any anticipated costs or downtime related thereto, including the construction of our Q7000 vessel;
•
statements regarding the acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto, including the construction, completion and mobilization of the Q7000;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;transactions or arrangements;
statements regarding anticipatedpotential legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
statements regarding our trade receivables and their collectability;
statements regarding anticipatedpotential developments, industry trends, performance or industry ranking;
statements regarding general economic or political conditions, whether international, national or in the regional andor local markets in which we do business;
statements regarding our ability to retain our senior management and other key employees;
statements regarding the underlying assumptions related to any projection or forward-looking statement; and
any other statements that relate to non-historical or future information.
 
Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to bediffer materially different from those in the forward-looking statements. These factors include: 
 
the impact of domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;
the impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;
the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;
the ability to effectively bid and perform our contracts;contracts, including the impact of equipment problems or failure;
the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets;
unexpected future capital expenditures, including the amount and nature thereof;
the effectiveness and timing of completion of our vessel and/or system upgrades and major maintenance items;
unexpected delays in the delivery, or chartering or customer acceptance, and terms of acceptance, of new assets for our well intervention and robotics fleet;assets;
the effects of our indebtedness and our ability to reduce capital commitments;
the results of our continuing efforts to control costs and improve performance;
the success of our risk management activities;

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the effects of competition;
the availability of capital (including any financing) to fund our business strategy and/or operations;
the impact of current and future laws and governmental regulations, including tax and accounting developments, such as the 2017 Tax Act;

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the impact of the vote in the U.K. to potentially exit the European Union, (the “EU”), known as Brexit, on our business, operations and financial condition, which is unknown at this time;
the effect of adverse weather conditions and/or other risks associated with marine operations;
the impact of foreign currency exchange controls and exchange rate fluctuations;
the effectiveness of our current and future hedging activities;
the potential impact of a loss of one or more key employees; and
the impact of general, market, industry or business conditions.
 
Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described inunder Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 20172018 Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.
EXECUTIVE SUMMARY
 
Business Strategy
 
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We believe that focusing on these services willshould deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities and/or the regions in which we operate, or add capacity to existing services in our key operating regions. We expect our well intervention fleet to expand with the completion and delivery in 2019 of the Q7000, a newbuild semi-submersible vessel, in 2019.vessel. Chartering newer vessels with additional capabilities, such as the three Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit from our fixed fee agreement for the HP I, a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator, until at least June 1, 2023. With the acquisition of certain oil and gas properties from Marathon Oil in January 2019, we expect improved utilization of our well intervention fleet in the Gulf of Mexico as we perform the P&A of the acquired assets as our schedule permits, subject to regulatory timelines.
 
In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the parties’ strategic allianceparties to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance is expected to leverageleverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. In April 2015, weWe and OneSubsea agreed to jointly develop and ordereddeveloped a 15,000 working p.s.i. intervention riser system (“15K IRS”) for, each owning a total cost of approximately $28 million (approximately $14 million for our 50% interest), whichinterest. The 15K IRS was completed and placed into service in January 2018. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our, each owning a 50% interest). At September 30, 2018, our total investment ininterest. Final acceptance testing on the ROAM was $5.6 million. The ROAMhas been completed and the system is currently expected to be available to customers in 2019.2020.
 
Economic Outlook and Industry Influences
 
Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities as well asand capital projects. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including: 
 
worldwide economic activity and general economic and business conditions, including available access to global capital and capital markets;
the global supply and demand for oil and natural gas, especially in the United States, Europe, Chinagas;

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political and India;
economic uncertainty and geopolitical unrest, including regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;
actions taken by the Organization of Petroleum Exporting Countries;
the availability and discovery rate of new oil and natural gas reserves in offshore areas;
the exploration and production of onshore shale oil and natural gas;
the cost of offshore exploration for and production and transportation of oil and natural gas;
the level of excess production capacity;

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the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;
the sale and expiration dates of offshore leases in the United StatesU.S. and overseas;
technological advances affecting energy exploration, production, transportation and consumption;
potential acceleration of the development of alternative fuels;
shifts in end-customer preferences toward fuel efficiency and the use of natural gas;
weather conditions and natural disasters;
environmental and other governmental regulations; and
domestic and international tax laws, regulations and policies.
 
OilWest Texas Intermediate oil prices have risen to around $70been volatile, fluctuating between $50 and $60 per barrel throughout most of the first nine months of 2019. Volatility in oil prices and imbalance in the past few months. Ansupply and demand for oil create uncertainty in oil and gas exploration and production activities. For instance, an increase in oil and gas exploration and production activities (shale oil production in particular) is expected aswhen major oil producing countries including the U.S. increase output as a result of rising oil prices. Increased supply without adequate levels of increase in demand, however, may constrainweaken oil prices and weaken industry prospects. The resulting weak industry environment may continue to curtaildiscourage oil and gas companies from making longer-term investments in offshore exploration and production as well as other offshore operational activities. Increased competition for limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects us, as drilling rigs historically have been the asset class used for offshore well intervention work. This rig overhang combined with lower volumes of work maycontinues to affect the utilization and/or rates we can achieve for our assets. The current volatileVolatile and uncertain macroeconomic conditions in some regions and countries around the world, such as West Africa, Brazil, China and the U.K. following Brexit, may have a direct and/or indirect impact on our existing contracts and contracting opportunities and may introduce further currency volatility into our operations and/or financial results. In addition, the longer term effects of the 2017 Tax Act on capital spending by oil and gas companies are still uncertain.
 
Many oil and gas companies are increasingly focusing on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that whenas oil and gas companies begin to increase overall spending levels, it likely will likely be forweighted towards production enhancement activities rather than for exploration projects. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide abandonmentP&A services at the end of the life of a field as required by governmental regulations. Thus, we believe that fundamentals for our business remain favorable over the longer term as the need for prolongation ofto prolong well life in oil and gas production is thea primary driver of demand for our services.
 
Our current strategy is to be positioned for future market recovery while coping withmanaging through a sustained period of weak activity. This strategy is based on the following factors:multiple factors, including: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as plug and abandonmentP&A costs are considered; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling as well as extending and enhancing the commercial life of subsea wells; and (3) in past cycles, well intervention and workover have been some of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.
Helix Fast Response System
We developedcould see the HFRS in 2011 as a culminationbeginnings of our experience as a responderan upturn in the 2010 Macondo well control and containment efforts. The HFRS centers on two ofdemand for our vessels, the HP I and the Q4000, both of which played a key role in the Macondo well control and containment efforts and are currently operatingservices in the Gulf of Mexico. PursuantMexico, which are primarily driven by three factors: (1) long-term rig contracts are not being renewed thus removing some of the rig overhang that was considered by our customers to an agreementbe a sunk cost; (2) previously deferred work on aging wells is less likely to be further deferred as well performance declines; and (3) North America customer spending shifts from unconventional onshore oil and gas to conventional offshore development and enhancement as returns from onshore investment opportunities diminish.

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Business Activity Summary
On January 16, 2019, we renewed the agreements that provide various operators with certain industry participants, in exchange for a retainer fee,access to the HFRS provides these participants with a response resource that can be named in permit applications to federal and state agencies. The HFRS agreements with individual participants also specify the day rates to be charged should the HFRS be deployed in connection with afor well control incident. The term of these agreements is currentlypurposes through March 31, 2019.2020 on newly agreed-upon rates and terms. These agreements automatically renew on an annual basis absent proper notice of termination.

32On January 18, 2019, we acquired from Marathon Oil several wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244. As part of the transaction, Marathon Oil will pay us agreed-upon amounts for the required P&A of the acquired assets, which we can perform as our schedule permits, subject to regulatory timelines. There is limited production associated with two wells that were acquired as part of the transaction.

On May 29, 2019, we acquired a 70% controlling interest in STL, an Aberdeen-based subsea engineering company that specializes in the design and manufacture of subsea pressure control equipment, including well intervention, well control and subsea control systems.
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RESULTS OF OPERATIONS
 
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our consolidated results of operations.
 
We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We operateprovide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. In addition to servicingserving the oil and gas market, our Robotics operationsassets are contracted for the development of renewable energy projects (wind farms). As of September 30, 2018,2019, our consolidated backlog that is supported by written agreements or contracts totaled $1.2 billion,$834 million, of which $121$115 million is expected to be performed over the remainder of 2018.2019. The substantial majority of our backlog is associated with our Well Intervention business segment. As of September 30, 2018,2019, our well intervention backlog was $0.9 billion,$627 million, including $89$92 million expected to be performed over the remainder of 2018.2019. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petróleo Brasileiro S.A. (“Petrobras”)Petrobras to provide well intervention services offshore Brazil with the Siem Helix1 and Siem Helix2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 89%86% of our total backlog as of September 30, 2018. Our contracts are in certain cases cancelable without penalty. In addition, if there are cancellation fees, the amount of those fees can be substantially less than the rates we would have generated had we performed the contract.2019. Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be added;added or subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than the rates we would have generated had we performed the contract.
 
Non-GAAP Financial Measures
 
A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.
 
We measure our operating performance based on EBITDA and free cash flow. EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA and free cash flow to monitor and facilitate the internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA and free cash flow provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand our operating performance and compare our results to other companies that have different financing, capital and tax structures.
 

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We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets.assets, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments and other than temporary loss on note receivable, which are excluded from EBITDA as a component of net other income or expense. We define free cash flow as cash flowflows from operating activities less capital expenditures, net of proceeds from sale of assets. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted.
 

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Other companies may calculate their measures of EBITDA, Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with GAAP. The reconciliation of our net income (loss) to EBITDA and Adjusted EBITDA is as follows (in thousands): 
Three Months Ended
September 30,		 Nine Months Ended
September 30,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2018 2017 2018 20172019 2018 2019 2018
              
Net income (loss)$27,121
 $2,290
 $42,345
 $(20,528)
Net income$31,622
 $27,121
 $49,763
 $42,345
Adjustments:              
Income tax provision (benefit)841
 (1,539) 1,226
 (1,117)
Income tax provision3,539
 841
 6,739
 1,226
Net interest expense3,249
 3,615
 10,744
 15,480
1,901
 3,249
 6,204
 10,744
Loss on extinguishment of long-term debt2
 —
 1,183
 397
—
 2
 18
 1,183
Other expense, net709
 551
 3,225
 619
2,285
 709
 2,430
 3,225
Depreciation and amortization27,680
 26,293
 83,339
 82,670
27,908
 27,680
 84,420
 83,339
EBITDA59,602
 31,210
 142,062
 77,521
67,255
 59,602
 149,574
 142,062
Adjustments:              
(Gain) loss on disposition of assets, net(146) —
 (146) 39
Gain on disposition of assets, net—
 (146) —
 (146)
Realized losses from foreign exchange contracts not designated as hedging instruments(820) (758) (2,316) (2,759)(982) (820) (2,763) (2,316)
Other than temporary loss on note receivable—
 —
 (1,129) —
—
 —
 —
 (1,129)
Adjusted EBITDA$58,636
 $30,452
 $138,471
 $74,801
$66,273
 $58,636
 $146,811
 $138,471
 
The reconciliation of our cash flowflows from operating activities to free cash flow is as follows (in thousands): 
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2018 20172019 2018
      
Cash flows from operating activities$150,827
 $31,323
$89,877
 $150,827
Less: Capital expenditures, net of proceeds from sale of assets(55,406) (121,428)(43,086) (55,406)
Free cash flow$95,421
 $(90,105)$46,791
 $95,421




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Comparison of Three Months Ended September 30, 20182019 and 20172018 
 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
Three Months Ended
September 30,		 
Increase/
(Decrease)
Three Months Ended
September 30,		 
Increase/
(Decrease)
2018 2017 2019 2018 Amount Percent
Net revenues —            
Well Intervention$154,441
 $111,522
 $42,919
$170,206
 $154,441
 $15,765
 10 %
Robotics54,340
 47,049
 7,291
51,909
 54,340
 (2,431) (4)%
Production Facilities15,877
 16,380
 (503)13,777
 15,877
 (2,100) (13)%
Intercompany elimination(12,083) (11,691) (392)
Intercompany eliminations(23,283) (12,083) (11,200)  
$212,575
 $163,260
 $49,315
$212,609
 $212,575
 $34
 — %
            
Gross profit (loss) —            
Well Intervention$37,833
 $20,642
 $17,191
$41,014
 $37,833
 $3,181
 8 %
Robotics8,089
 (6,991) 15,080
10,998
 8,089
 2,909
 36 %
Production Facilities6,831
 7,780
 (949)3,481
 6,831
 (3,350) (49)%
Corporate and other(982) (489) (493)
Intercompany elimination222
 199
 23
Corporate, eliminations and other(419) (760) 341
  
$51,993
 $21,141
 $30,852
$55,074
 $51,993
 $3,081
 6 %
            
Gross margin —            
Well Intervention24%
 19%
  24%
 24%
    
Robotics15%
 (15)%
  21%
 15%
    
Production Facilities43%
 47%
  25%
 43%
    
Total company24%
 13%
  26%
 24%
    
            
Number of vessels or robotics assets (1) / Utilization (2)
            
Well Intervention vessels6/91%
 5/88%
  6/97%
 6/91%
    
Robotics assets54/42%
 60/46%
  
Robotics assets (3)
51/44%
 54/42%
    
Chartered robotics vessels4/98%
 5/80%
  4/96%
 4/98%
    
(1)Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters, and excluding acquired vessels prior to their in-service dates and vessels disposed of and/or taken out of service prior to their disposition and vessels jointly owned with a third party.service.
(2)Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of available calendar days in the applicable period. The average utilization rates of chartered robotics vessels during the three-month periods ended September 30, 2019 and 2018 included 28 and 2017 include 113 and 51 spot vessel days, respectively, at near full utilization.

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Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties. Intercompany segment revenues are as follows (in thousands): 
 Three Months Ended
September 30,		 
Increase/
(Decrease)
 2018 2017 
      
Well Intervention$4,379
 $3,765
 $614
Robotics7,704
 7,926
 (222)
 $12,083
 $11,691
 $392
Net Revenues.  Our total net revenues increased by 30% for the three-month period ended September 30, 2018 as compared to the same period in 2017 as a result of higher revenues in our Well Intervention and Robotics business segments.
Our Well Intervention revenues increased by 38% for the three-month period ended September 30, 2018 as compared to the same period in 2017 reflecting higher revenues generated from our well intervention operations in all regions. In Brazil, the Siem Helix1 and Siem Helix 2 vessels commenced operations for Petrobras in mid-April 2017 and mid-December 2017, respectively. Both vessels were under contract during the third quarter of 2018 with the Siem Helix1 achieving full utilization and the Siem Helix2 achieving 90% utilization. During the third quarter of 2017, only the Siem Helix1 had commenced operations with 96% utilization. In the Gulf of Mexico, the Q5000 was 100% utilized during the third quarter of 2018 as compared to being 75% utilized during the same period in 2017. These increases were partially offset by reduced utilization of the Q4000 from 86% during the third quarter of 2017 to 59% during the same period in 2018. In the North Sea, the Well Enhancer was fully utilized during the third quarter of 2018 as compared to being 84% utilized during the same period in 2017. The Seawell was 98% utilized during the third quarter of 2018 as compared to being 97% utilized during the same period in 2017.
Robotics revenues increased by 15% for the three-month period ended September 30, 2018 as compared to the same period in 2017. The increase primarily reflects higher trenching revenues, as well as increased utilization of ROV support vessels (from 80% during the third quarter of 2017 to 98% during the same period in 2018).
Our Production Facilities revenues decreased by 3% for the three-month period ended September 30, 2018 as compared to the same period in 2017 primarily reflecting a performance incentive earned by the HP I during the third quarter of 2017.
Gross Profit (Loss).  Our total gross profit increased by 146% for the three-month period ended September 30, 2018 as compared to the same period in 2017 reflecting improvements in our Well Intervention and Robotics business segments.
The gross profit related to our Well Intervention segment increased by 83% for the three-month period ended September 30, 2018 as compared to the same period in 2017 primarily reflecting positive operating results from our well intervention operations in the Gulf of Mexico, North Sea and Brazil during the third quarter of 2018.
Our Robotics segment achieved a gross profit of $8.1 million for the three-month period ended September 30, 2018 as compared to a gross loss of $7.0 million for the same period in 2017 primarily reflecting higher trenching revenues, increased utilization for our ROV support vessels and cost reductions.
The gross profit related to our Production Facilities segment decreased by 12% for the three-month period ended September 30, 2018 as compared to the same period in 2017 primarily reflecting lower revenues and higher repair and maintenance costs in the third quarter of 2018.

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Selling, General and Administrative Expenses.  Our selling, general and administrative expenses increased by $4.4 million for the three-month period ended September 30, 2018 primarily attributable to increased costs associated with our employee share-based compensation awards that are linked to our stock price (Note 11).
Net Interest Expense.  Our net interest expense decreased by $0.4 million for the three-month period ended September 30, 2018 as compared to the same period in 2017. The decrease in net interest expense was largely attributable to a reduction in our overall debt levels.
Income Tax Provision (Benefit).  Income tax provision was $0.8 million for the three-month period ended September 30, 2018 as compared to income tax benefit of $1.5 million for the same period in 2017. The variance primarily reflects increased profitability in the current period. The effective tax rate was 3.0% for the three-month period ended September 30, 2018 as compared to (204.9)% for the same period in 2017. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and the reduction of the U.S. corporate tax rate from 35% to 21% as a result of the 2017 Tax Act (Note 7).
Comparison of Nine Months Ended September 30, 2018 and 2017 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
 Nine Months Ended
September 30,		 
Increase/
(Decrease)
 2018 2017 
Net revenues —     
Well Intervention$445,769
 $299,219
 $146,550
Robotics120,569
 102,078
 18,491
Production Facilities48,541
 47,965
 576
Intercompany elimination(33,417) (31,145) (2,272)
 $581,462
 $418,117
 $163,345
      
Gross profit (loss) —     
Well Intervention$93,554
 $47,757
 $45,797
Robotics(5,294) (29,376) 24,082
Production Facilities21,282
 21,031
 251
Corporate and other(2,334) (1,370) (964)
Intercompany elimination665
 641
 24
 $107,873
 $38,683
 $69,190
      
Gross margin —     
Well Intervention21%
 16%
  
Robotics(4)%
 (29)%
  
Production Facilities44%
 44%
  
Total company19%
 9%
  
      
Number of vessels or robotics assets (1) / Utilization (2)
     
Well Intervention vessels6/84%
 5/79%
  
Robotics assets54/37%
 60/42%
  
Chartered robotics vessels4/76%
 5/61%
  

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(1)(3)Represents the numberConsists of vessels or robotics assets as of the end of the period, including vessels under both short-termROVs, trenchers and long-term charters and excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.
(2)Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period. The average utilization rates of chartered robotics vessels during the nine-month periods ended September 30, 2018 and 2017 include 208 and 71 spot vessel days, respectively, at near full utilization.ROVDrill.
 
Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties. Intercompany segment revenues are as follows (in thousands): 
Nine Months Ended
September 30,		 
Increase/
(Decrease)
Three Months Ended
September 30,		 
Increase/
(Decrease)
2018 2017 2019 2018 
          
Well Intervention$10,546
 $8,033
 $2,513
$15,318
 $4,379
 $10,939
Robotics22,871
 23,112
 (241)7,965
 7,704
 261
$33,417
 $31,145
 $2,272
$23,283
 $12,083
 $11,200

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Net Revenues.  Our total net revenues increased by 39% for the nine-monththree-month period ended September 30, 2019 were consistent with those for the same period in 2018 reflecting a mix of higher revenues from our Well Intervention business segment, lower revenues from our Robotics and Production Facilities business segments, and higher intercompany eliminations.
Our Well Intervention revenues increased by 10% for the three-month period ended September 30, 2019 as compared to the same period in 2017 as a result2018 reflecting increases in revenues in the Gulf of Mexico and Brazil, partially offset by lower revenues in the North Sea. In the Gulf of Mexico, the Q4000 generated higher revenues due to higher utilization and a higher number of integrated service projects. IRS rental revenues were also higher in allthe third quarter of our business segments.
2019. Revenue increases from the Q4000 and IRS rental were partially offset by lower revenues from the Q5000 due to lower utilization. Our Well Intervention revenues increasedin the Gulf of Mexico during the third quarter of 2019 also included $10.6 million associated with P&A work on the Droshky wells for our Production Facilities segment, for which Marathon Oil remitted payment to us in September 2019. The increase in revenues in Brazil was primarily a result of the Siem Helix2 achieving 99% utilization during the third quarter of 2019 as compared to 90% during the same period in 2018. The decrease in revenues in the North Sea was primarily attributable to lower rates and a weaker British pound as compared to the third quarter of 2018.
Robotics revenues decreased by 49%4% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018. The decrease primarily reflecting higher revenuesreflected lower trenching activity and spot vessel utilization, offset in Brazil and the Gulf of Mexico. In Brazil, the Siem Helix1 and Siem Helix 2 vessels commenced operations for Petrobras in mid-April 2017 and mid-December 2017, respectively. The Siem Helix1 and the Siem Helix2 achieved 97% and 92% utilization, respectively, during the first nine months of 2018. In the first nine months of 2017, only the Siem Helix1 had commenced operations with 96% utilization. In the Gulf of Mexico, the Q4000 was 78% utilized during the first nine months of 2018 as compared to being 77% utilized during the same period in 2017. Even though the Q5000 was 86% utilized during the first nine months of 2018 as compared to being 88% utilized during the same period in 2017, the vessel earned higher revenue as a result of achievingpart by higher rates in 2018. The addition of the 15K IRS as well ason our Grand CanyonII chartered vessel and higher ROV utilization of our other IRS rental also contributed to the increased revenues in the first nine months of 2018. In the North Sea, revenue during the first nine months of 2018 was slightly higher than that during the same period in 2017 primarily reflecting rate improvements as well as more diving and high margin coil tubing work despite lower utilization for both vessels in 2018. The Well Enhancer was 76% utilized during the first nine months of 2018 as compared to being 81% utilized during the same period in 2017. The Seawell was 74% utilized during the first nine months of 2018 as compared to being 84% utilized during the same period in 2017.
Robotics revenues increased by 18% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 2017. The increase primarily reflects higher trenching revenues, as well as increased utilization of ROV support vessels (from 61% during the first nine months of 2017 to 76% during the same period in 2018).2018.
 
Our Production Facilities revenues increaseddecreased by 1%13% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 2017,2018 primarily reflecting lower revenues from the HFRS retainer fees during the first nine monthsthird quarter of 2017 as a result of2019, offset in part by production revenues from the Q4000 undergoing regulatory dry dockoil and gas properties that we acquired from Marathon Oil in 2017.January 2019 (Note 2).
 

The increase in intercompany eliminations was primarily the result of $10.6 million in revenue that our Well Intervention business segment earned associated with its completion of P&A work on behalf of our Production Facilities segment.
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Gross Profit (Loss).  Our total gross profit increased by 179%6% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018 reflecting improvements across allhigher gross profit generated by our Well Intervention and Robotics business segments.segments, offset in part by lower gross profit in our Production Facilities business segment.
 
The gross profit related to our Well Intervention segment increased by 96%8% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily reflecting positive operating results from our well intervention operationsas a result of higher revenues in the Gulf of Mexico and Brazil, partially offset in part by lower gross profitrevenues in the North Sea.
 
The gross loss associated withprofit related to our Robotics segment decreasedincreased by 82%36% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily reflecting higher trenching revenues increased utilization forgenerated by our ROV support vesselsGrand CanyonII chartered vessel and cost reductions.lower costs due to the expiration in July 2019 of foreign currency exchange contracts to hedge the vessel’s charter payments (Note 17), offset in part by lower spot vessel activity.
 
The gross profit related to our Production Facilities segment increaseddecreased by 1%49% for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily reflecting revenue increasesdecreases for the HFRS.
 
Selling, General and Administrative Expenses.  Our selling, general and administrative expenses increaseddecreased by $6.5$4.7 million for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 2017.2018. The increasedecrease was primarily attributable to increasedcompensation costs associated with our employee share-based compensation awards that are linked to our stock price (Note 11), partially offset by a $1.2 million charge duringin the firstthird quarter of 2017 associated with the provision for uncertain collection of a portion of our receivables2018 that were related to our Robotics segment.liability PSU awards, which settled in January 2019 (Note 11).
 

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Net Interest Expense.  Our net interest expense decreased by $4.7$1.3 million for the nine-monththree-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily reflecting a decrease in interest expense due to a reduction in our overall debt levels, offset in party by a decrease inhigher capitalized interest. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $11.5$5.1 million for the three-month period ended September 30, 2019 as compared to $3.9 million for the same period in 2018 as a result of the construction and completion of the Q7000.
Other Expense, Net.  Net other expense increased by $1.6 million for the three-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting a $1.3 million increase in foreign currency transaction losses.
Income Tax Provision.  Income tax provision was $3.5 million for the three-month period ended September 30, 2019 as compared to $0.8 million for the same period in 2018. The effective tax rate was 10.1% for the three-month period ended September 30, 2019 as compared to 3.0% for the same period in 2018. The increase was primarily attributable to improvements in profitability in the U.S. year over year (Note 7).
Comparison of Nine Months Ended September 30, 2019 and 2018 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
 Nine Months Ended
September 30,		 
Increase/
(Decrease)
 2019 2018 Amount Percent
Net revenues —       
Well Intervention$451,511
 $445,769
 $5,742
 1 %
Robotics136,396
 120,569
 15,827
 13 %
Production Facilities44,651
 48,541
 (3,890) (8)%
Intercompany eliminations(51,398) (33,417) (17,981)  
 $581,160
 $581,462
 $(302) — %
        
Gross profit (loss) —       
Well Intervention$84,761
 $93,554
 $(8,793) (9)%
Robotics14,546
 (5,294) 19,840
 375 %
Production Facilities13,152
 21,282
 (8,130) (38)%
Corporate, eliminations and other(1,197) (1,669) 472
  
 $111,262
 $107,873
 $3,389
 3 %
        
Gross margin —       
Well Intervention19%
 21%
    
Robotics11%
 (4)%
    
Production Facilities29%
 44%
    
Total company19%
 19%
    
        
Number of vessels or robotics assets (1) / Utilization (2)
       
Well Intervention vessels6/88%
 6/84%
    
Robotics assets (3)
51/42%
 54/37%
    
Chartered robotics vessels4/92%
 4/76%
    

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(1)Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters, and excluding acquired vessels prior to their in-service dates and vessels disposed of and/or taken out of service.
(2)Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of available calendar days in the applicable period. The average utilization rates of chartered robotics vessels during the nine-month periods ended September 30, 2019 and 2018 included 137 and 208 spot vessel days, respectively, at near full utilization.
(3)Consists of ROVs, trenchers and ROVDrill.
Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties. Intercompany segment revenues are as follows (in thousands): 
 Nine Months Ended
September 30,		 
Increase/
(Decrease)
 2019 2018 
      
Well Intervention$28,355
 $10,546
 $17,809
Robotics23,043
 22,871
 172
 $51,398
 $33,417
 $17,981
Net Revenues.  Our total net revenues for the nine-month period ended September 30, 2019 were consistent with those for the same period in 2018 reflecting a mix of higher revenues from our Well Intervention and Robotics business segments, lower revenues from our Production Facilities business segment, and higher intercompany eliminations.
Our Well Intervention revenues increased by 1% for the nine-month period ended September 30, 2019 as compared to the same period in 2018, primarily reflecting higher revenues in the Gulf of Mexico and Brazil, partially offset by lower revenues in the North Sea. The increase in revenues in the Gulf of Mexico was primarily attributable to higher utilization of the Q4000 during the first nine months of 2019 as compared to the same period in 2018. This revenue increase was offset by a reduction in IRS rental revenues during the comparative year-over-year periods. Our Well Intervention revenues in the Gulf of Mexico during the first nine months of 2019 also included $15.9 million associated with P&A work on the Droshky wells for our Production Facilities segment, for which Marathon Oil remitted payment to us in September 2019. The increase in revenues in Brazil was primarily a result of both the Siem Helix1 and the Siem Helix2 improving their utilization during the first nine months of 2019. The decrease in revenues in the North Sea primarily reflected a weaker British pound and lower rates as compared to the same period in 2018.
Robotics revenues increased by 13% for the nine-month period ended September 30, 2019 as compared to the same period in 2018. The increase primarily reflected higher trenching activities that contributed to increased utilization of our chartered vessels (from 76% during the first nine months of 2018 to 92% during the same period in 2019). Our robotics assets also achieved higher utilization in the first nine months of 2019 as compared to the same period in 2018.
Our Production Facilities revenues decreased by 8% for the nine-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting lower revenues from the HFRS during the nine-month period ended September 30, 2019, offset in part by production revenues from the oil and gas properties that we acquired from Marathon Oil in January 2019 (Note 2).
The increase in intercompany eliminations was primarily the result of $15.9 million in revenue that our Well Intervention business segment earned associated with its completion of P&A work on behalf of our Production Facilities segment.

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Gross Profit (Loss).  Our total gross profit increased by 3% for the nine-month period ended September 30, 2019 as compared to the same period in 2018 reflecting improvements in our Robotics business segment, offset in part by lower gross profit in our Well Intervention and Production Facilities business segments.
The gross profit related to our Well Intervention business segment decreased by 9% for the nine-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting lower IRS rental unit utilization in the Gulf of Mexico as well as reduced operating results in the North Sea, offset in part by improved operating results in Brazil.
Our Robotics segment achieved a gross profit of $14.5 million for the nine-month period ended September 30, 20182019 as compared to $12.6a gross loss of $5.3 million for the same period in 20172018 primarily reflecting higher trenching revenues, with increased utilization for our chartered vessels and our robotics assets, and a reduction in vessel charter costs.
The gross profit related to our Production Facilities segment decreased by 38% for the nine-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting revenue decreases for the HFRS.
Selling, General and Administrative Expenses.  Our selling, general and administrative expenses decreased by $4.1 million for the nine-month period ended September 30, 2019 as compared to the same period in 2018. The decrease was primarily attributable to compensation costs in the first nine months of 2018 that were related to liability PSU awards, which settled in January 2019 (Note 11).
Net Interest Expense.  Our net interest expense decreased by $4.5 million for the nine-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting higher capitalized interest and a decrease in interest expense due to a reduction in our overall debt levels. Capitalized interest totaled $15.3 million for the nine-month period ended September 30, 2019 as compared to $11.5 million for the same period in 2018 as a result of the construction and completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.Q7000.
 
Loss on Extinguishment of Long-Term Debt.  The $1.2 million loss for the nine-month period ended September 30, 2018 was attributable to the write-off of the unamortized debt issuance costs related to the prepayment of $61 million of the Term Loanthen-existing term loan in March 2018 and costs associated with our repurchase of $59.3 million in aggregate principal amount of the 2032 Notes (Note 6). The $0.4 million loss for the nine-month period ended September 30, 2017 was associated with the write-off of the unamortized debt issuance costs related to certain lenders exiting from our then outstanding term loan prior to its June 2017 amendment and restatement.
 
Other Expense, Net.  Net other expense increaseddecreased by $2.6$0.8 million for the nine-month period ended September 30, 20182019 as compared to the same period in 2017. Net other expense for the nine-month period ended September 30, 2018 includedprimarily reflecting a $1.1 million other than temporary loss on a note receivable (Note 3). Net other expense forduring the nine-month period ended September 30, 2017 included a $1.5 million gain associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 15).2018.
 
Income Tax Provision (Benefit).Provision.  Income tax provision was $1.2$6.7 million for the nine-month period ended September 30, 2019 as compared to $1.2 million for the same period in 2018. Excluding a $6.3 millionThe effective tax charge in 2017 attributable to a change in tax position related to our foreign taxes, we had an income tax benefit of $7.4 millionrate was 11.9% for the nine-month period ended September 30, 2017. The variance in our income taxes (excluding the 2017 tax charge) primarily reflects increased profitability in the current period. The effective tax rate was 2.8% for the nine-month period ended September 30, 20182019 as compared to 5.2%2.8% for the same period in 2017.2018. The varianceincrease was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions, the reduction ofimprovements in profitability in the U.S. corporate tax rate from 35% to 21% as a result of the 2017 Tax Act, and the tax charge in 2017year over year (Note 7).


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LIQUIDITY AND CAPITAL RESOURCES
 
Overview 
 
The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands): 
September 30,
2018		 December 31,
2017		September 30,
2019		 December 31,
2018
      
Net working capital$330,021
 $186,004
$199,934
 $259,440
Long-term debt (1)
401,265
 385,766
304,932
 393,063
Liquidity (2)
471,817
 348,207
458,971
 426,813
(1)Long-term debt does not include the current maturities portion of our long-term debt as that amount is included in net working capital. Long-term debt is also net of unamortized debt discountdiscounts and debt issuance costs. See Note 6 for information relating to our existinglong-term debt.
(2)Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under ourthe Revolving Credit Facility, which capacity is reduced by letters of credit drawn against that facility. Our liquidity at September 30, 20182019 included cash and cash equivalents of $325.1$286.3 million and $146.7$172.6 million of available borrowing capacity under ourthe Revolving Credit Facility (Note 6). Our liquidity at December 31, 20172018 included cash and cash equivalents of $266.6$279.5 million and $81.6$147.4 million of available borrowing capacity under our Revolving Credit Facility.then-existing revolving credit facility.
 
The carrying amount of our long-term debt, including current maturities, net of unamortized debt discountdiscounts and debt issuance costs, is as follows (in thousands): 
September 30,
2018		 December 31,
2017		September 30,
2019		 December 31,
2018
      
Term Loan (matures June 2020)$34,195
 $95,842
Term Loan (previously scheduled to mature June 2020)$—
 $33,321
Term Loan (matures December 2021)33,687
 —
Nordea Q5000 Loan (matures April 2020)132,717
 158,930
97,768
 123,980
MARAD Debt (matures February 2027)66,321
 72,487
59,951
 66,443
2022 Notes (mature May 2022) (1)
111,330
 108,829
114,848
 112,192
2023 Notes (mature September 2023) (2)
103,486
 —
2032 Notes (redeemed May 2018)—
 59,539
2023 Notes (mature September 2023) (1)
107,146
 104,379
Total debt$448,049
 $495,627
$413,400
 $440,315
(1)The 2022 Notes will increase to their face amount through accretion ofand the debt discount through May 1, 2022.
(2)The 2023 Notes will increase to their face amountamounts through accretion of thetheir debt discountdiscounts through May 1, 2022 and September 15, 2023.2023, respectively.
 
The following table provides summary data from our condensed consolidated statements of cash flows (in thousands): 
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2018 20172019 2018
Cash provided by (used in):      
Operating activities$150,827
 $31,323
$89,877
 $150,827
Investing activities(55,406) (121,428)(47,167) (55,406)
Financing activities(35,974) 88,420
(35,638) (35,974)
 


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Our current requirements for cash primarily reflect the need to fund capital spending for our current lines of business and to service our debt. Historically, we have funded our capital program with cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives. As of September 30, 2019, the remaining principal balance of the Nordea Q5000 Loan was classified to current as its maturity date is April 30, 2020. Although we currently have no plans to do so, we have the ability to fund the repayment of the Nordea Q5000 Loan when due with available borrowing capacity under the Revolving Credit Facility.
 
As a further response to the industry-wide spending reductions, we continue to remain focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, defer or cancel certain planned capital expenditures. We believe that our cash on hand, internally generated cash flows and available borrowing capacityavailability under ourthe Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.
 
In accordance with ourthe Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of a minimum cash balance, net worth, working capital and debt-to-equity requirements. OurThe Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by us. The Credit Agreement does permit us to incur certain unsecured indebtedness and also provides for our subsidiaries to incur project financing indebtedness (such as ourthe MARAD Debt and ourthe Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. OurThe Credit Agreement also permits our Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as defined in ourthe Credit Agreement). As of September 30, 20182019 and December 31, 2017,2018, we were in compliance with all of the covenants in our long-term debt agreements.
 
A prolonged period of weak industry activity may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to fully access ourthe Revolving Credit Facility may be impacted. At September 30, 2018,2019, our available borrowing capacity under ourthe Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $146.7$172.6 million, net of $3.3$2.4 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrow under ourthe Revolving Credit Facility other than for the issuance of letters of credit. Our ability to comply with loan agreement covenants and other restrictions is affected by economic conditions and other events beyond our control. Our failure to comply with these covenants and other restrictions could lead to an event of default, the possible acceleration of our outstanding debt and/orand the exercise of certain remedies by our lenders, including foreclosure against our collateral.
 
Subject to the terms and restrictions of the Credit Agreement, we may borrow and/or obtain letters of credit of up to $25 million under ourthe Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding ourthe Credit Agreement includingand related covenants and collateral.
 
The 2022 Notes and the 2023 Notes can be converted into our common stock by the holders or redeemed by us prior to their stated maturity under certain circumstances specified in the applicable indenture governing the notes. We can settle any conversion in cash, shares of our common stock or a combination thereof.
 
We repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018 and redeemed the remaining $0.8 million outstanding on May 4, 2018.
 
Operating Cash Flows 
 
Total cash flows from operating activities increaseddecreased by $119.5$61.0 million for the nine-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily reflecting improvementsthe timing of cash receipts from our customers and other increases in our operations and collectionnet working capital during the first nine months of accounts receivable2019 as well as reductions in interest payments.higher regulatory certification costs for our vessels and systems, which included costs related to planned dry docks for three of our vessels.
 


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Investing Activities 
 
Capital expenditures represent cash paid principally for the acquisition, construction, completion, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Capital expenditures also include interest on property and equipment under development. Significant sources (uses) of cash associated with investing activities are as follows (in thousands): 
Nine Months Ended
September 30,		Nine Months Ended
September 30,
2018 20172019 2018
Capital expenditures:      
Well Intervention$(54,845) $(130,649)$(44,323) $(54,845)
Robotics(89) (691)(388) (89)
Production Facilities(113) —
(123) (113)
Other(384) (88)(802) (384)
Proceeds from sale of assets (1)
25
 10,000
STL acquisition, net(4,081) —
Proceeds from sale of assets2,550
 25
Net cash used in investing activities$(55,406) $(121,428)$(47,167) $(55,406)
(1)Reflects cash received from the sale of our former spoolbase facility located in Ingleside, Texas.
 
Our capital expenditures haveabove primarily included payments associated with the construction and completion of our Q7000 vessel and the investment in the topside well intervention equipment for the Siem Helix 1 and Siem Helix 2 vessels that we charter to perform our agreements with PetrobrasQ7000 (see below).
 
In September 2013, we executedentered into a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, including the third amendment that was entered into in November2017, 20% of the contract price was paid upon the signing of the contract, in 2013, 20% was paid in each of 2016, 20% was paid in December 2017 and 2018, and the remaining 20% is to be paid on December31, 2018, and 20% is to be paiddue upon the delivery of the vessel, which at our option can be deferred until December31, 2019.vessel. We are also contractually committed to reimbursehave informed the shipyard for its costs in connection with the defermentof our intent to take delivery of the Q7000’s delivery beyond 2017.vessel in November 2019. At September 30, 2018,2019, our total investment in the Q7000 was $323.5$446.4 million, including $207.6$276.8 million of installment payments to the shipyard. Currently equipment is being manufactured and installed for the completion of the vessel. We plan to incur approximately $82$80 million related to the Q7000 over the remainder of 2018,2019, including a scheduledthe final shipyard payment of $69.2 millionmillion. The vessel is currently in December2018.
In February 2014, we entered into agreements with Petrobrasthe final preparation phase for work expected to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with options to extend by agreement of the parties for a total period of four years. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two monohull vessels, the Siem Helix 1, which commenced operations for Petrobrascommence in mid-April 2017, and the Siem Helix 2, which commenced operations for Petrobras in mid-December 2017.early 2020.
 
Financing Activities 
 
Cash flows from financing activities consist primarily of proceeds from debt and equity transactions and repayments of our long-term debt. TotalNet cash flowsoutflows from financing activities decreased by $124.4of $35.6 million for the nine-month period ended September 30, 2019 primarily reflected the repayment of $68.2 million of our indebtedness and $35.0 million in proceeds from the Term Loan (Note 6). Net cash outflows from financing activities of $36.0 million for the nine-month period ended September 30, 2018 as compared toprimarily reflected the same period in 2017. Cash inflows from financing activities for the nine-month period ended September 30, 2017 includedrepayment of $156.6 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of approximately $220$125 million we received from our underwritten public equity offering in January 2017. This was offset in part by higher debt repayments duringof the first nine months of 2017 as compared to the same period in 2018.2023 Notes (Note 6).
 

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Free Cash Flow
 
Free cash flow increaseddecreased by $185.5$48.6 million for the nine-month period ended September 30, 20182019 as compared to the same period in 20172018 primarily attributable to higherthe decrease in operating cash flows, slightly offset by reduced capital expenditures in the first nine months of 2018 as well as reduced capital expenditures as a result of the completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.2019.
 
Outlook 
 
We anticipate that our capital expenditures, including capitalized interest and deferred dry dockregulatory certification costs for 2018our vessels and systems, will approximate $135 million.$150 million for 2019. We believe that our cash on hand, internally generated cash flows and availability under ourthe Revolving Credit Facility will provide the capital necessary to continue funding our 20182019 capital obligations and to meet our debt obligations due in 2018.2019. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the level of our planned capital expenditures given a prolonged industry downturn.

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Contractual Obligations and Commercial Commitments 
 
The following table summarizes our contractual cash obligations as of September 30, 20182019 and the scheduled years in which the obligations are contractually due (in thousands): 
Total (1)
 
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
Total (1)
 
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
                  
Term Loan$34,629
 $4,212
 $30,417
 $—
 $—
$34,125
 $3,500
 $30,625
 $—
 $—
Nordea Q5000 Loan133,928
 35,714
 98,214
 —
 —
98,214
 98,214
 —
 —
 —
MARAD Debt70,468
 6,858
 14,760
 16,270
 32,580
63,610
 7,200
 15,497
 17,082
 23,831
2022 Notes (2)
125,000
 —
 —
 125,000
 —
125,000
 —
 125,000
 —
 —
2023 Notes (3)
125,000
 —
 —
 125,000
 —
125,000
 —
 —
 125,000
 —
Interest related to debt (4)
74,302
 22,581
 31,414
 17,277
 3,030
55,365
 18,620
 26,941
 8,207
 1,597
Property and equipment (5)
154,869
 85,386
 69,483
 —
 —
80,261
 80,261
 —
 —
 —
Operating leases (6)
510,948
 124,252
 202,578
 171,355
 12,763
405,123
 110,197
 193,669
 94,408
 6,849
Total cash obligations$1,229,144
 $279,003
 $446,866
 $454,902
 $48,373
$986,698
 $317,992
 $391,732
 $244,697
 $32,277
(1)Excludes unsecured letters of credit outstanding at September 30, 20182019 totaling $3.3$2.4 million. These letters of credit may be issued to support various obligations, such as contractual obligations, contract bidding and insurance activities.
(2)Notes mature in May 2022. The 2022 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $18.06 per share, which is 130% of the conversion price. At September 30, 2018,2019, the conversion trigger was not met. See Note 6 for additional information.
(3)Notes mature in September 2023. The 2023 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $12.31 per share, which is 130% of the conversion price. At September 30, 2018,2019, the conversion trigger was not met. See Note 6 for additional information.
(4)Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at September 30, 20182019 for variable rate debt.
(5)
Primarily reflects costs associated with our the Q7000 semi-submersible well intervention vessel, which is currently under constructioncompletion (Note 13)14).
(6)Operating leases include vessel charters and facility and equipment leases. At September 30, 2018,2019, our commitment related to long-term vessel charter commitmentscharters totaled approximately $474.5 million.$366.2 million, of which $147.2 million is related to the non-lease (services) components that are not included in operating lease liabilities on our balance sheet.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES
 
Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. We prepare these financial statements and related footnotes in conformity with accounting principles generally accepted in the United States.GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.
 
Revenue from Contracts with Customers
Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts).
We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations.
The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We do not generally provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. The estimated amount of variable consideration is constrained and is only included in the transaction price to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.
Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the uncertainty is resolved, which typically occurs when the related costs are incurred on behalf of the customer.
Revenue for lump sum contracts is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified.
For additional information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our 20172018 Form 10-K.


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Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
We are currently exposed to market risk in two areas:risks associated with interest rates and foreign currency exchange rates.
 
Interest Rate Risk.  As of September 30, 2018, $168.62019, $132.3 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may continue to rise, thereby increasing our interest expense and related cash outlay. In June 2015, we entered into various interest rate swap contracts to fix the interest rate on a portion of ourthe Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. As of September 30, 2018, $100.42019, the interest rate on $73.6 million of ourthe Nordea Q5000 Loan was hedged. Debt subject to variable rates after considering hedging activities was $68.1$58.7 million. The impact of interest rate risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional $0.7$0.5 million in interest expense for the nine-month period ended September 30, 2018.2019.
 
Foreign Currency Exchange Rate Risk.  Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. As such, our earnings are impacted by movements in foreign currency exchange rates when (i) transactions are denominated in currencies other than the functional currency of the relevant Helix entity, or (ii) the functional currency of our subsidiaries is not the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the United States, we generally pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the nine-month period ended September 30, 2018,2019, we recognized losses of $2.1$2.0 million related to foreign currency transactions in “Other income (expense),expense, net” in our condensed consolidated statement of operations.
 
Our cash flows are subject to fluctuations resulting from changes in foreign currency exchange rates. Fluctuations in exchange rates are likely to impact our results of operations and cash flows. As a result, we entered into various foreign currency exchange contracts to stabilize expected cash outflows related to certain vessel charters denominated in Norwegian kroners. In February 2013, we entered into various foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. A portion of these foreign currency exchange contracts currently qualifies for cash flow hedge accounting treatment. There was no foreign currency hedge ineffectiveness for the nine-month period ended September 30, 2018.
Item 4.Controls and Procedures
 
(a) Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of September 30, 2018.2019. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 20182019 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.
 
(b)Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 20182019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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Part II.  OTHER INFORMATION
Item 1.  Legal Proceedings 
 
See Part I, Item 1, Note 1314 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

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Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds 
 
Issuer Purchases of Equity Securities
Period
(a)
Total number
of shares
purchased
(b)
Average
price paid
per share
(c)
Total number
of shares
purchased as
part of publicly
announced
program
(d)
Maximum
number of shares
that may yet be
purchased under
the program (1)
July 1 to July 31, 2018—
$—
—
3,764,860
August 1 to August 31, 2018—
—
—
3,770,953
September 1 to September 30, 2018—
—
—
3,798,030
—
$—
—
Period 
(a)
Total number
of shares
purchased (1)
 
(b)
Average
price paid
per share
 
(c)
Total number
of shares
purchased as
part of publicly
announced
program
 
(d)
Maximum
number of shares
that may yet be
purchased under
the program (2)
July 1 to July 31, 2019 —
 $—
 —
 4,707,227
August 1 to August 31, 2019 2,255
 7.34
 —
 4,714,378
September 1 to September 30, 2019 —
 —
 —
 4,743,694
  2,255
 $7.34
 —
  
(1)Includes shares forfeited in satisfaction of tax obligations upon vesting of restricted shares.
(2)Under the terms of our stock repurchase program, the issuance of shares to members of our Board and to certain employees, including shares issued under ourthe ESPP to participating employees (Note 11), increases the amountnumber of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 9 to our 20172018 Form 10-K.
Item 6.  Exhibits
 
Exhibit Number Description Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1 
2005 Amended and Restated Articles of Incorporation of Helix.Helix Energy Solutions Group, Inc.
 
Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)
3.2 
Second Amended and Restated By-Laws of Helix.Helix Energy Solutions Group, Inc.
 
Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
31.1 
Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.
 
Filed herewith
31.2 
Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer.
 
Filed herewith
32.1 
Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.
 
Furnished herewith
101.INS XBRL Instance Document. Filed herewithThe instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH XBRL Schema Document. Filed herewith
101.CAL XBRL Calculation Linkbase Document. Filed herewith
101.PRE XBRL Presentation Linkbase Document. Filed herewith
101.DEF XBRL Definition Linkbase Document. Filed herewith
101.LAB XBRL Label Linkbase Document. Filed herewith



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SIGNATURES 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
    
HELIX ENERGY SOLUTIONS GROUP, INC. 
(Registrant)
 
Date:October 24, 201823, 2019 By: /s/ Owen Kratz                                   
    
Owen Kratz
President and Chief Executive Officer 
(Principal Executive Officer)
     
Date:October 24, 201823, 2019 By: /s/ Erik Staffeldt                         
    
Erik Staffeldt
SeniorExecutive Vice President and
Chief Financial Officer 
(Principal Financial Officer)


47