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 March 31,September 30, 2019
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 every Interactive Data File required to be submitted 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 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¨☐
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 April 22,October 18, 2019, 148,792,936148,809,467 shares of common stock were outstanding.
 






TABLE OF CONTENTS
PART I. FINANCIAL INFORMATIONPAGE
    
Item 1. Financial Statements: 
    
  
Condensed Consolidated Balance Sheets –
March 31,September 30, 2019 (Unaudited) and December 31, 2018
3
    
  
Condensed Consolidated Statements of Operations (Unaudited) –
Three and nine months ended March 31,September 30, 2019 and 2018
4
    
  
Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) –
Three and nine months ended March 31,September 30, 2019 and 2018
5
    
  
Condensed Consolidated Statements of Shareholders’ Equity (Unaudited) –
Three months ended March 31,September 30, 2019 and 2018
6
    
  
Condensed Consolidated Statements of Cash FlowsShareholders’ Equity (Unaudited) –
ThreeNine months ended March 31,September 30, 2019 and 2018
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
2931
    
Item 3. 
Quantitative and Qualitative Disclosures About Market Risk
4145
    
Item 4. 
Controls and Procedures
4145
    
PART II. OTHER INFORMATION 
    
Item 1. 
Legal Proceedings
4245
    
Item 2. 
Unregistered Sales of Equity Securities and Use of Proceeds
4246
    
Item 6. 
Exhibits
4246
    
  
Signatures
4347


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PART I.  FINANCIAL INFORMATION
Item 1.Financial Statements
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
March 31,
2019		 December 31,
2018		September 30,
2019		 December 31,
2018
(Unaudited)  (Unaudited)  
ASSETS
Current assets:      
Cash and cash equivalents$220,023
 $279,459
$286,340
 $279,459
Accounts receivable:      
Trade, net of allowance for uncollectible accounts of $0102,072
 67,932
91,707
 67,932
Unbilled and other41,364
 51,943
72,548
 51,943
Other current assets87,184
 51,594
61,751
 51,594
Total current assets450,643
 450,928
512,346
 450,928
Property and equipment2,804,271
 2,785,778
2,819,932
 2,785,778
Less accumulated depreciation(986,202) (959,033)(1,022,138) (959,033)
Property and equipment, net1,818,069
 1,826,745
1,797,794
 1,826,745
Operating lease right-of-use assets240,332
 —
213,048
 —
Other assets, net98,277
 70,057
90,323
 70,057
Total assets$2,607,321
 $2,347,730
$2,613,511
 $2,347,730
      
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:      
Accounts payable$63,849
 $54,813
$79,122
 $54,813
Accrued liabilities81,842
 85,594
71,982
 85,594
Income tax payable—
 3,829
—
 3,829
Current maturities of long-term debt47,888
 47,252
108,468
 47,252
Current operating lease liabilities55,241
 —
52,840
 —
Total current liabilities248,820
 191,488
312,412
 191,488
Long-term debt381,319
 393,063
304,932
 393,063
Operating lease liabilities191,545
 —
164,761
 —
Deferred tax liabilities107,367
 105,862
110,118
 105,862
Other non-current liabilities48,427
 39,538
39,008
 39,538
Total liabilities977,478
 729,951
931,231
 729,951


 

Redeemable noncontrolling interests3,257
 —
Shareholders’ equity:
      
Common stock, no par, 240,000 shares authorized, 148,785 and 148,203 shares issued, respectively1,310,738
 1,308,709
Common stock, no par, 240,000 shares authorized, 148,802 and 148,203 shares issued, respectively1,316,805
 1,308,709
Retained earnings388,912
 383,034
437,418
 383,034
Accumulated other comprehensive loss(69,807) (73,964)(75,200) (73,964)
Total shareholders’ equity
1,629,843
 1,617,779
1,679,023
 1,617,779
Total liabilities and shareholders’ equity
$2,607,321
 $2,347,730
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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2019 20182019 2018 2019 2018
          
Net revenues$166,823
 $164,262
$212,609
 $212,575
 $581,160
 $581,462
Cost of sales150,569
 151,279
157,535
 160,582
 469,898
 473,589
Gross profit16,254
 12,983
55,074
 51,993
 111,262
 107,873
Gain on disposition of assets, net—
 146
 —
 146
Selling, general and administrative expenses(15,985) (14,099)(16,076) (20,762) (48,923) (52,986)
Income (loss) from operations269
 (1,116)
Income from operations38,998
 31,377
 62,339
 55,033
Equity in losses of investment(40) (136)(13) (107) (82) (378)
Net interest expense(2,098) (3,896)(1,901) (3,249) (6,204) (10,744)
Loss on extinguishment of long-term debt—
 (1,105)—
 (2) (18) (1,183)
Other income, net1,166
 925
Other expense, net(2,285) (709) (2,430) (3,225)
Royalty income and other2,345
 2,855
362
 652
 2,897
 4,068
Income (loss) before income taxes1,642
 (2,473)
Income before income taxes35,161
 27,962
 56,502
 43,571
Income tax provision324
 87
3,539
 841
 6,739
 1,226
Net income (loss)$1,318
 $(2,560)
Net income31,622
 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 (loss) per share of common stock:   
Earnings per share of common stock:       
Basic$0.01
 $(0.02)$0.21
 $0.18
 $0.33
 $0.29
Diluted$0.01
 $(0.02)$0.21
 $0.18
 $0.33
 $0.29
          
Weighted average common shares outstanding:          
Basic147,421
 146,653
147,575
 146,700
 147,506
 146,679
Diluted147,751
 146,653
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 COMPREHENSIVE INCOME
(UNAUDITED)
(in thousands)
Three Months Ended
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2019 20182019 2018 2019 2018
          
Net income (loss)$1,318
 $(2,560)
Other comprehensive income, net of tax:   
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(149) 2,153
(274) (88) (701) 839
Reclassifications to net income (loss)1,846
 1,627
Reclassifications to net income1,046
 1,799
 4,867
 5,233
Income taxes on hedges(342) (815)(156) (357) (838) (1,298)
Net change in hedges, net of tax1,355
 2,965
616
 1,354
 3,328
 4,774
Unrealized loss on note receivable arising during the period—
 (629)—
 —
 —
 (629)
Income taxes on note receivable—
 132
—
 —
 —
 132
Unrealized loss on note receivable, net of tax—
 (497)—
 —
 —
 (497)
Foreign currency translation gain2,802
 4,691
Other comprehensive income, net of tax4,157
 7,159
Foreign currency translation loss(4,301) (1,421) (4,564) (4,277)
Other comprehensive loss, net of tax(3,685) (67) (1,236) —
Comprehensive income$5,475
 $4,599
27,937
 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 SHAREHOLDERS’ EQUITY
(UNAUDITED)
(in thousands)
Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
Shares Amount Shares Amount 
                    
Balance, December 31, 2018148,203
 $1,308,709
 $383,034
 $(73,964) $1,617,779
Net income—
 —
 1,318
 —
 1,318
Reclassification of deferred gain from sale and leaseback transaction to retained earnings—
 —
 4,560
 —
 4,560
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—
 —
 —
 2,802
 2,802
—
 —
 —
 (4,301) (4,301) (78)
Unrealized gain on hedges, net of tax—
 —
 —
 1,355
 1,355
—
 —
 —
 616
 616
 —
Accretion of redeemable noncontrolling interests—
 —
 (25) —
 (25) 25
Activity in company stock plans, net and other582
 (659) —
 —
 (659)43
 214
 —
 —
 214
 —
Share-based compensation—
 2,688
 —
 —
 2,688
—
 2,428
 —
 —
 2,428
 —
Balance, March 31, 2019148,785
 $1,310,738
 $388,912
 $(69,807) $1,629,843
Balance, September 30, 2019148,802
 $1,316,805
 $437,418
 $(75,200) $1,679,023
 $3,257
Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Total
Shareholders’
Equity
Common Stock 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss
 
Total
Shareholders’
Equity
 Redeemable Noncontrolling Interests
Shares Amount Shares Amount 
                    
Balance, December 31, 2017147,740
 $1,284,274
 $352,906
 $(69,787) $1,567,393
Net loss—
 —
 (2,560) —
 (2,560)
Reclassification of stranded tax effect to retained earnings—
 —
 1,530
 (1,530) —
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—
 —
 —
 4,691
 4,691
—
 —
 —
 (1,421) (1,421) —
Unrealized gain on hedges, net of tax—
 —
 —
 2,965
 2,965
—
 —
 —
 1,354
 1,354
 —
Unrealized loss on note receivable, net of tax—
 —
 —
 (497) (497)
Equity component of debt discount on convertible senior notes—
 15,424
 —
 —
 15,424
—
 (2) —
 —
 (2) —
Activity in company stock plans, net and other340
 (862) —
 —
 (862)40
 213
 —
 —
 213
 —
Share-based compensation—
 2,463
 —
 —
 2,463
—
 2,509
 —
 —
 2,509
 —
Balance, March 31, 2018148,080
 $1,301,299
 $351,876
 $(64,157) $1,589,018
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)
Three Months Ended
March 31,		Nine Months Ended
September 30,
2019 20182019 2018
Cash flows from operating activities:      
Net income (loss)$1,318
 $(2,560)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:   
Net income$49,763
 $42,345
Adjustments to reconcile net income to net cash provided by operating activities:   
Depreciation and amortization28,509
 27,782
84,420
 83,339
Amortization of debt discounts1,513
 1,360
4,642
 4,238
Amortization of debt issuance costs902
 935
2,752
 2,703
Share-based compensation2,719
 2,500
8,979
 7,569
Deferred income taxes(10) 108
2,347
 (5,716)
Equity in losses of investment40
 136
82
 378
Gain on disposition of assets, net—
 (146)
Loss on extinguishment of long-term debt—
 1,105
18
 1,183
Unrealized gain on derivative contracts, net(829) (1,534)(2,351) (2,289)
Changes in operating assets and liabilities:   
Changes in operating assets and liabilities, net of acquisitions:   
Accounts receivable, net(22,584) 22,761
(45,399) (15,769)
Other current assets(13,129) (3,948)12,215
 (5,662)
Income tax payable(2,370) (2,853)
Income tax payable, net of income tax receivable(3,143) 2,963
Accounts payable and accrued liabilities(17,027) (12,256)(14,765) 6,968
Other, net(13,298) 7,510
(9,683) 28,723
Net cash provided by (used in) operating activities(34,246) 41,046
Net cash provided by operating activities89,877
 150,827
      
Cash flows from investing activities:      
Capital expenditures(11,655) (21,214)(45,636) (55,431)
STL acquisition, net(4,081) —
Proceeds from sale of assets25
 —
2,550
 25
Other(326) —
Net cash used in investing activities(11,956) (21,214)(47,167) (55,406)
      
Cash flows from financing activities:      
Issuance of Convertible Senior Notes due 2023—
 125,000
—
 125,000
Repurchase of Convertible Senior Notes due 2032—
 (59,478)—
 (60,365)
Repayment of Term Loan(936) (61,468)
Proceeds from term loan35,000
 —
Repayment of term loan(34,567) (62,872)
Repayment of Nordea Q5000 Loan(8,929) (8,929)(26,786) (26,786)
Repayment of MARAD Debt(3,387) (3,226)(6,858) (6,532)
Debt issuance costs(113) (3,774)(1,544) (3,867)
Payments related to tax withholding for share-based compensation(826) (1,058)(1,345) (1,058)
Proceeds from issuance of ESPP shares136
 159
462
 506
Net cash used in financing activities(14,055) (12,774)(35,638) (35,974)
      
Effect of exchange rate changes on cash and cash equivalents821
 335
(191) (947)
Net increase (decrease) in cash and cash equivalents(59,436) 7,393
Net increase in cash and cash equivalents6,881
 58,500
Cash and cash equivalents:      
Balance, beginning of year279,459
 266,592
279,459
 266,592
Balance, end of period$220,023
 $273,985
$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 2018 Annual Report on Form 10-K (“2018 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 and statements of cash flows, as applicable. The operating results for the three-month periodthree- and nine-month periods ended March 31,September 30, 2019 are not necessarily indicative of the results that may be expected for the year ending December 31, 2019. Our balance sheet as of December 31, 2018 included herein has been derived from the audited balance sheet as of December 31, 2018 included in our 2018 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 2018 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 February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASC 842”), which was updated by subsequent amendments. ASC 842 requires a lessee to recognize a lease right-of-use asset and related lease liability for most leases, including those classified as operating leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We adopted ASC 842 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 corresponding 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 2016 sale and leaseback transaction to 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.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 iswill be effective for annual reporting periods beginning after December 15, 2019, including interim periods.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 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 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, and subsea intervention lubricators (“SILs”).basis.
 
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and 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, the Helix Fast Response System (the “HFRS”) and, our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 4). The HP I has been under contract to the Phoenix field operator since February 2013, and is currently under a fixed fee agreement through at least June 1, 2023. The HFRS, which was developed in 2011 as a culmination of our experience as a responder in the 2010 Macondo well control and containment efforts, combines our HP I, Q4000 and Q5000 vessels with certain well control equipment that can be deployed to respond to a well control incident in the Gulf of Mexico. The Production Facilities segment also includes certain operating depths, along with several wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244 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
 March 31,
2019		 December 31,
2018
    
Contract assets (Note 9)$10,770
 $5,829
Prepaids16,957
 10,306
Deferred costs (Note 9)26,344
 27,368
Other receivable (Note 13)26,000
 —
Other7,113
 8,091
Total other current assets$87,184
 $51,594

 


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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
 March 31,
2019		 December 31,
2018
    
Prepaids$1,028
 $5,896
Deferred recertification and dry dock costs, net21,676
 8,525
Deferred costs (Note 9)33,058
 38,574
Charter deposit (1)
12,544
 12,544
Other receivable (Note 13)25,410
 —
Other4,561
 4,518
Total other assets, net$98,277
 $70,057

(1)
This amount is deposited with the owner of 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
 March 31,
2019		 December 31,
2018
    
Accrued payroll and related benefits$18,576
 $43,079
Deferred revenue (Note 9)9,748
 10,103
Asset retirement obligations (Note 13)27,500
 —
Derivative liability (Note 17)7,323
 9,311
Other18,695
 23,101
Total accrued liabilities$81,842
 $85,594

 
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
 March 31,
2019		 December 31,
2018
    
Investee losses in excess of investment (Note 4)$5,466
 $6,035
Deferred gain on sale of property (1)
—
 5,052
Deferred revenue (Note 9)13,582
 15,767
Asset retirement obligations (Note 13)26,282
 —
Derivative liability (Note 17)—
 884
Other3,097
 11,800
Total other non-current liabilities$48,427
 $39,538

(1)Relates to the sale and lease-back in January 2016 of our office and warehouse property located in Aberdeen, Scotland. The deferred gain had been amortized over a 15-year minimum lease 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.

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Note 4 — 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 recordeddue. The platform decommissioning process is currently underway and is expected to be substantially completed within the next 12 months. We had a liability of $10.6$7.6 million at March 31,September 30, 2019 and $11.2 million at December 31, 2018 for our share of theIndependence Hub’s estimated obligations, net of remaining working capital. This liability is reflected in “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

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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 to 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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 Three Months Ended
 March 31, 2019
  
Operating lease cost$18,133
Variable lease cost3,075
Short-term lease cost4,158
Sublease income(353)
Net lease cost$25,013

Maturities of our operating lease liabilities as of March 31,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
 Vessels Facilities and Equipment Total
      
Remainder of 2019$49,454
 $5,167
 $54,621
202060,362
 6,258
 66,620
202154,611
 5,510
 60,121
202252,106
 5,077
 57,183
202334,580
 4,512
 39,092
Thereafter2,470
 10,434
 12,904
Total lease payments$253,583
 $36,958
 $290,541
Less: imputed interest(35,878) (7,877) (43,755)
Total operating lease liabilities$217,705
 $29,081
 $246,786
      
Current operating lease liabilities$50,242
 $4,999
 $55,241
Non-current operating lease liabilities167,463
 24,082
 191,545
Total operating lease liabilities$217,705
 $29,081
 $246,786

 

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The following table presents the weighted average remaining lease term and discount rate:
 March 31,September 30, 2019
  
Weighted average remaining lease term4.64.2 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
 Three Months Ended
 March 31, 2019
  
Cash paid for operating lease liabilities$17,148
ROU assets obtained in exchange for new operating lease obligations89

 
As previously disclosed in our 2018 Annual Report on 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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 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 March 31,September 30, 2019 are as follows (in thousands):
 
Term
Loan (1)
 
2022
Notes
 2023 Notes 
MARAD
Debt
 
Nordea
Q5000
Loan
 Total
            
Less than one year$5,147
 $—
 $—
 $7,027
 $35,714
 $47,888
One to two years27,610
 —
 —
 7,378
 80,357
 115,345
Two to three years—
 —
 —
 7,746
 —
 7,746
Three to four years—
 125,000
 —
 8,133
 —
 133,133
Four to five years—
 —
 125,000
 8,539
 —
 133,539
Over five years—
 —
 —
 28,258
 —
 28,258
Gross debt32,757
 125,000
 125,000
 67,081
 116,071
 465,909
Unamortized debt discounts (2)
—
 (10,305) (16,984) —
 —
 (27,289)
Unamortized debt issuance costs (3)
(310) (1,633) (2,738) (3,903) (829) (9,413)
Total debt32,447
 113,062
 105,278
 63,178
 115,242
 429,207
Less: current maturities(5,147) —
 —
 (7,027) (35,714) (47,888)
Long-term debt$27,300
 $113,062
 $105,278
 $56,151
 $79,528
 $381,319

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Term
Loan (1)
 
2022
Notes
 2023 Notes 
MARAD
Debt
 
Nordea
Q5000
Loan
 Total
            
Less than one year$3,500
 $—
 $—
 $7,200
 $98,214
 $108,914
One to two years3,500
 —
 —
 7,560
 —
 11,060
Two to three years27,125
 125,000
 —
 7,937
 —
 160,062
Three to four years—
 —
 125,000
 8,333
 —
 133,333
Four to five years—
 —
 —
 8,749
 —
 8,749
Over five years—
 —
 —
 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 debt33,687
 114,848
 107,146
 59,951
 97,768
 413,400
Less: current maturities(3,500) —
 —
 (7,200) (97,768) (108,468)
Long-term debt$30,187
 $114,848
 $107,146
 $52,751
 $—
 $304,932
(1)Term Loan pursuant to the Credit Agreement (as defined below) matures in June 2020.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 March 31,September 30, 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 $147.3$172.6 million, net of $2.7$2.4 million of letters of credit issued under that facility.
 
The Term Loan andBorrowings under the Revolving Loans (together, the “Loans”),Credit Agreement bear interest, at our election, bear interest at either Bank of America’s base rate, the 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 6.75%5.29% as of March 31,September 30, 2019. TheBorrowings 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 prepay indebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay indebtedness 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 Interest Coverage Ratio) and, funded debt to EBITDA (Consolidated Total Leverage Ratio), and provided 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 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..
 

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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 the 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”). 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.covenants. Our obligations under the Credit Agreement, and those 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.
 
OnIn January 18, 2019, contemporaneously with our purchase from Marathon Oil of certain operating depthsseveral wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure, we amended ourthe 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).
 
Convertible Senior Notes Due 2022 (“2022 Notes”)
 
On November 1, 2016, we completed a 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-monththree- and nine-month periods ended March 31,September 30, 2019, and 2018, 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 debt discount of the 2022 Notes was $10.3$8.8 million at March 31,September 30, 2019 and $11.0 million at December 31, 2018.
 

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Convertible Senior Notes Due 2023 (“2023 Notes”)
 
On March 20, 2018, we completed a 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 Convertible Senior Notes due 2032 (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).
 
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-monththree- and nine-month periods ended March 31,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 $0.4$4.3 million, respectively. The remaining unamortized debt discount of the 2023 Notes was $17.0$15.4 million at March 31,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.
 

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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 indebtedness 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 interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 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.
 
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 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 March 31,September 30, 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
March 31,
 2019 2018
    
Interest expense$7,896
 $8,299
Interest income(758) (590)
Capitalized interest(5,040) (3,813)
Net interest expense$2,098
 $3,896

Note 7 — Income Taxes
 
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.
 
The effective tax rates for the three-monththree- and nine-month periods ended March 31,September 30, 2019 were 10.1% and 2018 were 19.7% and (3.5)%11.9%, respectively. The variance waseffective tax rates for the three- and nine-month periods ended September 30, 2018 were 3.0% and 2.8%, respectively. The increases were primarily attributable to improvements in profitability in the earnings mix between our higher and lower tax rate jurisdictions.U.S. year over year.

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Income taxes are provided based on the U.S. statutory rate and 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
March 31,
 2019 2018
    
U.S. statutory rate21.0 % 21.0 %
Foreign provision(2.7) (19.1)
Other1.4
 (5.4)
Effective rate19.7 % (3.5)%
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Note 8 —Shareholders’ Equity
 
The components of accumulated other comprehensive income (loss)loss (“accumulated OCI”) are as follows (in thousands):
March 31,
2019		 December 31,
2018		September 30,
2019		 December 31,
2018
      
Cumulative foreign currency translation adjustment$(67,053) $(69,855)$(74,419) $(69,855)
Net unrealized loss on hedges, net of tax (1)
(2,754) (4,109)(781) (4,109)
Accumulated OCI$(69,807) $(73,964)$(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 17) and is net of deferred income taxes totaling $0.7$0.2 million at March 31,September 30, 2019 and $1.0 million at December 31, 2018.
Note 9 —Revenue from Contracts with Customers
 
We generate revenue in our Well Intervention segment by supplying 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 supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties.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.

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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 and repair rate). 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 include fees charged to the customer for mobilizing and/or 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.
A dayrate contract modification involving an extension of the contract by adding additional days of services is generally accounted for prospectively 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.
For additional information regarding revenue recognition, see Notes 2 and 10 to our 2018 Form 10-K.

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Disaggregation of Revenue
The following table provides information about disaggregated revenue by contract duration (in thousands):
 Well Intervention Robotics Production Facilities 
Intercompany Eliminations (1)
 Total Revenue Well Intervention Robotics Production Facilities 
Intercompany Eliminations (1)
 Total Revenue
Three months ended March 31, 2019          
Three months ended September 30, 2019          
Short-termShort-term$29,805
 $24,930
 $—
 $—
 $54,735
Short-term$53,018
 $26,809
 $—
 $—
 $79,827
Long-term (2)
Long-term (2)
92,426
 14,111
 15,253
 (9,702) 112,088
Long-term (2)
117,188
 25,100
 13,777
 (23,283) 132,782
TotalTotal$122,231
 $39,041
 $15,253
 $(9,702) $166,823
Total$170,206
 $51,909
 $13,777
 $(23,283) $212,609
                    
Three months ended March 31, 2018          
Three months ended September 30, 2018          
Short-termShort-term$42,027
 $20,324
 $—
 $—
 $62,351
Short-term$39,548
 $29,877
 $—
 $—
 $69,425
Long-term (2)
Long-term (2)
87,542
 6,845
 16,321
 (8,797) 101,911
Long-term (2)
114,893
 24,463
 15,877
 (12,083) 143,150
TotalTotal$129,569
 $27,169
 $16,321
 $(8,797) $164,262
Total$154,441
 $54,340
 $15,877
 $(12,083) $212,575
          
          
Nine months ended September 30, 2019          
Short-termShort-term$145,611
 $80,440
 $—
 $—
 $226,051
Long-term (2)
Long-term (2)
305,900
 55,956
 44,651
 (51,398) 355,109
TotalTotal$451,511
 $136,396
 $44,651
 $(51,398) $581,160
          
Nine months ended September 30, 2018          
Short-termShort-term$143,510
 $74,050
 $—
 $—
 $217,560
Long-term (2)
Long-term (2)
302,259
 46,519
 48,541
 (33,417) 363,902
TotalTotal$445,769
 $120,569
 $48,541
 $(33,417) $581,462

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(1)Intercompany revenues among 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.
 
Contract Balances
 
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 provided to a customer when those 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 sheets (Note 3). Contract assets were $10.8$0.6 million at March 31,September 30, 2019 and $5.8 million at December 31, 2018. ImpairmentWe incurred no impairment losses recognized on our accounts receivable and contract assets were immaterial for the three-monththree- and nine-month periods ended March 31,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 and/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 sheets (Note 3). Contract liabilities totaled $23.3$20.0 million at March 31,September 30, 2019 and $25.9 million at December 31, 2018. Revenue recognized for the three-monththree- and nine-month periods ended March 31,September 30, 2019 included $4.0 million and $7.4 million, 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 $2.5$7.4 million and $8.6$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.
 

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Performance Obligations
 
As of March 31,September 30, 2019, $1.1 billion$833.8 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $408.4$114.5 million in 2019, $396.4$443.2 million in 2020 and $277.8$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 of 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 March 31,September 30, 2019.
 
For the three-monththree- and nine-month periods ended March 31,September 30, 2019 and 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.
 

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Contract Fulfillment 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 the 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 sheets (Note 3). Our deferred contract costs totaled $59.4$47.1 million at March 31,September 30, 2019 and $65.9 million at December 31, 2018. For the three-monththree- and nine-month periods ended March 31,September 30, 2019, and 2018, we recorded $7.7 million and $8.9$23.6 million, respectively, related to amortization of deferred contract costs existing at the beginning of each period,period. For the three- and therenine-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. There were no associated impairment losses.losses for any period presented.
For additional information regarding revenue recognition, see Notes 2 and 10 to our 2018 Form 10-K.
Note 10 — Earnings Per Share
 
We have shares of restricted stock issued and outstanding that are currently unvested. Shares 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. We are required to compute earnings per share (“EPS”) under the two-class method in periods in which we have earnings. Under 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. For periods in which we have a net loss we do not use the two-class method as holders of our restricted shares are not obligated to share in such losses.
 
The presentation of basic EPS 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 are as follows (in thousands):

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 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



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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
 Three Months Ended
March 31, 2019		 Three Months Ended
March 31, 2018
 Income Shares Income Shares
Basic:       
Net income (loss)$1,318
   $(2,560)  
Less: Undistributed earnings allocated to participating securities(12)   —
  
Undistributed earnings (loss) allocated to common shares$1,306
 147,421
 $(2,560) 146,653
        
Diluted:       
Undistributed earnings (loss) allocated to common shares$1,306
 147,421
 $(2,560) 146,653
Effect of dilutive securities:       
Share-based awards other than participating securities—
 330
 —
 —
Net income (loss)$1,306
 147,751
 $(2,560) 146,653
We had a net loss for the three-month period ended March 31, 2018. Accordingly, our diluted EPS calculation for that period was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents, which were deemed to be anti-dilutive. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands): 
Three Months Ended
March 31, 2018
Diluted shares (as reported)146,653
Share-based awards243
Total146,896

 
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 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
March 31,
 2019 2018
    
2022 Notes8,997
 8,997
2023 Notes13,202
 1,614
2032 Notes (1)
—
 2,113

(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 March 31,September 30, 2019, there were 1.48.5 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 three-monthnine-month period ended March 31,September 30, 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/Unit
  Vesting Period  
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 688,540
 $5.41
 33% per year over three years
January 2, 2019 (2)
 688,540
 7.60
 100% on January 2, 2022 688,540
 7.60
 100% on January 2, 2022
January 2, 2019 (3)
 11,841
 5.41
 100% on January 1, 2021 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 and select management employees.
(2)Reflects grants of performance share units (“PSUs”) to our executive 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.0.
(3)Reflects grants of restricted stock to certain independent members of our Board of Directors (our “Board”) who have elected 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 her 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 period on a straight-line basis. Forfeitures are recognized as they occur. For the three-monththree- and nine-month periods ended March 31,September 30, 2019, and 2018, $1.3$1.2 million and $4.9 million respectively, were recognized as share-based compensation related to restricted stock. For the three- and nine-month periods ended September 30, 2018, $1.5 million and $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. 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 therefore are accounted for as equity 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.basis as an increase to equity. For the three-monththree- and nine-month periods ended March 31,September 30, 2019, and 2018, $1.3$1.2 million and $1.0$3.9 million, respectively, were recognized as share-based compensation 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. The liability balance for previously unvested PSUs granted in January 2016 was $11.1 million at December 31, 2018, which we settled in cash when those PSUs vested in January 2019.
 
Additionally in 20182019 and 2019,2018, we granted fixed-value cash awards of $4.6 million and $5.2 million, and $4.5 million of fixed value cash awardsrespectively, to select management employees under the 2005 Incentive Plan. The value of fixed value cash awards is recognized on a straight-line basis over a vesting period of three years. For the three-monththree- and nine-month periods ended March 31,September 30, 2019, and 2018, $0.8 million and $0.4$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 million, respectively, were recognized as compensation cost.
 
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 March 31, 2019.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 ourthe ESPP, see Note 12 to our 2018 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 Enhancer, 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.basis. Our Robotics segment includes ROVs, trenchers and 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, our ownership interest in Independence Hub (Note 4) and our ownership of certain oil and gas properties that we acquired from Marathon Oil in January 2019 (Note 13). All material intercompany transactions between the segments have been eliminated.
 
We evaluate our performance 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
March 31,
 2019 2018
Net revenues —   
Well Intervention$122,231
 $129,569
Robotics39,041
 27,169
Production Facilities15,253
 16,321
Intercompany eliminations(9,702) (8,797)
Total$166,823
 $164,262
    
Income (loss) from operations —   
Well Intervention$9,641
 $13,877
Robotics(3,904) (14,317)
Production Facilities4,405
 7,359
Segment operating income10,142
 6,919
Corporate, eliminations and other(9,873) (8,035)
Total$269
 $(1,116)

 
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.
 Three Months Ended
March 31,
 2019 2018
    
Well Intervention$3,225
 $1,952
Robotics6,477
 6,845
Total$9,702
 $8,797


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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
 March 31,
2019		 December 31,
2018
    
Well Intervention$2,104,002
 $1,916,638
Robotics190,473
 147,602
Production Facilities182,830
 120,845
Corporate and other130,016
 162,645
Total$2,607,321
 $2,347,730

Note 13 — Asset Retirement Obligations
 
Our asset retirement obligations (“AROs”) consist of estimated costs for subsea infrastructure plugging and abandonmentP&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
53,294
Liability settled during the period(15,944)
Accretion expense488
1,770
AROs at March 31, 2019$53,782
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 plug and abandonmentP&A of those assets in exchange for agreed-upon amounts to be paid by Marathon Oil as the plugging and abandonmentP&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 Petróleo 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 entered 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, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% is due 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 March 31,September 30, 2019, our total investment in the Q7000 was $413.3$446.4 million, including $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.
 

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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 and cash flows.
 
Litigation
 
We are involved in various legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act. In addition, from time to time we receive 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):
 Nine Months Ended
September 30,
 2019 2018
    
Interest paid, net of interest capitalized$2,404
 $6,620
Income taxes paid7,535
 4,699
 Three Months Ended
March 31,
 2019 2018
    
Interest paid, net of interest capitalized$1,604
 $2,238
Income taxes paid2,704
 3,036

 
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 $9.5$14.0 million at March 31,September 30, 2019 and $9.9 million at December 31, 2018.
Note 16 — 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 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
March 31, 2019 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$—
 $717
 $—
 $717
 (c)$—
 $108
 $—
 $108
 (c)
                
Liabilities:                
Foreign exchange contracts — hedging instruments—
 4,167
 —
 4,167
 (c)—
 1,089
 —
 1,089
 (c)
Foreign exchange contracts — non-hedging instruments—
 3,156
 —
 3,156
 (c)—
 1,634
 —
 1,634
 (c)
Total net liability$—
 $6,606
 $—
 $6,606
 $—
 $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, 2018 Using		    
 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
  

 
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
 March 31, 2019 December 31, 2018
 
Principal Amount (1)
 
Fair
Value (2) (3)
 
Principal Amount (1)
 
Fair
Value (2) (3)
        
Term Loan (matures June 2020)$32,757
 $32,716
 $33,693
 $33,314
Nordea Q5000 Loan (matures April 2020)116,071
 115,200
 125,000
 122,500
MARAD Debt (matures February 2027)67,081
 70,997
 70,468
 74,406
2022 Notes (mature May 2022)125,000
 123,438
 125,000
 114,298
2023 Notes (mature September 2023)125,000
 141,250
 125,000
 114,688
Total debt$465,909
 $483,601
 $479,161
 $459,206

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(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 and the 2023 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 2022 Notes and the 2023 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.
Note 17 — 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. Cash flow hedges are entered into to hedge 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 OCI. These changes are subsequently reclassified into earnings when the hedged transactions settle. In addition, any changeaffect earnings. Changes 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.
 
For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 18 to our 2018 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 interest rate swap contracts to fix the interest rate on $187.5 million of ourthe Nordea Q5000 Loan (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 accumulated OCI (net of tax). These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense.
 

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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 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 our foreign currency exchange contracts that qualify for hedge accounting treatment are included in accumulated 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, net” in the accompanying condensed consolidated statements of operations.
 

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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
 March 31, 2019 December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivative Instruments:       
Interest rate swapsOther current assets $685
 Other current assets $863
Interest rate swapsOther assets, net 32
 Other assets, net 201
   $717
   $1,064
        
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $4,167
 Accrued liabilities $5,857
Foreign exchange contractsOther non-current liabilities —
 Other non-current liabilities 354
   $4,167
   $6,211

 
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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 March 31, 2019 December 31, 2018
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $3,156
 Accrued liabilities $3,454
Foreign exchange contractsOther non-current liabilities —
 Other non-current liabilities 530
   $3,156
   $3,984

The following tables present the impact that derivative instruments designated as hedging instruments had on our accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of March 31,September 30, 2019, $2.8$0.8 million of net losses in accumulated 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
  Three Months Ended
March 31,
  2019 2018
     
Foreign exchange contracts $(34) $1,588
Interest rate swaps (115) 565
  $(149) $2,153

 

 
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)
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Location of Gain (Loss) Reclassified from
Accumulated OCI into Earnings
 
Gain (Loss) Reclassified from
Accumulated OCI into Earnings
  Three Months Ended
March 31,
  2019 2018
      
Foreign exchange contractsCost of sales $(2,078) $(1,656)
Interest rate swapsNet interest expense 232
 29
   $(1,846) $(1,627)

 
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)


30

 
Location of Gain (Loss)
Recognized in Earnings
 Gain (Loss) Recognized in Earnings
  Three Months Ended
March 31,
  2019 2018
      
Foreign exchange contractsOther income, net $(40) $844
   $(40) $844
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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 and 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, completion, upgrades or maintenance of vessels or equipment and any anticipated costs or downtime related thereto, including the construction and completion 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;

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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, chartering or customer acceptance, and terms of acceptance, of our 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 U.S.2017 Tax Cuts and Jobs Act (the “2017 Tax Act”);Act;
the impact of the vote in the U.K. to potentially exit the European Union, 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 2018 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.

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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 should 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. 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 plugging and abandonmentP&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 leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. We and OneSubsea jointly developed a 15,000 working p.s.i. intervention riser system (“15K IRS”), each owning a 50% interest. The 15K IRS was completed and placed into service in January 2018. Our total investment in the 15K IRS was approximately $17 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $6 million for our, each owning a 50% interest. At March 31, 2019, our total investment inFinal 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, China and India;gas;

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political and 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;
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.
 

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West Texas Intermediate oil prices have been volatile, entering the year at $45 per barrelfluctuating between $50 and reaching $60 per barrel at March 31,throughout most of the first nine months of 2019. Volatility in oil prices causesand imbalance in the supply and demand for oil creatingcreate 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 when 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 weaken oil prices and industry prospects. The resulting industry environment may discourage oil and gas companies from making longer termlonger-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 as oil and gas companies begin to increase overall spending levels, it likely will likely be weighted 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 managing 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. We could see the beginnings of an upturn in the demand for our services in the U.S. Gulf of Mexico, which are primarily driven by twothree factors: (1) long-term rig contracts are not being renewed thus removing some of the rig overhang that was considered by our customers to be a sunk cost; and (2) previously deferred work on aging wells is less likely to be further deferred as well performance declines.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 access to the HFRS for well control purposes through March 31, 2020 on newly agreed-upon rates and terms. These agreements automatically renew on an annual basis absent proper notice of termination by one of the parties.termination.

On January 18, 2019, we acquired from Marathon Oil certain operating depthsseveral wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure.244. As part of the transaction, Marathon Oil will pay us agreed-upon amounts for the required plug and abandonmentP&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.

32On 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 provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. In addition to serving the oil and gas market, our Robotics assets are contracted for the development of renewable energy projects (wind farms). As of March 31,September 30, 2019, our consolidated backlog that is supported by written agreements or contracts totaled $1.1 billion,$834 million, of which $408$115 million is expected to be performed over the remainder of 2019. The substantial majority of our backlog is associated with our Well Intervention business segment. As of March 31,September 30, 2019, our well intervention backlog was $0.8 billion,$627 million, including $310$92 million expected to be performed over the remainder of 2019. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with 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 86% of our total backlog as of March 31,September 30, 2019. Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be 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 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 flows 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
March 31,		Three Months Ended
September 30,		 Nine Months Ended
September 30,
2019 20182019 2018 2019 2018
          
Net income (loss)$1,318
 $(2,560)
Net income$31,622
 $27,121
 $49,763
 $42,345
Adjustments:          
Income tax provision324
 87
3,539
 841
 6,739
 1,226
Net interest expense2,098
 3,896
1,901
 3,249
 6,204
 10,744
Loss on extinguishment of long-term debt—
 1,105
—
 2
 18
 1,183
Other income, net(1,166) (925)
Other expense, net2,285
 709
 2,430
 3,225
Depreciation and amortization28,509
 27,782
27,908
 27,680
 84,420
 83,339
EBITDA31,083
 29,385
67,255
 59,602
 149,574
 142,062
Adjustments:          
Gain on disposition of assets, net—
 (146) —
 (146)
Realized losses from foreign exchange contracts not designated as hedging instruments(869) (690)(982) (820) (2,763) (2,316)
Other than temporary loss on note receivable—
 (1,129)—
 —
 —
 (1,129)
Adjusted EBITDA$30,214
 $27,566
$66,273
 $58,636
 $146,811
 $138,471
 
The reconciliation of our cash flows from operating activities to free cash flow is as follows (in thousands): 
Three Months Ended
March 31,		Nine Months Ended
September 30,
2019 20182019 2018
      
Cash flows from operating activities$(34,246) $41,046
$89,877
 $150,827
Less: Capital expenditures, net of proceeds from sale of assets(11,630) (21,214)(43,086) (55,406)
Free cash flow$(45,876) $19,832
$46,791
 $95,421




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Comparison of Three Months Ended March 31,September 30, 2019 and 2018 
 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
Three Months Ended
March 31,		 
Increase/
(Decrease)
Three Months Ended
September 30,		 
Increase/
(Decrease)
2019 2018 Amount Percent2019 2018 Amount Percent
Net revenues —              
Well Intervention$122,231
 $129,569
 $(7,338) (6)%$170,206
 $154,441
 $15,765
 10 %
Robotics39,041
 27,169
 11,872
 44 %51,909
 54,340
 (2,431) (4)%
Production Facilities15,253
 16,321
 (1,068) (7)%13,777
 15,877
 (2,100) (13)%
Intercompany eliminations(9,702) (8,797) (905)  (23,283) (12,083) (11,200)  
$166,823
 $164,262
 $2,561
 2 %$212,609
 $212,575
 $34
 — %
              
Gross profit (loss) —              
Well Intervention$13,510
 $17,688
 $(4,178) (24)%$41,014
 $37,833
 $3,181
 8 %
Robotics(1,589) (11,898) 10,309
 87 %10,998
 8,089
 2,909
 36 %
Production Facilities4,771
 7,457
 (2,686) (36)%3,481
 6,831
 (3,350) (49)%
Corporate, eliminations and other(438) (264) (174)  (419) (760) 341
  
$16,254
 $12,983
 $3,271
 25 %$55,074
 $51,993
 $3,081
 6 %
              
Gross margin —              
Well Intervention11%
 14%
    24%
 24%
    
Robotics(4)%
 (44)%
    21%
 15%
    
Production Facilities31%
 46%
    25%
 43%
    
Total company10%
 8%
    26%
 24%
    
              
Number of vessels or robotics assets (1) / Utilization (2)
              
Well Intervention vessels6/74%
 6/73%
    6/97%
 6/91%
    
Robotics assets(3)52/39%
 55/30%
    51/44%
 54/42%
    
Chartered robotics vessels4/88%
 4/56%
    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.
(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 March 31,September 30, 2019 and 2018 include 84included 28 and 42113 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): 
Three Months Ended
March 31,		 
Increase/
(Decrease)
Three Months Ended
September 30,		 
Increase/
(Decrease)
2019 2018 2019 2018 
          
Well Intervention$3,225
 $1,952
 $1,273
$15,318
 $4,379
 $10,939
Robotics6,477
 6,845
 (368)7,965
 7,704
 261
$9,702
 $8,797
 $905
$23,283
 $12,083
 $11,200


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Net Revenues.  Our total net revenues increased by 2% for the three-month period ended March 31,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 2018 as a result of higher revenues in our Robotics business segment, offset in part by revenue decreases in our Well Intervention and Production Facilities business segments.
Our Well Intervention revenues decreased by 6% for the three-month period ended March 31, 2019 as compared to the same period in 2018, primarily reflecting lower revenues in the Gulf of Mexico, offset by higher revenues in the North Sea and Brazil. The decreaseincreases in revenues in the Gulf of Mexico was primarily attributableand 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 the third quarter of 2019. Revenue increases from the Q4000 and IRS rental were partially offset by lower revenues from the Q5000 due to lower integrated services revenueutilization. Our Well Intervention revenues in the Gulf of Mexico during the firstthird quarter of 2019 as comparedalso 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 the same periodus in 2018. In addition, our IRS rentals contributed to higher revenues in the first quarter of 2018.September 2019. The increase in revenues in the North Sea primarily reflects rate improvements in the region. The increase in revenues In Brazil was primarily a result of the Siem Helix2 achieving 98%99% utilization during the firstthird quarter of 2019 as compared to 88%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 increaseddecreased by 44%4% for the three-month period ended March 31,September 30, 2019 as compared to the same period in 2018. The increasedecrease primarily reflectsreflected lower trenching activity and spot vessel utilization, offset in part by higher trenching activities that contributed to increased utilization ofrates on our Grand CanyonII chartered vessel and higher ROV support vessels (from 56% during the first quarter of 2018 to 88% during the same period in 2019). Our ROVs also achieved higher utilization in the first quarter ofthree-month period ended September 30, 2019 as compared to the same period in 2018.
 
Our Production Facilities revenues decreased by 7%13% for the three-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily reflecting lower revenues from the HFRS during the firstthird quarter of 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 $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.
Gross Profit (Loss).  Our total gross profit increased by 25%6% for the three-month period ended March 31,September 30, 2019 as compared to the same period in 2018 reflecting higher gross profit generated by our Well Intervention and Robotics business 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 8% for the three-month period ended September 30, 2019 as compared to the same period in 2018 primarily as a result of higher revenues in the Gulf of Mexico and Brazil, partially offset by lower revenues in the North Sea.
The gross profit related to our Robotics segment increased by 36% for the three-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting higher revenues generated by our Grand CanyonII chartered vessel and 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 decreased by 49% for the three-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 $4.7 million for the three-month period ended September 30, 2019 as compared to the same period in 2018. The decrease was primarily attributable to compensation costs in the third quarter of 2018 that were related to liability PSU awards, which settled in January 2019 (Note 11).

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Net Interest Expense.  Our net interest expense decreased by $1.3 million for the three-month period ended September 30, 2019 as compared to the same period in 2018 primarily reflecting higher capitalized interest. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $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 24%9% for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily reflecting lower gross profitIRS rental unit utilization in the Gulf of Mexico as a result of lower IRS rental unit utilization,well as reduced operating results in the North Sea, offset in part by improved operating results in the North Sea and Brazil.
 
The gross loss associated with ourOur Robotics segment decreased by 87%achieved a gross profit of $14.5 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to a gross loss of $5.3 million for the same period in 2018 primarily reflecting a reduction in vessel charter costs, higher trenching revenues, with increased utilization for our ROV supportchartered vessels and ROVs.our robotics assets, and a reduction in vessel charter costs.
 
The gross profit related to our Production Facilities segment decreased by 36%38% for the three-monthnine-month period ended March 31,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 increaseddecreased by $1.9$4.1 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018. The increasedecrease was primarily as a resultattributable to compensation costs in the first nine months of increased costs2018 that were related to employee incentive compensation.liability PSU awards, which settled in January 2019 (Note 11).
 
Net Interest Expense.  Our net interest expense decreased by $1.8$4.5 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily reflecting higher interest income and capitalized interest as well asand a decrease in interest expense due to a reduction in our overall debt levels. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $5.0$15.3 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to $3.8$11.5 million for the same period in 2018 as a result of the construction and completion of the Q7000.
 
Loss on Extinguishment of Long-Term Debt.  The $1.1$1.2 million loss for the three-monthnine-month period ended March 31,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).
 

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Income Tax Provision.  Income tax provision increasedOther Expense, Net.  Net other expense decreased by $0.2$0.8 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily reflecting increased profitability ina $1.1 million other than temporary loss on a note receivable during the current period. The effectivenine-month period ended September 30, 2018.
Income Tax Provision.  Income tax rateprovision was 19.7%$6.7 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to (3.5)%$1.2 million for the same period in 2018. The varianceeffective tax rate was 11.9% for the nine-month period ended September 30, 2019 as compared to 2.8% for the same period in 2018. The increase was primarily attributable to improvements in profitability in the earnings mix between our higher and lower tax rate jurisdictionsU.S. year 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): 
March 31,
2019		 December 31,
2018		September 30,
2019		 December 31,
2018
      
Net working capital$201,823
 $259,440
$199,934
 $259,440
Long-term debt (1)
381,319
 393,063
304,932
 393,063
Liquidity (2)
367,362
 426,813
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 long-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 March 31,September 30, 2019 included cash and cash equivalents of $220.0$286.3 million and $147.3$172.6 million of available borrowing capacity under ourthe Revolving Credit Facility (Note 6). Our liquidity at December 31, 2018 included cash and cash equivalents of $279.5 million and $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): 
March 31,
2019		 December 31,
2018		September 30,
2019		 December 31,
2018
      
Term Loan (matures June 2020)$32,447
 $33,321
Term Loan (previously scheduled to mature June 2020)$—
 $33,321
Term Loan (matures December 2021)33,687
 —
Nordea Q5000 Loan (matures April 2020)115,242
 123,980
97,768
 123,980
MARAD Debt (matures February 2027)63,178
 66,443
59,951
 66,443
2022 Notes (mature May 2022) (1)
113,062
 112,192
114,848
 112,192
2023 Notes (mature September 2023) (2)
105,278
 104,379
2023 Notes (mature September 2023) (1)
107,146
 104,379
Total debt$429,207
 $440,315
$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.
 

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The following table provides summary data from our condensed consolidated statements of cash flows (in thousands): 
Three Months Ended
March 31,		Nine Months Ended
September 30,
2019 20182019 2018
Cash provided by (used in):      
Operating activities$(34,246) $41,046
$89,877
 $150,827
Investing activities(11,956) (21,214)(47,167) (55,406)
Financing activities(14,055) (12,774)(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 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 March 31,September 30, 2019 and December 31, 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 March 31,September 30, 2019, our available borrowing capacity under ourthe Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $147.3$172.6 million, net of $2.7$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 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 and 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.
 

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Operating Cash Flows 
 
Total cash flows from operating activities decreased by $75.3$61.0 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily reflecting the timing of cash receipts from our customers and other increases in net working capital during the first quarternine months of 2019 as well as 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): 
Three Months Ended
March 31,		Nine Months Ended
September 30,
2019 20182019 2018
Capital expenditures:      
Well Intervention$(11,485) $(21,190)$(44,323) $(54,845)
Robotics—
 (16)(388) (89)
Production Facilities(2) —
(123) (113)
Other(168) (8)(802) (384)
STL acquisition, net(4,081) —
Proceeds from sale of assets25
 —
2,550
 25
Other$(326) $—
Net cash used in investing activities$(11,956) $(21,214)$(47,167) $(55,406)
 
Our capital expenditures haveabove primarily included payments associated with the construction and completion of our the Q7000 vessel (see below).
 
In September 2013, we entered 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, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% is due 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 March 31,September 30, 2019, our total investment in the Q7000 was $413.3$446.4 million, including $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 $102$80 million related to the Q7000 over the remainder of 2019, including the final shipyard payment of $69.2 million. The vessel is currently in the final preparation phase for work expected to commence in 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. Net cash outflows from financing activities of $14.1$35.6 million for the three-monthnine-month period ended March 31,September 30, 2019 primarily reflectreflected the repayment of $13.3$68.2 million of our indebtedness.indebtedness and $35.0 million in proceeds from the Term Loan (Note 6). Net cash outflows from financing activities of $12.8$36.0 million for the three-monthnine-month period ended March 31,September 30, 2018 primarily reflectreflected the repayment of $133.1$156.6 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of $125 million of ourthe 2023 Notes (Note 6).
 
Free Cash Flow
 
Free cash flow decreased by $65.7$48.6 million for the three-monthnine-month period ended March 31,September 30, 2019 as compared to the same period in 2018 primarily attributable to the decrease in operating cash flows, slightly offset by reduced capital expenditures in the first quarternine months of 2019.
 

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Outlook 
 
We anticipate that our capital expenditures, including capitalized interest and regulatory certification costs for our vessels and systems, will approximate $140$150 million for 2019. We believe that cash on hand, internally generated cash flows and availability under ourthe Revolving Credit Facility will provide the capital necessary to continue funding our 2019 capital obligations and to meet our debt obligations due in 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 March 31,September 30, 2019 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$32,757
 $5,147
 $27,610
 $—
 $—
$34,125
 $3,500
 $30,625
 $—
 $—
Nordea Q5000 Loan116,071
 35,714
 80,357
 —
 —
98,214
 98,214
 —
 —
 —
MARAD Debt67,081
 7,027
 15,124
 16,672
 28,258
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)
62,597
 21,464
 27,231
 11,643
 2,259
55,365
 18,620
 26,941
 8,207
 1,597
Property and equipment (5)
86,607
 86,301
 306
 —
 —
80,261
 80,261
 —
 —
 —
Operating leases (6)
464,641
 118,574
 195,618
 141,120
 9,329
405,123
 110,197
 193,669
 94,408
 6,849
Total cash obligations$1,079,754
 $274,227
 $346,246
 $419,435
 $39,846
$986,698
 $317,992
 $391,732
 $244,697
 $32,277
(1)Excludes unsecured letters of credit outstanding at March 31,September 30, 2019 totaling $2.7$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 March 31,September 30, 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 March 31,September 30, 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 March 31,September 30, 2019 for variable rate debt.
(5)
Primarily reflects costs associated with our the Q7000 semi-submersible well intervention vessel, which is currently under completion (Note 14).
(6)Operating leases include vessel charters and facility and equipment leases. At March 31,September 30, 2019, our commitment related to long-term vessel charters totaled approximately $427.6$366.2 million, of which $173.7$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.
 
For information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our 2018 Form 10-K.

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Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
We are exposed to market risk in two areas:risks associated with interest rates and foreign currency exchange rates.
 
Interest Rate Risk.  As of March 31,September 30, 2019, $148.8$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 March 31,September 30, 2019, the interest rate on $87.1$73.6 million of ourthe Nordea Q5000 Loan was hedged. Debt subject to variable rates after considering hedging activities was $29.0$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 $0.2$0.5 million in interest expense for the three-monthnine-month period ended March 31,September 30, 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 three-monthnine-month period ended March 31,September 30, 2019, we recognized gainslosses of $1.2$2.0 million related to foreign currency transactions in “Other income,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.
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 March 31,September 30, 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 March 31,September 30, 2019 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.
 

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(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 March 31,September 30, 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Part II.  OTHER INFORMATION
Item 1.  Legal Proceedings 
 
See Part I, Item 1, Note 14 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 (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)
January 1 to January 31, 2019 146,338
 $5.65
 —
 4,660,969
February 1 to February 28, 2019 —
 —
 —
 4,660,969
March 1 to March 31, 2019 —
 —
 —
 4,660,969
  146,338
 $5.65
 —
  
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 number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 9 to our 2018 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:April 24,October 23, 2019 By: /s/ Owen Kratz                                   
    
Owen Kratz
President and Chief Executive Officer 
(Principal Executive Officer)
     
Date:April 24,October 23, 2019 By: /s/ Erik Staffeldt                         
    
Erik Staffeldt
Executive Vice President and
Chief Financial Officer 
(Principal Financial Officer)


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