Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q

þQuarterly report pursuant to Section

QUARTERLY REPORT PURSUANT TO SECTION 13 orOR 15(d) of the Securities Exchange Act ofOF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2017

March 31, 2021

or

¨Transition report pursuant to Section

TRANSITION 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 NumberNumber: 001-32936

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Graphic

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)

Minnesota

95-3409686

Minnesota

(State or other jurisdiction

of incorporation or organization)

95–3409686

(I.R.S. Employer

Identification No.)

3505 West Sam Houston Parkway North

Suite 400

HoustonTexas

77043

(Address of principal executive offices)

77043

(Zip Code)

(281)

(281) 618–0400

(Registrant'sRegistrant’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 class

Trading Symbol(s)

Name of each exchange on which registered

Common Stock

HLX

New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  þ Yes ¨ No

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  þ Yes ¨ No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ

Accelerated filer ¨

Non-accelerated filer ¨

Smaller reporting company ¨

Emerging growth company ¨

(Do not check if a smaller reporting company)

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  ¨ Yes þ No

As of October 20, 2017, 147,720,399April 22, 2021, 150,723,988 shares of common stock were outstanding.





Table of Contents

TABLE OF CONTENTS

PART I.

FINANCIAL INFORMATION

PAGE

PART I.

FINANCIAL INFORMATION

PAGE

Item 1.

Financial Statements:

3

Item 1.

Financial Statements:

5

6

Condensed Consolidated Statements of Cash Flows (Unaudited) –

Item 2.

26

Item 3.

37

Item 4.

38

PART II.

OTHER INFORMATION

38

Item 1.

38

Item 2.

38

Item 6.

39

40


2


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PART I. FINANCIAL INFORMATION

Item 1.Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)

 September 30,
2017
 December 31,
2016
 (Unaudited)  
ASSETS
Current assets:   
Cash and cash equivalents$356,889
 $356,647
Accounts receivable:   
Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively90,480
 101,825
Unbilled revenue and other45,816
 10,328
Current deferred tax assets
 16,594
Other current assets38,172
 37,388
Total current assets531,357
 522,782
Property and equipment2,612,407
 2,450,890
Less accumulated depreciation(878,248) (799,280)
Property and equipment, net1,734,159
 1,651,610
Other assets, net100,974
 72,549
Total assets$2,366,490
 $2,246,941
    
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:   
Accounts payable$91,412
 $60,210
Accrued liabilities60,761
 58,614
Income tax payable1,756
 
Current maturities of long-term debt108,611
 67,571
Total current liabilities262,540
 186,395
Long-term debt395,345
 558,396
Deferred tax liabilities154,158
 167,351
Other non-current liabilities42,736
 52,985
Total liabilities854,779
 965,127
Commitments and contingencies

 

Shareholders equity:
   
Common stock, no par, 240,000 shares authorized, 147,713 and 120,630 shares issued, respectively1,281,747
 1,055,934
Retained earnings302,326
 322,854
Accumulated other comprehensive loss(72,362) (96,974)
Total shareholders equity
1,511,711
 1,281,814
Total liabilities and shareholders equity
$2,366,490
 $2,246,941

March 31, 

December 31, 

    

2021

    

2020

ASSETS

 

  

 

  

Current assets:

 

  

 

  

Cash and cash equivalents

$

204,802

$

291,320

Restricted cash

 

65,579

 

Accounts receivable, net of allowance for credit losses of $1,665 and $3,469, respectively

 

132,314

 

132,233

Other current assets

 

86,242

 

102,092

Total current assets

 

488,937

 

525,645

Property and equipment

 

2,956,804

 

2,948,907

Less accumulated depreciation

 

(1,197,712)

 

(1,165,943)

Property and equipment, net

 

1,759,092

 

1,782,964

Operating lease right-of-use assets

 

136,210

 

149,656

Other assets, net

 

37,510

 

40,013

Total assets

$

2,421,749

$

2,498,278

LIABILITIES AND SHAREHOLDERS' EQUITY

 

  

 

  

Current liabilities:

 

  

 

  

Accounts payable

$

55,148

$

50,022

Accrued liabilities

 

76,486

 

87,035

Current maturities of long-term debt

 

36,478

 

90,651

Current operating lease liabilities

 

50,321

 

51,599

Total current liabilities

 

218,433

 

279,307

Long-term debt

 

299,560

 

258,912

Operating lease liabilities

 

88,576

 

101,009

Deferred tax liabilities

 

100,655

 

110,821

Other non-current liabilities

 

3,105

 

3,878

Total liabilities

 

710,329

 

753,927

Redeemable noncontrolling interests

 

3,960

 

3,855

Shareholders’ equity:

 

  

 

  

Common stock, 0 par, 240,000 shares authorized, 150,715 and 150,341 shares issued, respectively

 

1,286,380

 

1,327,592

Retained earnings

 

468,087

 

464,524

Accumulated other comprehensive loss

 

(47,007)

 

(51,620)

Total shareholders’ equity

 

1,707,460

 

1,740,496

Total liabilities, redeemable noncontrolling interests and shareholders’ equity

$

2,421,749

$

2,498,278

The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)

 Three Months Ended
September 30,
 2017 2016
    
Net revenues$163,260
 $161,245
Cost of sales142,119
 121,061
Gross profit21,141
 40,184
Selling, general and administrative expenses(16,374) (18,714)
Income from operations4,767
 21,470
Equity in losses of investment(153) (122)
Net interest expense(3,615) (6,843)
Gain on early extinguishment of long-term debt
 244
Other income (expense), net(551) 830
Other income (expense) – oil and gas303
 (468)
Income before income taxes751
 15,111
Income tax provision (benefit)(1,539) 3,649
Net income$2,290
 $11,462
    
Earnings per share of common stock:   
Basic$0.02
 $0.10
Diluted$0.02
 $0.10
    
Weighted average common shares outstanding:   
Basic145,958
 113,680
Diluted145,958
 113,680

Three Months Ended

March 31, 

    

2021

    

2020

Net revenues

$

163,415

$

181,021

Cost of sales

 

148,791

 

179,011

Gross profit

 

14,624

 

2,010

Goodwill impairment

 

 

(6,689)

Selling, general and administrative expenses

 

(15,179)

 

(16,348)

Loss from operations

 

(555)

 

(21,027)

Net interest expense

 

(6,053)

 

(5,746)

Other income (expense), net

 

1,617

 

(10,427)

Royalty income and other

 

2,057

 

2,179

Loss before income taxes

 

(2,934)

 

(35,021)

Income tax provision (benefit)

 

116

 

(21,093)

Net loss

 

(3,050)

 

(13,928)

Net loss attributable to redeemable noncontrolling interests

 

(172)

 

(1,990)

Net loss attributable to common shareholders

$

(2,878)

$

(11,938)

Loss per share of common stock:

 

  

 

  

Basic

$

(0.02)

$

(0.09)

Diluted

$

(0.02)

$

(0.09)

Weighted average common shares outstanding:

 

  

 

  

Basic

 

149,935

 

148,863

Diluted

 

149,935

 

148,863

The accompanying notes are an integral part of these condensed consolidated financial statements.


4


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

COMPREHENSIVE INCOME

(UNAUDITED)

(in thousands, except per share amounts)

 Nine Months Ended
September 30,
 2017 2016
    
Net revenues$418,117
 $359,551
Cost of sales379,434
 330,639
Gross profit38,683
 28,912
Loss on disposition of assets, net(39) 
Selling, general and administrative expenses(46,532) (47,493)
Loss from operations(7,888) (18,581)
Equity in losses of investment(457) (366)
Net interest expense(15,480) (25,007)
Gain (loss) on early extinguishment of long-term debt(397) 546
Other income (expense), net(619) 4,018
Other income – oil and gas3,196
 2,500
Loss before income taxes(21,645) (36,890)
Income tax provision (benefit)(1,117) (9,858)
Net loss$(20,528) $(27,032)
    
Loss per share of common stock:   
Basic$(0.14) $(0.25)
Diluted$(0.14) $(0.25)
    
Weighted average common shares outstanding:   
Basic145,057
 109,135
Diluted145,057
 109,135
thousands)

Three Months Ended

March 31, 

2021

    

2020

Net loss

$

(3,050)

 

$

(13,928)

Other comprehensive income (loss), net of tax:

 

  

 

  

Net unrealized loss on hedges arising during the period

 

 

(96)

Reclassifications into earnings

 

 

427

Income taxes on hedges

 

 

(66)

Net change in hedges, net of tax

 

 

265

Foreign currency translation gain (loss)

 

4,613

 

(33,587)

Other comprehensive income (loss), net of tax

 

4,613

 

(33,322)

Comprehensive income (loss)

 

1,563

 

(47,250)

Less comprehensive loss attributable to redeemable noncontrolling interests:

 

  

 

  

Net loss

 

(172)

 

(1,990)

Foreign currency translation gain (loss)

 

36

 

(228)

Comprehensive loss attributable to redeemable noncontrolling interests

 

(136)

 

(2,218)

Comprehensive income (loss) attributable to common shareholders

$

1,699

 

$

(45,032)

The accompanying notes are an integral part of these condensed consolidated financial statements.


5


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)

 Three Months Ended
September 30,
 2017 2016
    
Net income$2,290
 $11,462
Other comprehensive income, net of tax:   
Unrealized gain on hedges arising during the period2,297
 4,418
Reclassification adjustments for loss on hedges included in net income3,383
 3,157
Income taxes on unrealized gain on hedges(1,992) (2,683)
Unrealized gain on hedges, net of tax3,688
 4,892
Foreign currency translation gain (loss)5,513
 (3,611)
Other comprehensive income, net of tax9,201
 1,281
Comprehensive income$11,491
 $12,743
 Nine Months Ended
September 30,
 2017 2016
    
Net loss$(20,528) $(27,032)
Other comprehensive income (loss), net of tax:   
Unrealized gain on hedges arising during the period4,141
 5,450
Reclassification adjustments for loss on hedges included in net loss10,822
 9,651
Income taxes on unrealized gain on hedges(5,256) (5,236)
Unrealized gain on hedges, net of tax9,707
 9,865
Foreign currency translation gain (loss) arising during the period14,905
 (24,827)
Reclassification adjustment for translation loss realized upon liquidation
 289
Foreign currency translation gain (loss)14,905
 (24,538)
Other comprehensive income (loss), net of tax24,612
 (14,673)
Comprehensive income (loss)$4,084
 $(41,705)

Accumulated

 

Other

Total

Redeemable

Common Stock

Retained

Comprehensive

Shareholders’

Noncontrolling

    

Shares

    

Amount

    

Earnings

    

Loss

    

Equity

    

Interests

Balance, December 31, 2020

 

150,341

$

1,327,592

$

464,524

$

(51,620)

$

1,740,496

 

$

3,855

Net loss

 

 

 

(2,878)

 

 

(2,878)

 

(172)

Cumulative-effect adjustments upon adoption of ASU No. 2020-06

 

 

(41,456)

 

6,682

 

 

(34,774)

 

Foreign currency translation adjustments

 

 

 

 

4,613

 

4,613

 

36

Accretion of redeemable noncontrolling interests

 

 

 

(241)

 

 

(241)

 

241

Activity in company stock plans, net and other

 

374

 

(1,600)

 

 

 

(1,600)

 

Share-based compensation

 

 

1,844

 

 

 

1,844

 

Balance, March 31, 2021

 

150,715

$

1,286,380

$

468,087

$

(47,007)

$

1,707,460

 

$

3,960

Accumulated

 

Other

Total

Redeemable

Common Stock

Retained

Comprehensive

Shareholders’

Noncontrolling

    

Shares

    

Amount

    

Earnings

    

Loss

    

Equity

    

Interests

Balance, December 31, 2019

 

148,888

$

1,318,961

$

445,370

$

(64,740)

$

1,699,591

 

$

3,455

Net loss

 

 

 

(11,938)

 

 

(11,938)

 

(1,990)

Credit losses recognized in retained earnings upon adoption of ASU No. 2016-13

 

 

 

(620)

 

 

(620)

 

Foreign currency translation adjustments

 

 

 

 

(33,587)

 

(33,587)

 

(228)

Unrealized gain on hedges, net of tax

 

 

 

 

265

 

265

 

Accretion of redeemable noncontrolling interests

 

 

 

(2,086)

 

 

(2,086)

 

2,086

Activity in company stock plans, net and other

 

1,074

 

(4,730)

 

 

 

(4,730)

 

Share-based compensation

 

 

2,170

 

 

 

2,170

 

Balance, March 31, 2020

 

149,962

$

1,316,401

$

430,726

$

(98,062)

$

1,649,065

 

$

3,323

The accompanying notes are an integral part of these condensed consolidated financial statements.


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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)

 Nine Months Ended
September 30,
 2017 2016
Cash flows from operating activities:   
Net loss$(20,528) $(27,032)
Adjustments to reconcile net loss to net cash provided by operating activities:   
Depreciation and amortization82,670
 84,846
Amortization of debt discount3,487
 4,655
Amortization of debt issuance costs5,238
 6,430
Share-based compensation7,613
 4,351
Deferred income taxes(3,019) (6,726)
Equity in losses of investment457
 366
Loss on disposition of assets, net39
 
(Gain) loss on early extinguishment of long-term debt397
 (546)
Unrealized gain and ineffectiveness on derivative contracts, net(4,291) (9,282)
Changes in operating assets and liabilities:   
Accounts receivable, net(21,709) (27,346)
Other current assets(12,145) (10,853)
Income tax receivable2,742
 20,576
Accounts payable and accrued liabilities30,675
 (1,794)
Other non-current, net(40,303) (22,201)
Net cash provided by operating activities31,323
 15,444
    
Cash flows from investing activities:   
Capital expenditures(131,428) (79,353)
Distribution from equity investment
 1,200
Proceeds from sale of equity investment
 25,000
Proceeds from sale of assets10,000
 10,887
Net cash used in investing activities(121,428) (42,266)
    
Cash flows from financing activities:   
Proceeds from term loan100,000
 
Repayment of term loan(193,508) (30,500)
Repayment of Nordea Q5000 Loan(26,786) (26,786)
Repayment of MARAD Debt(6,222) (5,926)
Repurchase of Convertible Senior Notes due 2032
 (13,400)
Debt issuance costs(3,694) (1,230)
Net proceeds from issuance of common stock219,504
 94,538
Payments related to tax withholding for share-based compensation(1,306) (187)
Proceeds from issuance of ESPP shares432
 708
Net cash provided by financing activities88,420
 17,217
    
Effect of exchange rate changes on cash and cash equivalents1,927
 (2,481)
Net increase (decrease) in cash and cash equivalents242
 (12,086)
Cash and cash equivalents:   
Balance, beginning of year356,647
 494,192
Balance, end of period$356,889
 $482,106

Three Months Ended

March 31, 

    

2021

    

2020

Cash flows from operating activities:

 

  

  

Net loss

$

(3,050)

$

(13,928)

Adjustments to reconcile net loss to net cash provided by operating activities:

 

 

  

Depreciation and amortization

 

34,566

 

31,598

Goodwill impairment

 

 

6,689

Amortization of debt discounts

 

 

1,633

Amortization of debt issuance costs

 

810

 

833

Share-based compensation

 

1,904

 

2,259

Deferred income taxes

 

(892)

 

(6,517)

Unrealized gain on derivative contracts, net

 

 

(601)

Unrealized foreign currency (gain) loss

 

(951)

 

9,237

Changes in operating assets and liabilities:

 

  

 

  

Accounts receivable, net

 

(463)

 

(25,375)

Income tax receivable

 

6,256

 

(17,033)

Other current assets

 

9,361

 

(5,475)

Accounts payable and accrued liabilities

 

(4,881)

 

15,563

Other, net

 

(2,791)

 

(16,105)

Net cash provided by (used in) operating activities

 

39,869

 

(17,222)

Cash flows from investing activities:

 

  

 

  

Capital expenditures

 

(1,329)

 

(12,389)

Net cash used in investing activities

 

(1,329)

 

(12,389)

Cash flows from financing activities:

 

  

 

  

Repayment of Term Loan

 

(875)

 

(875)

Repayment of Nordea Q5000 Loan

 

(53,572)

 

(8,929)

Repayment of MARAD Debt

 

(3,734)

 

(3,556)

Debt issuance costs

 

(43)

 

(212)

Payments related to tax withholding for share-based compensation

 

(1,878)

 

(5,150)

Proceeds from issuance of ESPP shares

 

217

 

331

Net cash used in financing activities

 

(59,885)

 

(18,391)

Effect of exchange rate changes on cash and cash equivalents and restricted cash

 

406

 

(2,834)

Net decrease in cash and cash equivalents and restricted cash

 

(20,939)

 

(50,836)

Cash and cash equivalents and restricted cash:

 

  

 

  

Balance, beginning of year

 

291,320

 

262,561

Balance, end of period

$

270,381

$

211,725

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”). 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 (“U.S. GAAP”).

The accompanying condensed consolidated financial statements have been prepared in conformity with GAAP in U.S. GAAPdollars and are consistent in all material respects with those applied in our 20162020 Annual Report on Form 10-K (“2016(our “2020 Form 10-K”) with the exception of the impact of early adopting Accounting Standards Update (“ASU”) No. 2020-06 on a modified retrospective basis beginning January 1, 2021 (see below). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments, (which werewhich, unless otherwise disclosed, are of normal recurring adjustments)nature, that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive income (loss), and statements of cash flows, as applicable. The operating results for the three- and nine-month periodsthree-month period ended September 30, 2017March 31, 2021 are not necessarily indicative of the results that may be expected for the year ending December 31, 2017.2021. Our balance sheet as of December 31, 20162020 included herein has been derived from the audited balance sheet as of December 31, 20162020 included in our 20162020 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the audited annual audited consolidated financial statements and notes thereto included in our 20162020 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

In May 2014,August 2020, the Financial Accounting Standards Board (the “FASB”)FASB issued Accounting Standards Update (“ASU”)ASU No. 2014-09, “Revenue from2020-06, “Accounting for Convertible Instruments and Contracts with Customers (Topic 606).” This ASU provides a five-step approach to account for revenue arising from contracts with customers. The ASU requires an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflectsEntity's Own Equity,” which simplifies the consideration to which the entity expects to be entitled in exchange for those goods or services. This revenue standard was originally effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods, and was subsequently deferred by one year to annual reporting periods beginning after December 15, 2017. The FASB also issued several subsequent updates containing implementation guidance on principal versus agent considerations (gross versus net revenue presentation), identifying performance obligations and accounting for licensescertain financial instruments with characteristics of intellectual property.liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Among other changes, this ASU removes from GAAP the requirement to separate certain convertible instruments, such as our Convertible Senior Notes Due 2022, Convertible Senior Notes Due 2023 and Convertible Senior Notes Due 2026 (Note 5), into liability and equity components. Consequently, those convertible instruments will be accounted for in their entirety as liabilities measured at their amortized cost. We elected to early adopt ASU No. 2020-06 on a modified retrospective basis beginning January 1, 2021. The adoption of this ASU increased our long-term debt and decreased our common stock by $44.1 million and $41.5 million, respectively, as we reclassified the conversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of this ASU also increased our retained earnings and decreased deferred tax liabilities by $6.7 million and $9.3 million, respectively. Subsequent to its adoption, the ASU is also expected to reduce our interest expense as there will no longer be debt discounts to amortize associated with our outstanding convertible senior notes. Additionally, these updates provide narrow-scope improvementsthe ASU no longer permits the treasury stock method for convertible instruments and practical expedients as well as technical corrections and improvementsinstead requires the application of the if-converted method to calculate the guidance. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the yearimpact of adoption through a cumulative adjustment. Our assessment at this stage is that weour convertible senior notes on diluted earnings per share (“EPS”).

We do not expect the new revenue standardany other recently issued accounting standards to have a material impact on our consolidated financial statements upon adoption. We continue working on expanded disclosure requirements and documentationposition, results of new policies, procedures and controls. We currently intend on adopting this guidance using the modified retrospective method.operations or cash flows when they become effective.

8

In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes.” This ASU requires companies to classify all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. The requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount was not affected by this guidance. We adopted this guidance prospectively in the first quarter of 2017. Prior periods were not retrospectively adjusted.

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In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU amends the existing accounting standards for leases. The amendments are intended to increase transparency and comparability among organizations by requiring recognition of lease assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. The guidance is required to be adopted at the earliest period presented using a modified retrospective approach. We expect to adopt this guidance in the first quarter of 2019. We are currently evaluating the impact these amendments will have on our consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification in the statement of cash flows. Our share-based awards typically vest in the beginning of each year. The adoption of this guidance had no material impact on our consolidated financial statements for the three- and nine-month periods ended September 30, 2017.
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments.” 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 is effective for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
In October 2016, the FASB issued ASU No. 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” This ASU eliminates the exception in current guidance that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. Under the new ASU, an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
In May 2017, the FASB issued ASU No. 2017-09, “Scope of Modification Accounting.” This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require application of modification accounting. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We do not expect this ASU to have a material impact on our consolidated financial statements.
In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU improves the financial reporting of hedging relationships to better align risk management activities in financial statements and makes certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

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 provideTraditionally, our services and methodologies thathave covered the lifecycle of an offshore oil or gas field. In recent years, we believe are critical to maximizing production economics.have seen an increasing demand for our services from the offshore renewable energy market. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions,regions. Our North Sea operations are subject to seasonal changes in demand, which generally peaks in the summer months and have expanded our operations into Brazil withdeclines in the commencement of operations of the Siem Helix 1 in mid-April 2017.winter months. Our “life of field” services are segregated into three3 reportable business segments: Well Intervention, Robotics and Production Facilities (Note 11)10).


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Our Well Intervention segment includesprovides services enabling our vessels and equipment usedcustomers to performsafely access offshore wells for the purpose of performing well enhancement or decommissioning operations. Our well intervention services primarily invessels include the U.S. Gulf of Mexico, North SeaQ4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and Brazil.2 chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. Our Well Intervention segment alsowell intervention equipment includes intervention riser systems (“IRSs”), some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”). and the Riserless Open-water Abandonment Module (“ROAM”), some of which we provide on a stand-alone basis.

Our Robotics segment provides offshore construction, cable trenching, seabed clearance, inspection, repair and maintenance services to both the oil and gas and the renewable energy markets globally. Our Robotics services also complement well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer and two chartered vessels, the Siem Helix 1 which is used and the Siem Helix 2 which is to be used in connection with our contracts to provide well intervention services offshore Brazil. We also have a semi-submersible well intervention vessel under construction, the Q7000.

services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore constructiona ROVDrill, and well intervention services, and currently operates four chartered ROV2 robotics support vessels includingunder long-term charter, the Grand Canyon II and the Grand Canyon III that went into service for us in May 2017.
, as well as spot vessels as needed.

Our Production Facilities segment includes the Helix ProducerI (the HP I”I), a ship-shaped dynamic positioningdynamically positioned floating production vessel, and the Helix Fast Response System (the “HFRS”), which provides certain operators access to and our Q4000ownership of oil and HP I vessels in the eventgas properties. All of a well control incidentour current Production Facilities activities are located in the Gulf of Mexico. The HP I has been under contract since February 2013 to process production from the Phoenix field for the field operator. We currently operate under a fixed fee agreement for the HP I for service to the Phoenix field until at least June 1, 2023. We are party to an agreement providing various operators with access to the HFRS for well control purposes, which agreement was amended effective February 1, 2017 to reduce the retainer fee and to extend the term of the agreement by one year to March 31, 2019. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) and previously included our former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) that we sold in February 2016 (Note 5).

Note 3 — Details of Certain Accounts

Other current assets consist of the following (in thousands):

 September 30,
2017
 December 31,
2016
    
Note receivable (1)
$
 $10,000
Prepaid insurance2,432
 4,426
Other prepaids10,021
 9,547
Deferred costs (2)
20,704
 7,971
Spare parts inventory1,598
 2,548
Income tax receivable
 880
Value added tax receivable2,169
 1,345
Other1,248
 671
Total other current assets$38,172
 $37,388
(1)Relates to the balance of the promissory note we received in connection with the sale of our former Ingleside spoolbase in January 2014. Interest on the note was payable quarterly at a rate of 6% per annum. In June 2017, we collected the remaining $10 million principal balance of this note receivable as well as accrued interest.
(2)Primarily reflects deferred mobilization costs associated with certain long-term contracts, which are to be amortized within 12 months from the balance sheet date.

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March 31, 

December 31, 

    

2021

    

2020

Contract assets (Note 7)

$

360

 

$

2,446

Prepaids

 

15,289

 

15,904

Deferred costs (Note 7)

 

18,717

 

23,522

Income tax receivable

 

13,847

 

20,787

Other receivable (Note 11)

 

30,052

 

29,782

Other

 

7,977

 

9,651

Total other current assets

$

86,242

 

$

102,092

Other assets, net consist of the following (in thousands):

March 31, 

December 31, 

    

2021

    

2020

Deferred recertification and dry dock costs, net

$

19,073

 

$

21,464

Deferred costs (Note 7)

 

916

 

861

Charter deposit (1)

 

12,544

 

12,544

Intangible assets with finite lives, net

 

3,756

 

3,809

Other

 

1,221

 

1,335

Total other assets, net

$

37,510

 

$

40,013

 September 30,
2017
 December 31,
2016
    
Note receivable, net (1)
$3,129
 $2,827
Prepaids8,112
 6,418
Deferred dry dock costs, net14,260
 14,766
Deferred costs (2)
57,934
 30,738
Deferred financing costs, net (3)
2,814
 3,745
Charter fee deposit (4)
12,544
 12,544
Other2,181
 1,511
Total other assets, net$100,974
 $72,549
(1)In 2016, we entered into an agreementThis amount is deposited with onethe owner of our customersthe Siem Helix2 to defer theiroffset certain payment obligations until June 30, 2018. On March 30, 2017, we entered into a new agreementassociated with this customer in which we agreed to forgive all but $4.3 million of our outstanding receivables due from the customer in exchange for redeemable convertible bonds that approximated that amount. The bonds are redeemable by the customervessel at any time and the maturity date of the bonds is December 14, 2019. Interest at a rate of 5% per annum is payable on the bonds annually. We received the redeemable convertible bonds in September 2017 when all aspects of the agreement were finalized. The amount at September 30, 2017 reflected the fair value of the notes as of that date. The amount at December 31, 2016 was net of allowance of $4.2 million.
(2)Primarily reflects deferred mobilization costs to be amortized after 12 months from the balance sheet date through the end of the applicable term of certain long-term contracts.
(3)Represents unamortized debt issuance costs related to our revolving credit facility (Note 6).
(4)
This amount deposited with the vessel owner is to be used to reduce our final charter payments for the Siem Helix2.
term.

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Accrued liabilities consist of the following (in thousands):

 September 30,
2017
 December 31,
2016
   ��
Accrued payroll and related benefits$29,682
 $20,705
Deferred revenue8,664
 8,911
Accrued interest2,997
 3,758
Derivative liability (Note 14)9,927
 18,730
Taxes payable excluding income tax payable1,209
 1,214
Other8,282
 5,296
Total accrued liabilities$60,761
 $58,614

11



March 31, 

December 31, 

    

2021

    

2020

Accrued payroll and related benefits

$

20,327

 

$

24,768

Accrued interest

3,010

7,098

Deferred revenue (Note 7)

 

9,614

 

8,140

Asset retirement obligations (Note 11)

 

30,961

 

30,913

Other

 

12,574

 

16,116

Total accrued liabilities

$

76,486

 

$

87,035

Other non-current liabilities consist of the following (in thousands):

 September 30,
2017
 December 31,
2016
    
Investee losses in excess of investment (Note 5)$8,845
 $10,238
Deferred gain on sale of property (1)
5,910
 5,761
Deferred revenue8,827
 8,598
Derivative liability (Note 14)9,663
 20,191
Other9,491
 8,197
Total other non-current liabilities$42,736
 $52,985
(1)Relates to the sale and lease-back in January 2016 of our office and warehouse property located in Aberdeen, Scotland. The deferred gain is amortized over a 15-year minimum lease term.

March 31, 

December 31, 

    

2021

    

2020

Deferred revenue (Note 7)

$

1,333

 

$

1,869

Other

 

1,772

 

2,009

Total other non-current liabilities

$

3,105

 

$

3,878

Note 4 — StatementLeases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. We also sublease some 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. our facilities under non-cancelable sublease agreements.

The following table provides supplemental cash flow informationdetails the components of our lease cost (in thousands):

 Nine Months Ended
September 30,
 2017 2016
    
Interest paid, net of interest capitalized$9,002
 $17,970
Income taxes paid$3,967
 $4,674
Our non-cash investing activities include property and equipment capital expenditures that are incurred but not yet paid. These non-cash capital expenditures totaled $21.7 million

Three Months Ended

March 31, 

    

2021

    

2020

Operating lease cost

$

16,216

 

$

16,323

Variable lease cost

 

3,484

 

3,212

Short-term lease cost

 

1,732

 

7,174

Sublease income

 

(349)

 

(279)

Net lease cost

$

21,083

 

$

26,430

Maturities of our operating lease liabilities as of September 30, 2017 and $10.1 millionMarch 31, 2021 are as follows (in thousands):

    

    

Facilities and

    

    

Vessels

    

Equipment

    

Total

Less than one year

$

52,620

$

5,825

 

$

58,445

One to two years

 

52,105

 

5,249

 

57,354

Two to three years

 

24,203

 

4,637

 

28,840

Three to four years

 

 

4,205

 

4,205

Four to five years

 

 

1,591

 

1,591

Over five years

 

0

 

3,884

 

3,884

Total lease payments

$

128,928

$

25,391

 

$

154,319

Less: imputed interest

 

(11,088)

 

(4,334)

 

(15,422)

Total operating lease liabilities

$

117,840

$

21,057

 

$

138,897

Current operating lease liabilities

$

45,598

$

4,723

 

$

50,321

Non-current operating lease liabilities

 

72,242

 

16,334

 

88,576

Total operating lease liabilities

$

117,840

$

21,057

 

$

138,897

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Maturities of our operating lease liabilities as of December 31, 2016.

2020 are as follows (in thousands):

    

    

Facilities and

    

    

Vessels

    

Equipment

    

Total

Less than one year

$

54,621

$

6,028

 

$

60,649

One to two years

 

52,106

 

5,435

 

57,541

Two to three years

 

34,580

 

4,649

 

39,229

Three to four years

 

2,470

 

4,374

 

6,844

Four to five years

 

 

2,340

 

2,340

Over five years

 

 

4,054

 

4,054

Total lease payments

$

143,777

$

26,880

 

$

170,657

Less: imputed interest

 

(13,352)

 

(4,697)

 

(18,049)

Total operating lease liabilities

$

130,425

$

22,183

 

$

152,608

Current operating lease liabilities

$

46,748

$

4,851

 

$

51,599

Non-current operating lease liabilities

 

83,677

 

17,332

 

101,009

Total operating lease liabilities

$

130,425

$

22,183

 

$

152,608

The following table presents the weighted average remaining lease term and discount rate:

March 31, 

December 31, 

    

2021

2020

Weighted average remaining lease term

 

3.0

years

3.1

years

Weighted average discount rate

 

7.53

%  

7.53

%

The following table presents other information related to our operating leases (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Cash paid for operating lease liabilities

$

16,502

 

$

16,472

ROU assets obtained in exchange for new operating lease obligations

 

113

 

Note 5 — Equity Investments

We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. We previously had a 50% ownership interest in Deepwater Gateway, which we sold in February 2016 to a subsidiary of Genesis Energy, L.P., the other 50% owner, for $25 million with no resulting gain or loss. We also received a cash distribution of $1.2 million from Deepwater Gateway in February 2016. These equity investments are included in our Production Facilities segment.
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. Our share of the losses reported by Independence Hub exceeded the carrying amount of our investment by $8.8 million as of September 30, 2017 and $10.2 million at December 31, 2016 reflecting our share of Independence Hub’s obligations (primarily its estimated asset retirement obligations to decommission the platform), net of remaining working capital. This liability is reflected in “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

12



Note 6 —Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of September 30, 2017March 31, 2021 are as follows (in thousands):

Term

2022

2023

2026

MARAD

 

    

Loan

    

Notes

    

Notes

    

Notes

    

Debt

    

Total

Less than one year

$

28,875

$

$

$

$

7,746

 

$

36,621

One to two years

 

 

35,000

 

 

 

8,133

 

43,133

Two to three years

 

 

 

30,000

 

 

8,539

 

38,539

Three to four years

 

 

 

 

 

8,965

 

8,965

Four to five years

 

 

 

 

200,000

 

9,412

 

209,412

Over five years

 

 

 

 

 

9,881

 

9,881

Gross debt

 

28,875

 

35,000

 

30,000

 

200,000

 

52,676

 

346,551

Unamortized debt issuance costs (1)

 

(143)

 

(206)

 

(445)

 

(6,792)

 

(2,927)

 

(10,513)

Total debt

 

28,732

 

34,794

 

29,555

 

193,208

 

49,749

 

336,038

Less current maturities

 

(28,732)

 

 

 

 

(7,746)

 

(36,478)

Long-term debt

$

$

34,794

$

29,555

$

193,208

$

42,003

 

$

299,560

 
Term
Loan (1)
 
2022
Notes
 
2032
Notes (2)
 
MARAD
Debt
 
Nordea
Q5000
Loan
 Total
            
Less than one year$6,250
 $
 $60,115
 $6,532
 $35,714
 $108,611
One to two years11,250
 
 
 6,858
 35,714
 53,822
Two to three years81,250
 
 
 7,200
 98,215
 186,665
Three to four years
 
 
 7,560
 
 7,560
Four to five years
 125,000
 
 7,937
 
 132,937
Over five years
 
 
 40,913
 
 40,913
Total debt98,750
 125,000
 60,115
 77,000
 169,643
 530,508
Current maturities(6,250) 
 (60,115) (6,532) (35,714) (108,611)
Long-term debt, less current maturities92,500
 125,000
 
 70,468
 133,929
 421,897
Unamortized debt discount (3)

 (14,555) (1,052) 
 
 (15,607)
Unamortized debt issuance costs (4)
(1,815) (2,427) (92) (4,635) (1,976) (10,945)
Long-term debt$90,685
 $108,018
 $(1,144) $65,833
 $131,953
 $395,345
(1)Term Loan borrowing pursuant to the Credit Agreement (amended and restated in June 2017) matures in June 2020.
(2)The holders of our remaining Convertible Senior Notes due 2032 may require us to repurchase the notes in March 2018. Accordingly, these notes are classified as current liabilities.
(3)Our Convertible Senior Notes due 2022 will increase to their face amount through accretion of non-cash interest charges through May 2022. Our Convertible Senior Notes due 2032 will increase to their face amount through accretion of non-cash interest charges through March 2018.
(4)Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement. See Note 1 for accounting changes as a result of the adoption of ASU No. 2020-06.

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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

We have a credit agreement (and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). The amended and restated credit facilityCredit Agreement is comprised of a $100Term Loan with a remaining balance of $28.9 million term loan (the “Term Loan”)as of March 31, 2021 and a revolving credit facility (the “RevolvingRevolving Credit Facility”)Facility with a maximum availability of up to $150 million (the “Revolving Loans”).$175 million. The Credit Agreement expires and the Term Loan matures on December 31, 2021. The Revolving Credit Facility permits the Companyus 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. The $100 million proceeds from the Term Loan as well as cash on hand were used to repay the approximately $180 million term loan then outstanding under the credit facility prior to its June 2017 amendment and restatement. At September 30, 2017,Facility. As of March 31, 2021, we had no0 borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the applicable leverage ratio covenant,ratios, totaled $69.9$172.2 million, net of $4.0$2.8 million of letters of credit issued under that facility.


13



The Term Loan and

Borrowings under the Revolving Loans (together, the “Loans”),Credit Agreement bear interest, at our election, bear interestat either in relation to Bank of America’s base rate, the LIBOR or to a LIBOR rate.comparable successor rate, or a combination thereof. The Term Loan or portions thereof bearing interest at the base rate will bear interest at a per annum rate equal to theBank of America’s base rate plus 3.25%a margin of 2.25%. The Term Loan or portions thereof 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 3.36% as of March 31, 2021. Borrowings under the Revolving Loans or portions thereofCredit Facility bearing interest at the base rate will bear interest at a per annum rate equal to theBank of America’s base rate plus a margin ranging from 1.75%1.50% to 3.25%2.50%. TheBorrowings under the Revolving Loans or portions thereofCredit 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 itsthe 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 ratioConsolidated 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.

The Term Loan principal is required to be repaid in quarterly installments of 5% in the first loan year, 10% in the second loan year and 15% in the third loan year,2.5% of its aggregate principal amount, with a balloon payment at maturity. Installment amountsInstallments are subject to adjustment for any prepayments on the Term Loan.prepayments. We may elect to prepay amountsindebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amountsindebtedness outstanding under the Revolving Credit Facility without premium or penalty, and may reborrow any amounts prepaid up to the amount ofavailable under the Revolving Credit Facility. The Loans mature on June 30, 2020.

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 and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I – Title XI, Inc.) and of Helix Robotics Solutions Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries (restricted subsidiaries).

The Credit Agreement and the other documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, whichthat we consider customary for this type of 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 financial ratio requirements of EBITDA to interest charges (“Consolidated(Consolidated Interest Coverage Ratio”) andRatio), funded debt to EBITDA (“Consolidated(Consolidated Total Leverage Ratio”),Ratio) and provided that if there are no Loans outstanding, thesecured funded debt ratio requirement permits us to offset a certain amount of cash against the funded debt used in the calculation (“Consolidated Net Leverage Ratio”). After the initial 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 are also required to ensure that the ratio of our total secured indebtedness to EBITDA (“Consolidated(Consolidated Secured Leverage Ratio”) does not exceed the maximum permitted ratio. The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness outstanding. These financial covenant requirements are detailed as follows:

(a)The minimum required Consolidated Interest Coverage Ratio:
Four Fiscal Quarters Ending
Minimum Consolidated
Interest Coverage Ratio
September 30, 2017 and each fiscal quarter thereafter2.50
to 1.00
(b)The maximum permitted Consolidated Total Leverage Ratio or Consolidated Net Leverage Ratio:
Four Fiscal Quarters Ending
Maximum Consolidated
Total or Net Leverage Ratio
September 30, 20176.00
to 1.00
December 31, 20175.75
to 1.00
March 31, 20185.50
to 1.00
June 30, 20185.25
to 1.00
September 30, 20185.00
to 1.00
December 31, 2018 through and including March 31, 20194.50
to 1.00
June 30, 2019 through and including September 30, 20194.25
to 1.00
December 31, 20194.00
to 1.00
March 31, 2020 and each fiscal quarter thereafter3.50
to 1.00


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(c)The maximum permitted Consolidated Secured Leverage Ratio:
Four Fiscal Quarters Ending
Maximum Consolidated
Secured Leverage Ratio
September 30, 2017 through and including June 30, 20183.00
to 1.00
September 30, 2018 and each fiscal quarter thereafter2.50
to 1.00
(d)The minimum required Unrestricted Cash and Cash Equivalents:
Consolidated Total Leverage Ratio
Minimum Cash (1)
Greater than or equal to 4.00 to 1.00$100,000,000.00
Greater than or equal to 3.50 to 1.00 but less than 4.00 to 1.00$50,000,000.00
Less than 3.50 to 1.00$0.00
(1)This minimum cash balance is not required to be maintained in any particular bank account or to be segregated from other cash balances in bank accounts that we use in our ordinary course of business. Because the use of this cash is not legally restricted notwithstanding this maintenance covenant, we present it on our balance sheet as cash and cash equivalents. As of September 30, 2017, we were required to, and did, maintain an aggregate cash balance of at least $100 million in complying with this covenant.
Ratio).

We may from time to time designate one or more of our new foreign subsidiaries as subsidiaries which are not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided that we meet certain liquidity requirements.. The Unrestricted Subsidiaries are not pledged as collateral under the Credit Agreement, and the debt and EBITDA of the Unrestricted Subsidiaries, with the exception of Helix Q5000 Holdings, S.à r.l., a wholly owned Luxembourg subsidiary of Helix Vessel Finance S.à r.l., 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 Canyon Offshore Limited, a wholly owned Scottish subsidiary, and our obligations under the Credit Agreement and of such guarantors under their guarantee are secured by most of our assets of the parent, our domestic subsidiaries (other than Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, as well as pledges of up to two-thirds of the shares of certain foreign subsidiaries.

In June 2017, we recognized a $0.4 million loss to write off the unamortized debt issuance costs related to the lenders exiting from the term loan then outstanding under the credit facility priorextent of any cash actually distributed by such subsidiary to its June 2017 amendment and restatement, which loss is presented as “Loss on early extinguishmentHelix.

12

Table of long-term debt” in the accompanying consolidated statements of operations. In connection with decreases in lenders’ commitments under our revolving credit facility, in June 2017 and February 2016 we recorded interest charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments were reduced.Contents

Convertible Senior Notes Due 2022

On November 1, 2016, we completed a public offering and sale of our Convertible Senior Notes due (“2022 (the “2022 Notes”) in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2022 Notes were $121.7 million after deducting the underwriter’s discounts and commissions and offering expenses. We used net proceeds from the issuance of the 2022 Notes as well as cash on hand to repurchase and retire $125 million in principal of the 2032 Notes (see “Convertible Senior Notes Due 2032” below) in separate, privately negotiated transactions.

15



The 2022 Notes bear interest at a coupon interest 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.until maturity. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions (as described in the Indenture governing the 2022 Notes) therepurchased by us. The 2022 Notes are convertible by thetheir holders into shares of our common stockat any time beginning February 1, 2022 at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal amount, (whichwhich currently represents 2,519,118 potentially convertible shares at an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2022 Notes. Westock. Upon conversion, we have the right to satisfy our conversion obligation by delivering cash, shares of our common stock or any combination thereof.

Prior to February 1, 2022, holders of the 2022 Notes may convert their notes if the closing price of our common stock exceeds 130% of the conversion price for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter (share price condition) or if the trading price of the 2022 Notes was equal to or less than 97% of the conversion value of the notes during the 5 consecutive business days immediately after any 10 consecutive trading day period (trading price condition). Holders of the 2022 Notes may also convert their notes if we make certain distributions on shares of our common stock or engage in certain corporate transactions, in which case the holders may be entitled to an increase in the conversion rate, depending on the price of our common shares and the intentiontime remaining to settle any such future conversions in cash.

maturity, of up to 30.5887 shares of our common stock per $1,000 principal amount.

Prior to November 1, 2019, the 2022 Notes arewere not redeemable. On or after November 1, 2019, we may redeem all or any portion of the 2022 Notes if the price of our common stock has been at least 130% of the conversion price for at least 20 trading days during any 30 consecutive trading day period preceding our option, subjectredemption notice. Any redemption would be payable in cash equal to 100% of the principal amount plus accrued and unpaid interest and a “make-whole premium” calculated as the present value of all remaining scheduled interest payments. Holders of the 2022 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2022 Notes may also require us to repurchase the notes following a “fundamental change,” which includes a change of control or a termination of trading of our common stock (as defined in the indenture governing the 2022 Notes).

The indenture governing the 2022 Notes contains customary terms and covenants, including that upon certain conditions,events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a subsidiary, the principal amount of the 2022 Notes together with any accrued interest will become immediately due and payable.

The 2022 Notes were initially separated between the equity component recognized in shareholders’ equity and the debt component, which was presented as long-term debt, net of the unamortized debt discount and debt issuance costs. Those unamortized debt discount and debt issuance costs were accreted to interest expense through the maturity date of the 2022 Notes. As of December 31, 2020, unamortized debt discount and debt issuance costs related to the 2022 Notes totaled $1.5 million. As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the 2022 Notes (Note 1). As of March 31, 2021, unamortized debt issuance costs related to the 2022 Notes were $0.2 million.

The effective interest rate for the 2022 Notes prior to the adoption of ASU No. 2020-06 was 7.3%. The effective interest rate subsequent to the adoption of ASU No. 2020-06 decreased to 4.8%. For the three-month period ended March 31, 2021, total interest expense related to the 2022 Notes was $0.4 million primarily from coupon interest expense. For the three-month period ended March 31, 2020, total interest expense related to the 2022 Notes was $2.3 million, with coupon interest expense of $1.4 million and the amortization of debt discount and issuance costs of $0.9 million.

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Table of Contents

Convertible Senior Notes Due 2023 (“2023 Notes”)

The 2023 Notes bear interest at a coupon interest rate of 4.125% per annum payable semi-annually in arrears on March 15 and September 15 of each year until maturity. The 2023 Notes mature on September 15, 2023 unless earlier converted, redeemed or repurchased by us. The 2023 Notes are convertible by their holders at any time beginning March 15, 2023 at an initial conversion rate of 105.6133 shares of our common stock per $1,000 principal amount, which currently represents 3,168,399 potentially convertible shares at an initial conversion price of approximately $9.47 per share of common stock. Upon conversion, we have the right to satisfy our conversion obligation by delivering cash, shares of our common stock or any combination thereof.

Prior to March 15, 2023, holders of the 2023 Notes may convert their notes if the closing price of our common stock exceeds 130% of the conversion price for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter (share price condition) or if the trading price of the 2023 Notes was equal to or less than 97% of the conversion value of the notes during the 5 consecutive business days immediately after any 10 consecutive trading day period (trading price condition). Holders of the 2023 Notes may also convert their notes if we make certain distributions on shares of our common stock or engage in certain corporate transactions, in which case the holders may be entitled to an increase in the conversion rate, depending on the price of our common shares and the time remaining to maturity, of up to 47.5260 shares of our common stock per $1,000 principal amount.

Prior to March 15, 2021, the 2023 Notes were not redeemable. On or after March 15, 2021, we may redeem all or any portion of the 2023 Notes if the price of our common stock has been at least 130% of the conversion price for at least 20 trading days during any 30 consecutive trading day period preceding our redemption pricenotice. Any redemption would be payable in cash equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest and a “make-whole premium” with a value equal tocalculated as the present value of theall remaining scheduled interest payments of the 2022 Notes to be redeemed through May 1, 2022.payments. Holders of the 20222023 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2023 Notes may also require us to repurchase the notes following a “fundamental change,” aswhich includes a change of control or a termination of trading of our common stock (as defined in the 2022 Notes documentation.

The Indentureindenture governing the 20222023 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 2022 Notes may declare the entire principal amount of alland any accrued interest on the notes and the interest accrued on such notes, if any, tomay be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a principalsignificant subsidiary, the principal amount of the 20222023 Notes together with any accrued and unpaid interest thereon will automatically be and become immediately due and payable.

In connection

The 2023 Notes were initially separated between the equity component recognized in shareholders’ equity and the debt component, which was presented as long-term debt, net of the unamortized debt discount and debt issuance costs. Those unamortized debt discount and debt issuance costs were accreted to interest expense through the maturity date of the 2023 Notes. As of December 31, 2020, unamortized debt discount and debt issuance costs related to the 2023 Notes totaled $3.1 million. As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the 2023 Notes (Note 1). As of March 31, 2021, unamortized debt issuance ofcosts related to the 20222023 Notes we recorded a debt discount of $16.9 million as required under existing accounting rules. To arrive at this discount amount, we estimated the fair value of the liability component of the 2022 Notes as of October 26, 2016 using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of pricing and an expected life of 5.5 years. were $0.4 million.

The effective interest rate for the 20222023 Notes is 7.3% after consideringprior to the effectadoption of ASU No. 2020-06 was 7.8%. The effective interest rate subsequent to the accretionadoption of ASU No. 2020-06 decreased to 4.8%. For the related debt discount that represented the equity component of the 2022 Notes at their inception. We recorded $11.0 million, net of tax,three-month period ended March 31, 2021, total interest expense related to the carrying amount2023 Notes was $0.4 million, with coupon interest expense of $0.3 million and the equity componentamortization of issuance costs of $0.1 million. For the 2022 Notes. The remaining unamortized amountthree-month period ended March 31, 2020, total interest expense related to the 2023 Notes was $2.3 million, with coupon interest expense of $1.3 million and the amortization of debt discount and issuance costs of the 2022 Notes was $14.6 million at September 30, 2017 and $16.5 million at December 31, 2016.$1.0 million.

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Convertible Senior Notes Due 2032 

In March 2012, we completed a public offering and sale of our Convertible Senior Notes due 2032 (the “20322026 (“2026 Notes”) in the aggregate principal amount of $200 million, $60 million of which are currently outstanding.

The 20322026 Notes bear interest at a coupon interest rate of 3.25%6.75% per annum and are payable semi-annually in arrears on MarchFebruary 15 and SeptemberAugust 15 of each year, beginning on SeptemberFebruary 15, 2012.2021 until maturity. The 20322026 Notes mature on MarchFebruary 15, 20322026 unless earlier converted, redeemed or repurchased.repurchased by us. The 20322026 Notes are convertible in certain circumstances and during certain periodsby their holders at any time beginning November 17, 2025 at an initial conversion rate of 39.9752143.3795 shares of our common stock per $1,000 principal amount, (whichwhich currently represents 28,675,900 potentially convertible shares at an initial conversion price of approximately $25.02$6.97 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes. Westock. Upon conversion, we have the right to satisfy our conversion obligation by delivering cash, shares of our common stock or any combination thereof.

Prior to November 17, 2025, holders of the 2026 Notes may convert their notes if the closing price of our common stock exceeds 130% of the conversion price for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter (share price condition) or if the trading price of the 2026 Notes was equal to or less than 97% of the conversion value of the notes during the 5 consecutive business days immediately after any 10 consecutive trading day period (trading price condition). Holders of the 2026 Notes may also convert their notes if we make certain distributions on shares of our common stock or engage in certain corporate transactions, in which case the holders may be entitled to an increase in the conversion rate, depending on the price of our common shares and the intentiontime remaining to settle any such future conversions in cash.


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up to 64.5207 shares of our common stock per $1,000 principal amount.

Prior to March 20, 2018,August 15, 2023, the 20322026 Notes are not redeemable. On or after March 20, 2018,August 15, 2023, we at our option, may redeem someall or allany portion of the 20322026 Notes in cash, at any time uponif the price of our common stock has been at least 130% of the conversion price for at least 20 trading days during any 30 days’ notice, at a priceconsecutive trading day period preceding our redemption notice. Any redemption would be payable in cash equal to 100% of the principal amount plus accrued and unpaid interest (including contingentand a “make-whole premium” calculated as the present value of all remaining scheduled interest if any) up to but excluding the redemption date. In addition, the holderspayments. Holders of the 20322026 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2026 Notes may also require us to purchaserepurchase the notes following a “fundamental change,” which includes a change of control or a termination of trading of our common stock (as defined in cash somethe indenture governing the 2026 Notes).

The indenture governing the 2026 Notes contains customary terms and covenants, including that upon certain events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or all of their 2032 Notes atreorganization relating to us or a repurchase price equal to 100% ofsignificant subsidiary, the principal amount of the 20322026 Notes plustogether with any accrued interest will become immediately due and unpaid interest (including contingent interest, if any) up to but excludingpayable.

The 2026 Notes were initially separated between the applicable repurchase date, on March 15, 2018, March 15, 2022equity component recognized in shareholders’ equity and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a Fundamental Change (either a Change of Control or a Termination of Trading,debt component, which was presented as those terms are defined in the Indenture governing the 2032 Notes). We elected to repurchase $7.3 million, $7.6 million and $125 million, respectively, in aggregate principal amountlong-term debt, net of the 2032 Notes in June, Julyunamortized debt discount and Novemberdebt issuance costs. Those unamortized debt discount and debt issuance costs were accreted to interest expense through the maturity date of 2016, respectively. For the three-2026 Notes. As of December 31, 2020, unamortized debt discount and nine-month periods ended September 30, 2016, we recognized gainsdebt issuance costs related to the repurchase2026 Notes totaled $47.3 million. As a result of the 2032 Notesadoption of $0.2 million and $0.5 million, respectively, which are presented as “Gain on early extinguishment of long-term debt” in the accompanying consolidated statements of operations.

In connectionASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the issuance of the 20322026 Notes we recorded a debt discount of $35.4 million as required under existing accounting rules. To arrive at this discount amount we estimated the fair value of the liability component of the 2032 Notes as(Note 1). As of March 12, 2012 using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at31, 2021, unamortized debt issuance costs related to the time of pricing and an expected life of 6.0 years. In selecting the expected life, we selected the earliest date the holders could require us to repurchase all or a portion of the 20322026 Notes (March 15, 2018). were $6.8 million.

The effective interest rate for the 20322026 Notes is 6.9% after consideringprior to the effectadoption of ASU No. 2020-06 was 12.4%. The effective interest rate subsequent to the accretionadoption of ASU No. 2020-06 decreased to 7.6%. For the related debt discount that represented the equity component of the 2032 Notes at their inception. We recorded $22.5 million, net of tax,three-month period ended March 31, 2021, total interest expense related to the carrying amount2026 Notes was $3.7 million, with coupon interest expense of $3.4 million and the amortization of debt issuance costs of $0.3 million.

In connection with the 2026 Notes offering, we entered into capped call transactions (the “2026 Capped Calls”) with three separate option counterparties. The 2026 Capped Calls are separate transactions from the 2026 Notes and do not change the holders' rights under the 2026 Notes. Holders of the equity component2026 Notes do not have any rights with respect to the 2026 Capped Calls.

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The 2026 Capped Calls are for an aggregate of 28,675,900 shares of our common stock, which corresponds to the shares into which the 2026 Notes are initially convertible. The capped call shares are subject to certain anti-dilution adjustments. Each capped call option has an initial strike price of approximately $6.97 per share, which corresponds to the initial conversion price of the 2032 Notes.2026 Notes, and an initial cap price of approximately $8.42 per share. The remaining unamortized amountstrike and cap prices are subject to certain adjustments. The 2026 Capped Calls are intended to offset some or all of the debt discountpotential dilution to Helix common shares caused by any conversion of the 20322026 Notes was $1.1up to the cap price. The 2026 Capped Calls can be settled in either net shares or cash at our option in components commencing December 15, 2025 and ending February 12, 2026, which could be extended under certain circumstances.

The 2026 Capped Calls are subject to either adjustment or termination upon the occurrence of specified extraordinary events affecting Helix, including a merger, tender offer, nationalization, insolvency or delisting. In addition, certain events may result in a termination of the 2026 Capped Calls, including changes in law, insolvency filings and hedging disruptions. The 2026 Capped Calls are recorded at their aggregate cost of $10.6 million at September 30, 2017 and $2.6 million at December 31, 2016.

as a reduction to common stock in the shareholders’ equity section of our consolidated balance sheet.

MARAD Debt

This U.S. government guaranteedgovernment-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, beginning in August 2002 and matures in February 2027 and initially borebears interest at a floating rate that approximated AAA Commercial Paper yields plus 20 basis points. As required by the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date.

Nordea Credit Agreement
In September 2014, Q5000 Holdings entered into.

Other

We previously had a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in anto finance the construction of the Q5000. The loan was secured by the Q5000 and its charter earnings. As of December 31, 2020, the remaining principal amount of up to $250 million. Thethe Nordea Q5000 Loan was funded in$53.6 million, reflecting the amount of $250 million in April 2015 at the time the Q5000 vessel was delivered to us. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.

The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment on the final maturity of $80.4 million at maturity. Q5000 Holdings may elect to prepay amounts 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 onJanuary 31, 2021. We repaid this debt. In June 2015, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 14). The total notional amount of the swaps (initially $187.5 million) decreasesbalance in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.

17



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.
Other 
January 2021.

In accordance with ourthe Credit Agreement, the 2022 Notes, the 20322023 Notes, the 2026 Notes and the MARAD Debt agreements, and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio, a consolidated total leverage ratio and variousa consolidated secured leverage ratios,ratio, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. As of September 30, 2017,March 31, 2021, we were in compliance with these covenants.

The following table details the components of our net interest expense (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Interest expense

$

6,112

 

$

7,394

Capitalized interest

 

 

(1,182)

Interest income

 

(59)

 

(466)

Net interest expense

$

6,053

 

$

5,746

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 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
Interest expense$8,336
 $10,745
 $30,183
 $34,224
Interest income(792) (833) (2,056) (1,713)
Capitalized interest(3,929) (3,069) (12,647) (7,504)
Net interest expense$3,615
 $6,843
 $15,480
 $25,007

Note 76 — 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, anduncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

For the three-month period ended March 31, 2021, our estimated annual effective tax rate, adjusted for discrete tax items, is applied to our pre-tax loss as we have determined that the use of the annual effective tax rate method is appropriate. We used the discrete effective tax rate method for recording income taxes for the three-month period ended March 31, 2020. The discrete method is applied when the application of the estimated annual effective tax rate is impractical because it is not possible to reliably estimate the annual effective tax rate. The discrete method treats the year-to-date period as if it were the annual period and determines the income tax expense or benefit on that basis. For the three-month period ended March 31, 2020, we believed using the discrete method was more appropriate than the annual effective tax rate method because of the high degree of uncertainty in estimating annual pretax earnings created at the time by uncertainty in future market conditions caused by the ongoing COVID-19 pandemic as well as uncertainty in the oil and gas market.

The U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which was signed into law on March 27, 2020, is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses, which previously had been required to be carried forward, at the tax rates applicable in the relevant carryback year. As a result of these changes, in the three-month period ended March 31, 2020 we recognized an estimated $5.8 million net tax benefit, consisting of a $15.9 million current tax benefit and a $10.1 million deferred tax expense. This $5.8 million net tax benefit resulted from our deferred tax assets related to our net operating losses in the U.S. being utilized at the previous higher income tax rate applicable to the carryback periods.

During the three-month period ended March 31, 2020, we migrated 2 of our foreign subsidiaries into our U.S. consolidated tax group. Subsequent to the migration, these subsidiaries are disregarded and no longer subject to certain branch profits taxes. Consequently, we recognized net deferred tax benefits of $8.3 million due to the reduction in the overall tax rate associated with these subsidiaries.

Income taxes are provided at the U.S. statutory rate and at the local statutory rate for each foreign jurisdiction and adjusted for items that are permanent differences for Federal and foreign income tax reporting purposes, but not for book purposes. The effective tax rates for the three- and nine-monththree-month periods ended September 30, 2017March 31, 2021 and 2020 were (204.9)(4.0)% and 5.2%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, 2016 were 24.1% and 26.7%60.2%, respectively. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions and a change inas well as our carrying back certain net operating losses to prior periods with higher income tax position related to our foreign taxes.

We continued recording income taxes using a year-to-daterates. The effective tax rate method for the three- and nine-month periodsthree-month period ended September 30, 2017. The use of this methodMarch 31, 2021 was based on our expectations at September 30, 2017 that a small change in our estimated ordinary income could result in a large change in the estimated annual effective tax rate. We will re-evaluate our use of this method each quarter until such time as a return to the annualized effective tax rate method is deemed appropriate.

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Income taxes are provided based onsignificantly lower than the U.S. statutory rate primarily due to non-creditable foreign taxes and offset in part by a significant portion of 35%our current period earnings being generated in certain jurisdictions with a lower tax rate. The combination of these offsetting factors resulted in an overall tax provision and ata negative tax rate for the localquarter. The effective tax rate for the three-month period ended March 31, 2020 was significantly higher than the U.S. statutory rate for eachprimarily due to our recognition of discrete benefits during the period related to the restructuring of certain foreign jurisdiction adjusted for items that are allowed as deductions for federalsubsidiaries and foreignour carrying back certain net operating losses to prior periods with higher income tax reporting purposes, but not for book purposes. rates under tax law changes associated with the CARES Act whereas we had only nominal pre-tax losses.

17

Table of Contents

The primary differences between the income tax provision (benefit) at the U.S. statutory rate and our effective rateactual income tax provision (benefit) are as follows: 

follows (dollars in thousands):

Three Months Ended

 

March 31, 

 

    

2021

    

2020

 

Taxes at U.S. statutory rate

$

(616)

 

21.0

%  

$

(7,355)

 

21.0

%

Foreign tax provision

 

(938)

 

32.0

 

1,051

 

(3.0)

CARES Act

 

 

 

(5,814)

 

16.6

Subsidiary restructuring

 

 

 

(8,333)

 

23.8

Other

 

1,670

 

(57.0)

 

(642)

 

1.8

Income tax provision (benefit) (1)

$

116

 

(4.0)

%  

$

(21,093)

 

60.2

%

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
U.S. statutory rate35.0 % 35.0 % 35.0 % 35.0 %
Foreign provision(241.5) (10.8) 2.8
 (8.8)
Change in tax position (1)

 
 (29.3) 
Other1.6
 (0.1) (3.3) 0.5
Effective rate(204.9)% 24.1 % 5.2 % 26.7 %
(1)We consider all available evidence, both positive andThe negative when determining whether a valuation allowanceeffective tax rate for the three-month period ended March 31, 2021 is required against deferreddue to the tax assets. Due to weaker near term outlook and financial results primarilybenefits associated with our Robotics segment, we currently do not anticipate generating sufficientnominal pretax loss being smaller than our non-creditable foreign source income to fully utilize our foreign tax credits prior to their expiration. We have concluded that it is more likely than not previously recorded deferred tax assets attributable to foreign tax credits will not be realized. As a result of this change in tax position, we recorded a tax charge of $6.3 million in June 2017, which is comprised of a $2.8 million valuation allowance attributable to a foreign tax credit carryforward from 2015 and a $3.5 million charge attributable to the decision to deduct foreign taxes related to 2016 and 2017.taxes.

Note 87 —Shareholders’ Equity

On January 10, 2017, we completed an underwritten public offering (the “Offering”) Revenue from Contracts with Customers

Disaggregation of 26,450,000 sharesRevenue

Our revenues are primarily derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of our common stock atsuch 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. Contracts are classified as long-term if all or part of the contract is to be performed over a public offering price of $8.65 per share. The net proceedsperiod extending beyond 12 months from the Offering approximated $220 million, after deducting underwriting discounts and commissions and estimated offering expenses. We usedeffective date of the net proceeds fromcontract. Long-term contracts may include multi-year agreements whereby the Offeringcommitment for general corporate purposes, including debt repayment, capital expenditures, working capital and investmentsservices in our subsidiaries.

any one year may be short in duration. The components of Accumulated Other Comprehensive Income (Loss) (“OCI”) are as followsfollowing table provides information about disaggregated revenue by contract duration (in thousands):

Well

Production

Intercompany

Total

    

Intervention

    

Robotics

    

Facilities

    

Eliminations (1)

    

Revenue

Three months ended March 31, 2021

 

  

 

  

 

  

 

  

 

  

Short-term

$

49,217

$

9,407

$

0

$

0

$

58,624

Long-term

 

84,551

 

12,749

 

16,447

 

(8,956)

 

104,791

Total

$

133,768

$

22,156

$

16,447

$

(8,956)

$

163,415

Three months ended March 31, 2020

 

  

 

  

 

  

 

  

 

  

Short-term

$

82,324

$

22,441

$

0

$

0

$

104,765

Long-term

 

58,328

 

12,817

 

15,541

 

(10,430)

 

76,256

Total

$

140,652

$

35,258

$

15,541

$

(10,430)

$

181,021

 September 30,
2017
 December 31,
2016
    
Cumulative foreign currency translation adjustment$(64,048) $(78,953)
Unrealized loss on hedges, net (1)
(8,314) (18,021)
Accumulated other comprehensive loss$(72,362) $(96,974)
(1)
Relates to foreign currency hedges for the Grand Canyon, Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan, andIntercompany revenues among our business segments are net of deferred income taxes totaling $4.5 million at September 30, 2017 and $9.7 million at December 31, 2016 (Note 14).
under agreements that are considered long-term.

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.

18

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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” in the accompanying condensed consolidated balance sheets (Note 3). Contract assets were $0.4 million at March 31, 2021 and $2.4 million at December 31, 2020. We had 0 credit losses on our contract assets for the three-month periods ended March 31, 2021 and 2020.

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 a single performance obligation and recognized ratably over the contract term and/or (ii) amounts 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” in the accompanying condensed consolidated balance sheets (Note 3). Contract liabilities totaled $10.9 million at March 31, 2021 and $10.0 million at December 31, 2020. Revenue recognized for the three-month periods ended March 31, 2021 and 2020 included $2.5 million and $3.4 million, respectively, that were included in the contract liability balance at the beginning of each period.

We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.

Performance Obligations

As of March 31, 2021, $358.4 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $238.7 million in 2021, $84.4 million in 2022 and $35.3 million in 2023 and thereafter. These amounts include 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, 2021.

For the three-month periods ended March 31, 2021 and 2020, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

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” in the accompanying condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $19.6 million at March 31, 2021 and $24.4 million at December 31, 2020. For the three-month periods ended March 31, 2021 and 2020, we recorded $10.4 million and $9.2 million, respectively, related to amortization of these deferred contract costs. There were no associated impairment losses for any period presented.

For additional information regarding revenue recognition, see Notes 2 and 12 to our 2020 Form 10-K.

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Note 98 — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. HoldersBecause 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 basic and diluted EPS under the shares of restricted stock are thus considered participating securities.two-class method in periods in which we have earnings. Under applicable accounting guidance, the undistributed earningstwo-class method, net income or loss attributable to common shareholders for each period areis allocated based on the participation rights of both the common shareholders and the holders of any participating securities as if earnings for the respective periods had been distributed. Because both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute earnings per share (“EPS”) amounts under the two class method in periods in which we have earnings. For periods in which we have a net loss we do not use the two classtwo-class method as holders of our restricted shares are not obligated to share in such losses.

The presentation of basic

Basic EPS amounts on the face of the accompanying condensed consolidated statements of operations is computed by dividing net income or loss available to common shareholders 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 income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. The computations of the numerator (income) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations for the three-month periods ended September 30, 2017 and 2016 are as follows (in thousands):

 Three Months Ended
September 30, 2017
 Three Months Ended
September 30, 2016
 Income Shares Income Shares
Basic:       
Net income$2,290
   $11,462
  
Less: Undistributed earnings allocated to participating securities(27)   (160)  
Undistributed earnings allocated to common shares$2,263
 145,958
 $11,302
 113,680
        
Diluted:       
Undistributed earnings allocated to common shares$2,263
 145,958
 $11,302
 113,680
Effect of dilutive securities:       
Share-based awards other than participating securities
 
 
 
Undistributed earnings reallocated to participating securities
 
 
 
Net income$2,263
 145,958
 $11,302
 113,680

Three Months Ended

Three Months Ended

March 31, 2021

March 31, 2020

    

Income

    

Shares

    

Income

    

Shares

Basic and Diluted:

 

  

 

  

 

  

 

  

Net loss attributable to common shareholders

$

(2,878)

 

$

(11,938)

 

  

Less: Accretion of redeemable noncontrolling interests

 

(241)

 

(2,086)

 

  

Net loss available to common shareholders

$

(3,119)

149,935

$

(14,024)

 

148,863

We had net losses for the nine-monththree-month periods ended September 30, 2017March 31, 2021 and 2016.2020. Accordingly, our diluted EPS calculation for these periods was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):

 Nine Months Ended
September 30,
 2017 2016
    
Diluted shares (as reported)145,057
 109,135
Share-based awards364
 308
Total145,421
 109,443

20



In addition, the

Three Months Ended

March 31, 

    

2021

    

2020

Diluted shares (as reported)

 

149,935

 

148,863

Share-based awards

 

1,093

 

722

Total

 

151,028

 

149,585

The following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 20322026 Notes were excluded from the diluted EPS calculation because we have the right and the intention to settle any such future conversions in cash (Note 6)as they were anti-dilutive (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

2022 Notes

 

2,519

 

8,997

2023 Notes

 

3,168

 

13,202

2026 Notes

 

28,676

 

20

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
2022 Notes8,997
 
 8,997
 
2032 Notes2,403
 7,493
 2,403
 7,814

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Note 109 — Employee Benefit Plans

Long-Term Incentive Stock-Based Plan

As of September 30, 2017,March 31, 2021, there were 2.46.0 million shares of our common stock available for issuance under our long-term incentive stock-based plan, the 2005 Long-Term Incentive Plan, as amended and restated January 1, 2017 (the “2005 Incentive Plan”). During the nine-monththree-month period ended September 30, 2017,March 31, 2021, the following grants of share-based awards were made under the 2005 Incentive Plan:

Grant Date

Fair Value

Date of Grant

    

Shares/Units

    

Per Share/Unit

    

Vesting Period

January 1, 2021 (1)

 

452,381

$

4.20

 

33% per year over three years

January 4, 2021 (2)

 

452,381

$

5.33

 

100% on January 4, 2024

January 4, 2021 (3)

 

14,249

$

4.20

 

100% on January 1, 2023

Date of Grant  Shares   
Grant Date
Fair Value
Per Share
  Vesting Period
           
January 3, 2017 (1)
  671,771
   $8.82
  33% per year over three years
January 3, 2017 (2)
  671,771
   $12.64
  100% on January 1, 2020
January 3, 2017 (3)
  9,956
   $8.82
  100% on January 1, 2019
April 3, 2017 (3)
  8,004
   $7.77
  100% on January 1, 2019
July 3, 2017 (3)
  14,018
   $5.64
  100% on January 1, 2019
(1)Reflects grants of restricted stock units (“RSUs”) to our executive officers and select management employees.officers.
(2)Reflects grants of performance share units (“PSUs”) to our executive officers and select management employees. Theofficers. These PSUs provide for an awardconsist of two components: (i) 50% based on the performance of our common stock over a three-year period withand (ii) 50% based on cumulative total Free Cash Flow (“FCF”). The grant date fair value represents the maximum amountaverage grant date fair value of the award being 200% of the original awarded PSUs and the minimum amount being zero. For the 2017 awards, vested PSUs can only be settled in shares of our common stock.two components.
(3)Reflects grants of restricted stock to certain independent members of our Board of Directors (the(our “Board”) who have made an electionelected to take their quarterly fees in stock in lieu of cash.

Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting periodsperiod on a straight-line basis. We elected to account for forfeitures whenForfeitures are recognized as they occur upon the adoption of the new guidance for employee share-based payment accounting (Note 1).occur. No restricted stock awards were granted in 2021. All outstanding unvested restricted stock awards were granted in 2020 and 2019. For the three- and nine-monththree-month periods ended September 30, 2017, $1.7March 31, 2021 and 2020, $0.8 million and $5.4$1.1 million, respectively, were recognized as share-based compensation related to restricted stock. For

Our existing PSUs that were granted prior to 2021 are to be settled solely in shares of our common stock and are accounted for as equity awards. Those PSUs contain a service condition and a market condition. PSUs granted in 2021 may be settled in either cash or shares of our common stock upon vesting at the three-discretion of the Compensation Committee of our Board and nine-month periods ended September 30, 2016, $1.4 millionare initially accounted for as equity awards. The PSUs granted in 2021 consist of 2 components: (i) 50% based on the performance of our common stock against peer group companies, which contains a service condition and $4.3 million, respectively, were recognizeda market condition, and (ii) 50% based on cumulative total FCF, which contains a service condition and a performance condition. FCF is calculated as share-based compensation related to restricted stock.


21


Tablecash flows from operating activities less capital expenditures, net of Contents

Theproceeds from sale of assets. Our PSUs cliff vest at the end of a three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being 0.

Compensation cost for PSUs that have a service condition and a market condition and are accounted for as equity awards is measured based on the grant date estimated fair value of PSUsand recognized over the vesting period on a straight-line basis. The grant date estimated fair value is determined using a Monte Carlo simulation model. Compensation cost for PSUs that have a service condition and a performance condition and are accounted for as equity awards is initially measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. PSUs that are accounted for as liability awards are measured based on the estimated fair value at the balance sheet date and changes in fair value of the awards are recognized in earnings.value. Cumulative compensation cost for vested liability PSU awards equalsis subsequently adjusted at the actual cash payout amount upon vesting. The 2017 awards are accounted for as equity awards whereas awards made priorend of each reporting period to 2017 are accounted for as liability awards.reflect the current estimation of achieving the performance condition. For the three- and nine-monththree-month periods ended September 30, 2017, $4.0March 31, 2021 and 2020, $1.0 million and $5.8$1.1 million, respectively, were recognized as share-based compensation related to equity PSUs. In January 2021, based on the performance of our common stock price as compared to our performance peer group over a three-year period, 368,038 equity PSUs granted in 2018 vested at 200%, representing 736,075 shares of our common stock with a total market value of $3.1 million.

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Table of Contents

RSUs granted in 2021 have been accounted for as liability awards. Liability RSUs are measured at their estimated fair value at each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting. For the three-three-month period ended March 31, 2021, $0.2 million was recognized as compensation cost.

In 2021 and nine-month2020, we granted fixed-value cash awards of $3.4 million and $4.7 million, respectively, to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the three-month periods ended September 30, 2016, $2.5March 31, 2021 and 2020, $1.0 million and $5.3$1.2 million, respectively, were recognized as share-based compensation related to PSUs. The liability balancecost.

Defined Contribution Plan

We sponsor a defined contribution 401(k) retirement plan. We suspended our discretionary contributions for unvested PSUs was $10.2 million at September 30, 2017 and $7.1 million at December 31, 2016. We paid $0.6 million in cash to settle the 2014 grant of PSUs when they vested inan indefinite period beginning January 2017.

2021.

Employee Stock Purchase Plan

We have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance,As of which 0.6March 31, 2021, 1.7 million shares were available for issuance as of September 30, 2017. In February 2016, we suspendedunder the ESPP. The ESPP purchases for the January through April 2016 purchase period and indefinitely imposedcurrently has a purchase limit of 130260 shares per employee for subsequentper purchase periods.

period.

For more information regarding our employee benefit plans, including our long-term incentive stock-basedthe 2005 Incentive Plan and cash plans and our employee stock purchase plan,the ESPP, see Note 1214 to our 20162020 Form 10-K.

Note 1110 — 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 includesprovides services enabling our vessels and equipment usedcustomers to performsafely access offshore wells for the purpose of performing well intervention servicesenhancement or decommissioning operations primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and Brazil. Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and SILs.West Africa. Our well intervention vessels include the Q4000, the Q5000, the SeawellQ7000, the Seawell, the Well Enhancer, and the chartered Siem Helix 1 and Siem Helix 2 chartered vessels. The Siem Helix 1 commenced its operations for Petrobras in mid-April 2017.Our well intervention equipment includes IRSs, SILs and the ROAM, some of which we provide on a stand-alone basis. Our Robotics segment provides offshore construction, cable trenching, seabed clearance, inspection, repair and maintenance services to both the oil and gas and the renewable energy markets globally. Our Robotics services also complement well intervention services. Our Robotics segment includes ROVs, trenchers and ROVDrills designed to complement offshore constructiona ROVDrill, and well intervention services, and currently operates four chartered ROV2 robotics support vessels includingunder long-term charter, the Grand Canyon II and the Grand Canyon III that went into service for us in May 2017., as well as spot vessels as needed. Our Production Facilities segment includes the HP I, the HFRS and our investment in Independence Hub that is accounted for under the equity method,ownership of oil and previously included our former ownership interest in Deepwater Gateway that we sold in February 2016gas properties (Note 5)11). All material intercompany transactions between the segments have been eliminated.

22


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We evaluate our performance primarily based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):

Three Months Ended

March 31, 

2021

    

2020

Net revenues —

  

 

  

Well Intervention

$

133,768

$

140,652

Robotics

 

22,156

 

35,258

Production Facilities

 

16,447

 

15,541

Intercompany eliminations

 

(8,956)

 

(10,430)

Total

$

163,415

$

181,021

Income (loss) from operations —

 

  

 

  

Well Intervention

$

5,243

$

(5,692)

Robotics

 

(2,934)

 

(2,824)

Production Facilities

 

6,514

 

3,643

Segment operating income (loss)

 

8,823

 

(4,873)

Goodwill impairment (1)

 

 

(6,689)

Corporate, eliminations and other

 

(9,378)

 

(9,465)

Total

$

(555)

$

(21,027)

(1)As a result of the decline in oil prices as well as energy and energy services valuations during the first quarter 2020 due to the COVID-19 pandemic and the price war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”), we impaired all of our goodwill, which consisted entirely of goodwill attributable to the acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”).
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
Net revenues —       
Well Intervention$111,522
 $108,287
 $299,219
 $214,262
Robotics47,049
 48,897
 102,078
 119,805
Production Facilities16,380
 17,128
 47,965
 54,567
Intercompany elimination(11,691) (13,067) (31,145) (29,083)
Total$163,260
 $161,245
 $418,117
 $359,551
        
Income (loss) from operations —       
Well Intervention$16,906
 $24,413
 $37,356
 $7,187
Robotics(9,365) (94) (37,313) (21,667)
Production Facilities7,660
 8,312
 20,724
 25,225
Corporate and other(10,633) (10,288) (29,296) (28,784)
Intercompany elimination199
 (873) 641
 (542)
Total$4,767
 $21,470
 $(7,888) $(18,581)

Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties.segments. Intercompany segment revenues are as follows (in thousands):

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
Well Intervention$3,765
 $2,898
 $8,033
 $5,740
Robotics7,926
 10,169
 23,112
 23,343
Total$11,691
 $13,067
 $31,145
 $29,083

Three Months Ended

March 31, 

    

2021

    

2020

Well Intervention

$

2,587

$

3,304

Robotics

 

6,369

 

7,126

Total

$

8,956

$

10,430

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):

March 31, 

December 31,

    

2021

    

2020

Well Intervention

$

2,081,641

$

2,134,081

Robotics

 

108,372

 

132,550

Production Facilities

 

134,989

 

129,773

Corporate and other

 

96,747

 

101,874

Total

$

2,421,749

$

2,498,278

23

 September 30,
2017
 December 31,
2016
    
Well Intervention$1,774,821
 $1,596,517
Robotics179,777
 186,901
Production Facilities141,739
 158,192
Corporate and other270,153
 305,331
Total$2,366,490
 $2,246,941

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Note 11 — Asset Retirement Obligations

Asset retirement obligations (“AROs”) are recorded at fair value and consist of estimated costs for subsea infrastructure plug and abandonment (“P&A”) activities associated with our oil and gas properties. 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.

Our AROs relate to our Droshky oil and gas properties that we acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019. In connection with assuming the P&A obligations related to those assets, we are entitled to receive agreed-upon amounts from Marathon Oil as the P&A work is completed. The following table describes the changes in our AROs (both current and long-term) (in thousands):

    

2021

    

2020

AROs at January 1,

$

30,913

$

28,258

Accretion expense

 

48

 

676

AROs at March 31, 

$

30,961

$

28,934

Note 12 — Commitments and Contingencies and Other Matters

Commitments

We have charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. In February 2016, we amended the charter agreements to reduce the charter rates and, in connection with those reductions, to extend the terms to October 2019 for the Grand Canyon, to April 2021 for the Grand Canyon II and to May 2023 for the Grand Canyon III. We also have a charter agreement for the Deep Cygnus that expires in March 2018.

In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000 for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being built to North Sea standards. This $346 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the original contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% is to be paid upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% is to be paid upon the delivery of the vessel, which at our option can be deferred until December30, 2018. We agreed to pay the shipyard its incremental costs in connection with the contract amendments to extend the scheduled delivery of the Q7000 and to defer certain payment obligations. Incremental costs are capitalized as they are incurred during the construction of the vessel. At September 30, 2017, our total investment in the Q7000 was $213.6 million, including $138.4 million of installment payments to the shipyard.
In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil, and in connection with the Petrobras agreements, we entered intolong-term charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohullthe Siem Helix1 and Siem Helix2 vessels, the Siem Helix1 and the Siem Helix2.which are currently 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. The initial termSiem Helix 1 charter expires June 2023 and the Siem Helix 2 charter expires February 2024. We have time charter agreements for the Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The expiration date of the agreementsGrand Canyon II charter was extended in February 2021 from April 2021 until December 2021, with Petrobras is for four years with Petrobras’s optionsan option to extend.
renew. The Siem Helix1 vessel was delivered to us and theGrand Canyon III charter term began on June 14, 2016. The vessel was accepted by Petrobras and commenced operations on April 14, 2017, at which time we agreed with Petrobras to commence operations at reduced day rates. Our day rates improved in the third quarter as we addressed most of the items identified in the vessel acceptance process. The Siem Helix2 was delivered to us and the charter term began on February 10, 2017. The vessel has transited to Brazil after integration and commissioning of our topside equipment onboard and is currently in the process of inspection protocol and customer equipment integration. We currently anticipate that the vessel will commence operations for Petrobras late in the fourth quarter of 2017. At September 30, 2017, our total investment in the topside equipment for the two vessels was $304.1 million.
expires May 2023.

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 or cash flows.

Litigation

We are involved in various other legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence.Act. In addition, from time to time we incurreceive other claims, such as contract and employment-related disputes, in the normal course of business.

Note 13 — 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. We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. The following table provides supplemental cash flow information (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Interest paid, net of interest capitalized

$

9,397

$

4,785

Income taxes paid

 

1,790

 

2,584

Our capital additions include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $0.6 million at March 31, 2021 and $1.6 million at December 31, 2020.

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Note 1314 — Allowance for Credit Losses

We estimate current expected credit losses on our accounts receivable at each reporting date. We estimate current expected credit losses based on our credit loss history, adjusted for current factors including global economic and business conditions, offshore energy industry and market conditions, customer mix, contract payment terms and past due accounts receivable.

The following table sets forth the activity in our allowance for credit losses (in thousands):

    

2021

    

2020

Balance at January 1,

$

3,469

$

Additions (1)

 

7

 

586

Write-offs (2)

(1,811)

Adjustments (3)

 

 

785

Balance at March 31, 

$

1,665

$

1,371

(1)The additions in allowance for credit losses reflect credit loss reserves during the respective periods.
(2)The write-offs of allowance for credit losses reflect certain receivables related to our Robotics segment that were previously reserved and subsequently deemed to be uncollectible.
(3)The adjustment in allowance for credit losses reflects provision for current expected credit losses upon the adoption of ASU No. 2016-13 on January 1, 2020.

Note 15 — 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.
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

24



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).

Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term debt and various derivative instruments.debt. 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 net carrying amount of our long-term note receivable also approximates its fair value. The following tables provide additional information relating to other financial instruments measured at fair value on a recurring basis (in thousands): 

25

 Fair Value Measurements at
September 30, 2017 Using
    
 Level 1 
Level 2 (1)
 Level 3 Total 
Valuation
Approach
Assets:         
Interest rate swaps$
 $374
 $
 $374
 (c)
          
Liabilities:         
Foreign exchange contracts
 19,508
 
 19,508
 (c)
Interest rate swaps
 82
 
 82
 (c)
Total liability$
 $19,216
 $
 $19,216
  
 Fair Value Measurements at
December 31, 2016 Using
    
 Level 1 
Level 2 (1)
 Level 3 Total 
Valuation
Approach
Assets:         
Interest rate swaps$
 $451
 $
 $451
 (c)
          
Liabilities:         
Foreign exchange contracts
 38,170
 
 38,170
 (c)
Interest rate swaps
 751
 
 751
 (c)
Total net liability$
 $38,470
 $
 $38,470
  
(1)Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. See Note 14 for further discussion on fair value of our derivative instruments.

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The carrying valuesprincipal amount and estimated fair valuesvalue of our long-term debt are as follows (in thousands):

March 31, 2021

December 31, 2020

Principal

Fair

Principal

Fair

    

Amount (1)

    

Value (2) (3)

    

Amount (1)

    

Value (2) (3)

Term Loan (matures December 2021)

$

28,875

$

28,622

$

29,750

$

28,969

Nordea Q5000 Loan (matured January 2021) (4)

 

 

 

53,572

 

53,598

MARAD Debt (matures February 2027)

 

52,676

 

58,502

 

56,410

 

62,318

2022 Notes (mature May 2022)

 

35,000

 

34,917

 

35,000

 

33,513

2023 Notes (mature September 2023)

 

30,000

 

28,942

 

30,000

 

28,650

2026 Notes (mature February 2026)

 

200,000

 

232,674

 

200,000

 

211,383

Total debt

$

346,551

$

383,657

$

404,732

$

418,431

 September 30, 2017 December 31, 2016
 
Carrying
Value (1)
 
Fair
Value (2)
 
Carrying
Value (1)
 
Fair
Value (2)
        
Term Loan (previously scheduled to mature June 2018)$
 $
 $192,258
 $192,258
Nordea Q5000 Loan (matures April 2020)169,643
 168,583
 196,429
 192,746
Term Loan (matures June 2020)98,750
 99,120
 
 
MARAD Debt (matures February 2027)77,000
 83,928
 83,222
 92,049
2022 Notes (mature May 2022)125,000
 123,281
 125,000
 130,156
2032 Notes (mature March 2032)60,115
 60,077
 60,115
 59,965
Total debt$530,508
 $534,989
 $657,024
 $667,174
(1)Carrying valuePrincipal amount includes current maturities and excludes theany related unamortized debt discount and debt issuance costs. See Note 65 for additional disclosures on our long-term debt.
(2)The estimated fair value of the 2022 Notes, the 2023 Notes and the 20322026 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt the Term Loan maturing June 2020 and our previous term loan that was scheduled to mature June 2018 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, the 2023 Notes and the 2026 Notes are for the entire instrument inclusive of the conversion feature, which had been accounted for in shareholders’ equity through December 31, 2020.
(4)The Nordea Q5000 Loan was fully repaid upon maturity in January 2021 (Note 5).

Note 14 — 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 hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative instruments are reflected in the accompanying condensed consolidated balance sheets at fair value.
We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are deferred to the extent the hedges are effective. These changes are recorded as a component of Accumulated OCI (a component of shareholders’ equity) until the hedged transactions occur and are recognized in earnings. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change in the fair value of a derivative instrument that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.
For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 18 to our 2016 Form 10-K.
Interest Rate Risk
From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into various interest rate swap contracts to fix the interest rate on $187.5 million of our 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 deferred to the extent the swaps are effective. These changes are recorded as a component of Accumulated OCI until the anticipated interest is recognized as interest expense. The ineffective portion of the interest rate swaps, if any, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.

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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 January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 our foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand Canyon II and Grand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. In December 2015, we de-designated the foreign currency exchange contracts associated with the charter payment obligations for the Grand Canyon II and Grand Canyon III vessels that no longer qualified for cash flow hedge accounting treatment and we re-designated the hedging relationship between a portion of these contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring. Unrealized losses associated with the effective portion of our foreign currency exchange contracts that qualify for hedge accounting treatment are included in our Accumulated OCI (net of tax). Reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations are changes in unrealized losses associated with the foreign currency exchange contracts that are no longer designated as cash flow hedges. Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations. There were no gains or losses associated with hedge ineffectiveness for the three- and nine-month periods ended September 30, 2017 and the three-month period ended September 30, 2016. For the nine-month period ended September 30, 2016, we recorded unrealized gains of $0.1 million related to our hedge ineffectiveness.
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, 2017 December 31, 2016
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Asset Derivative Instruments:       
Interest rate swapsOther assets, net $374
 Other assets, net $451
   $374
   $451
        
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $6,945
 Accrued liabilities $14,056
Interest rate swapsAccrued liabilities 82
 Accrued liabilities 751
Foreign exchange contractsOther non-current liabilities 6,123
 Other non-current liabilities 13,383
   $13,150
   $28,190

27



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, 2017 December 31, 2016
 
Balance Sheet
Location
 
Fair
Value
 
Balance Sheet
Location
 
Fair
Value
Liability Derivative Instruments:       
Foreign exchange contractsAccrued liabilities $2,900
 Accrued liabilities $3,923
Foreign exchange contractsOther non-current liabilities 3,540
 Other non-current liabilities 6,808
   $6,440
   $10,731
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 September 30, 2017, $4.6 million of losses in Accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.
 
Gain (Loss) Recognized in OCI on
Derivative Instruments, Net of Tax
(Effective Portion)
 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
Foreign exchange contracts$3,620
 $4,249
 $9,341
 $10,745
Interest rate swaps68
 643
 366
 (880)
 $3,688
 $4,892
 $9,707
 $9,865
 
Location of Loss Reclassified from
Accumulated OCI into Earnings
 
Loss Reclassified from
Accumulated OCI into Earnings
(Effective Portion)
  Three Months Ended
September 30,
 Nine Months Ended
September 30,
  2017 2016 2017 2016
          
Foreign exchange contractsCost of sales $(3,288) $(2,663) $(10,280) $(8,033)
Interest rate swapsNet interest expense (95) (494) (542) (1,618)
   $(3,383) $(3,157) $(10,822) $(9,651)
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 Gain
Recognized in Earnings on
Derivative Instruments
 
Gain Recognized in Earnings
on Derivative Instruments
  Three Months Ended
September 30,
 Nine Months Ended
September 30,
  2017 2016 2017 2016
          
Foreign exchange contractsOther income (expense), net $1,050
 $1,309
 $1,531
 $3,375
   $1,050
 $1,309
 $1,531
 $3,375

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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 current expectations and beliefs concerningor forecasts of 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 herein 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 or

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, capital expenditures or other financial items;
statements regarding our backlog and commercial 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 spot market, the continuation of our current backlog, our spending and cost reduction plans and our ability to manage changes, and the ongoing COVID-19 pandemic and oil price volatility and their respective effects and results on the foregoing as well as our protocols and plans;
statements regarding the acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto;
statements regarding any financing transactions or arrangements, or our ability to enter into such transactions or arrangements;

26

statements regarding the construction, upgrades or acquisition

Table of vessels or equipment and any anticipated costs related thereto, including the construction of our Q7000 vessel;

Contents

statements regarding potential legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
statements regarding our trade receivables and their collectability;
statements regarding potential developments, industry trends, performance or industry ranking;
statements regarding global, market or investor sentiment with respect to fossil fuels;
statements regarding our existing activities in, and future expansion into, the offshore renewable energy market;
statements regarding general economic or political conditions, whether international, national or in the regional or local markets in which we do business;
statements regarding our ability to retain our senior management and other key employees;
statements regarding the underlying assumptions related to any projection or forward-looking statement; and
any other statements that relate to non-historical or future information.
statements regarding the commencement of commercial operations of the Siem Helix2 chartered vessel to be used in connection with our contracts to provide well intervention services offshore Brazil;
statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;
statements regarding our backlog and long-term contracts and rates thereunder;
statements regarding any financing transactions or arrangements, or ability to enter into such transactions;
statements regarding anticipated legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
statements regarding our trade receivables and their collectability;
statements regarding anticipated developments, industry trends, performance or industry ranking;
statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business;
statements regarding our ability to retain key members of 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 results and effects of the ongoing COVID-19 pandemic and actions by governments, customers, suppliers and partners with respect thereto;
the impact of domestic and global economic conditions and the future impact of such conditions on the offshore energy industry and the demand for our services;
the general impact of oil and gas price volatility and the cyclical nature of the oil and gas market;
the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;
the ability to effectively bid, renew and perform our 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, our ability to comply with debt covenants 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;
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 and how they will be interpreted or enforced;
the future impact of U.K.’s exit from the European Union (the “EU”), known as Brexit, and related trade agreements between the U.K. and the EU on our business, operations and financial condition;
the effect of adverse weather conditions and/or other risks associated with marine operations;
the impact of foreign currency exchange controls, potential illiquidity of those currencies and exchange rate fluctuations;
the effectiveness of our 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.

27

unexpected delays in the delivery or chartering or customer acceptance, and terms of acceptance, of new vessels for our well intervention and robotics fleet, including the Q7000 and the Siem Helix2, which is to be used to perform contracted well intervention work offshore Brazil;
the ability to continue to work through the items identified in the Siem Helix1 acceptance process and the timing thereof;
the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets, including the Q4000, the Q5000 and the Siem Helix1;
unexpected future capital expenditures, including the amount and nature thereof;
the effectiveness and timing of completion of our vessel upgrades and major maintenance items;
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;
the effects of competition;

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Table of Contents


the availability (or lack thereof) 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;
the impact of the vote in the U.K. to exit the European Union (the “EU”), known as Brexit, on our business, operations and financial condition, which is unknown at this time;
the effect of adverse weather conditions and/or other risks associated with marine operations;
the impact of foreign currency 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 in Item 1A. “Risk Factors”7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 20162020 Form 10-K. AllShould one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements attributablestatements.

We caution you not to us or persons actingplace undue reliance on our behalf are expressly qualified in their entirety by these risk factors.the forward-looking statements. 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, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ.

All forward-looking statements, express or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. We urge you to carefully review and consider the disclosures made in this Quarterly Report and our reports filed with the SEC and incorporated by reference in our 2020 Form 10-K that attempt to advise interested parties of the risks and factors that may affect our business.

EXECUTIVE SUMMARY

Our 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 focusingThe services we offer to the oil and gas market cover the lifecycle of an offshore oil or gas field, and the services we offer to the renewable energy market are currently focused on these services will deliver favorable long-term financial returns. From time to time, we make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions.offshore wind farm projects and cable burial operations. Our well intervention fleet expanded followingincludes seven purpose-built well intervention vessels, six IRSs, three SILs and the deliveryROAM. Our robotics equipment includes 42 work-class ROVs, four trenchers and one ROVDrill. We charter ROV support vessels on both long-term and spot bases to facilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the world. Our Production Facilities segment includes the HP I, the HFRS and our ownership of the Siem Helix 2 chartered vessel in February 2017oil and is expected to further expand following the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel that went into service for us in May 2017, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also benefit by our fixed fee agreement for the HP I servicing the Phoenix field for the field operator until at least June 1, 2023.

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 alliance to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to customers, combining marine support with well access and control technologies. In April 2015, we and OneSubsea agreed to jointly develop and ordered a 15,000 working p.s.i. IRS, which is expected to be completed mid-fourth quarter of 2017 for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At September 30, 2017, our total investment in the IRS was $11.6 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 $12 million (approximately $6 million for our 50% interest). At September 30, 2017, our total investment in the ROAM was $1.9 million. The ROAM is expected to be available to customers in the first quarter of 2018.
gas properties.

Economic Outlook and Industry Influences

Demand for our services is primarily influenced by the condition of the oil and gas industry, and the renewable energy markets, in particular, the willingness of oil and gasoffshore energy companies to spend on operational activities as well asand capital projects. The performance of our business is also largely dependent onaffected by 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, global health, and several other factors, including:

worldwide economic activity and general economic and business conditions, including access to global capital and capital markets;
the global supply and demand for oil and natural gas;
political and economic uncertainty and geopolitical unrest, including regional conflicts and economic and political conditions in oil-producing regions;
actions taken by OPEC and/or OPEC+;
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 environmental and social sustainability of the oil and gas sector and the perception thereof, including within the investing community;
the sale and expiration dates of offshore leases globally;
governmental restrictions on oil and gas leases;
technological advances affecting energy exploration, production, transportation and consumption;
potential acceleration of the development of alternative fuels;

28

worldwide economic activity, including available access

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shifts in end-customer preferences toward fuel efficiency and the use of natural gas or renewable energy alternatives;
weather conditions, natural disasters, and epidemic and pandemic diseases, including the ongoing COVID-19 pandemic;
laws, regulations and policies directly related to the industries in which we provide services, and their interpretation and enforcement;
environmental and other governmental regulations; and
domestic and international tax laws, regulations and policies.

Crude oil prices historically have been volatile, which volatility has been exacerbated recently due to global capital and capital markets;

supply and demand for oil and natural gas, especially in the United States, Europe, China and India;
regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;
ongoing COVID-19 pandemic as well as actions taken by the Organization of Petroleum Exporting Countries;

30



the availabilityOPEC+ nations. Prices have since recovered to pre-COVID-19 levels, but their stability and discovery rate of new oil and natural gas reserves in offshore areas;
the exploration and production of 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 States 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.
recovery remain uncertain. The significant decline in oil prices since mid-year 2014in 2020 and the resulting difficult industry environment has had a significant adverse impact on investmentsvolatility and uncertainty in prices have caused oil and gas explorationoperators to drastically reduce spending (on both operational activities and production. Many oilcapital projects), which has decreased the demand and gas companies have terminated or not renewed contractsrates for many of their contracted rigs and have drastically cut investments in exploration and production as well as other operational activities. We expect these challenging industry conditions to continue through the end of 2017 and beyond if oil and gas prices fail to increase to a level conducive to increased activity levels. Increased competition for limitedservices provided by offshore oil and gas projects has driven down rates thatservices providers. Historically, 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 rigwork, and our customers have used drilling rigs on existing long-term contracts to perform well intervention work instead of new drilling activities. Rig day rates are also a pricing indicator for our services. Rig overhang, combined with lower volumes of work may affectand lower day rates quoted by drilling rig contractors, affects the utilization and/or rates we can achieve for our assets. In addition, despite the upward trend in global economic growth especially in emerging markets, the currentassets and services. Furthermore, additional volatile 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. We continue to monitor

The ongoing COVID-19 pandemic has resulted in a new period of market weakness. While the full impact of the COVID-19 pandemic, including the duration of the decrease in economic activity and the resulting impact on the demand and price of oil, remains unknown, we expect that the impact of Brexit and any exit agreements as they are negotiated, but the impact from Brexit on our business and operations will dependCOVID-19 on the outcome of tariff, tax treaties, trade, regulatoryindustry will continue to be felt through 2021 and possibly longer. We believe the uncertainty and other negotiations,conditions of the current environment will make it more difficult for us to secure long-term contracts for our vessels and systems, as operators have been less willing to commit to future spending. These developments have also impacted, and are expected to continue to impact, many other aspects of our industry and the global economy, including limiting access to and use of capital across various sources and markets, disrupting supply chains and increasing costs, and negatively affecting human capital resources including complicating offshore crew changes due to health and travel restrictions as well as the overall health of the global workforce. The COVID-19 pandemic and its effects on our industry and the global economy impacted our 2020 and 2021 operating results to date. Most if not all of our oil and gas customers have cut their spending, which has reduced the demand and rates for the services offered to our oil and gas customers. We warm-stacked two of our vessels in 2020 as a result of decreased demand and government lock-downs, and the Seawell in the North Sea remains stacked to date. The COVID-19 pandemic continues to pose challenges with, and increase costs related to, our supply chain, logistics and human capital resources, including minimizing the direct impact of BrexitCOVID-19 on macroeconomic growthour offshore workforce and currencychallenges with offshore crew changes due to travel restrictions and quarantine measures.

Despite this current period of market weakness and volatility, which are uncertain at this time.

Manyover the longer term we expect oil and gas companies areto increasingly focusingfocus on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that whenAs oil and gas companies begin to increase overall spending levels,re-assess and focus their budgetary spend allocations, we expect that it will likelymay be forweighted towards production enhancement activities rather than exploration projects as enhancement is less expensive per incremental barrel of oil than new exploration. Moreover, as the subsea tree base expands and ages, the demand for exploration projects.P&A services should persist. Our well intervention and robotics operations are intended to service the life spanlifecycle 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 over the longer term,We believe that we have a competitive advantage in performing well intervention services efficiently and 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 theand safely decommission end of life wells are primary driverdrivers of demand for our services.
Our current strategy is to be positioned for future recovery while coping with a sustained period of weak activity. This strategybelief 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.

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Helix Fast Response System

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We developed the HFRS in 2011 as a culmination of

Demand for our experience as a responderservices in the 2010 Macondo well controlrenewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and containment efforts. The HFRS centers on twogovernment subsidies for renewable energy projects.

Backlog

We 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. In addition to serving the oil and gas market, our vessels,robotics assets are contracted for the HP I and the Q4000, bothdevelopment of which played a key roleoffshore renewable energy projects (wind farms). We provide services primarily in the Macondo well control and containment efforts and are currently operatingdeepwater in the Gulf of Mexico. The HFRS provides industry participants with a response resourceMexico, Brazil, North Sea, Asia Pacific and West Africa regions. As of March 31, 2021, our consolidated backlog that is supported by written agreements or contracts totaled $358 million, of which $239 million is expected to be named in permit applications to federal and state agencies in exchange for a retainer fee.performed over the remainder of 2021. The HFRS agreements specify the day ratessubstantial majority of our backlog is associated with our Well Intervention segment. As of March 31, 2021, our well intervention backlog was $162 million, all of which is expected to be charged shouldperformed over the HFRS be deployed in connectionremainder of 2021. Our contract with aBP to provide well control incident. Theintervention 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 providing access tofor the HFRS was amended effective February 1, 2017 to reduce the retainer fee and to extend the termHP I represent approximately 57% of the agreement by one year toour total backlog as of March 31, 2019.


31



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.

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 condensed 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 operate primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and have expanded our operations into Brazil with the commencement of operations of the Siem Helix 1 in mid-April 2017. In addition to servicing the oil and gas market, our Robotics operations are contracted for the development of renewable energy projects (wind farms). As of September 30, 2017, our consolidated backlog that is supported by written agreements or contracts totaled $1.7 billion, of which $135.3 million is expected to be performed over the remainder of 2017. The substantial majority of our backlog is associated with our Well Intervention business segment. As of September 30, 2017, our well intervention backlog was $1.3 billion, including $94.9 million expected to be performed over the remainder of 2017. 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 Helix 1 and Siem Helix 2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 87% of our total backlog as of September 30, 2017. Backlog contracts are cancelable sometimes without penalty. In addition, if there are cancellation fees, the amount of those fees can be substantially less than the rates we would have generated had we performed the contract. Accordingly, backlog is not necessarily a reliable indicator of total annual revenues for our services as contracts may be added, renegotiated, deferred, canceled and in many cases modified while in progress, and reduced rates, fines and penalties may be imposed by our customers.

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 U.S. GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with U.S. GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these non-GAAP measures.

We measure our operating performance based on EBITDA aand free cash flow. EBITDA and free cash flow are non-GAAP financial measuremeasures that isare commonly used but isare not a recognized accounting termterms under U.S. 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 measuremeasures of EBITDA providesand 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.

We define EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. To arrive at our measure of Adjusted EBITDA, we exclude gain or loss on disposition of assets. In addition, we include realized losses from the cash settlements of our ineffective foreign currency exchange contracts, which are excluded from EBITDA as a component of net other income or expense. In the following reconciliation, we provide amounts as reflected in our accompanying condensed consolidated financial statements unless otherwise footnoted.

32



Other companies may calculate their measures of EBITDA, and Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. BecauseEBITDA, Adjusted EBITDA and Adjusted EBITDA are not financial measures calculated in accordance with U.S. GAAP, theyfree 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 U.S. GAAP.

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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. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets and the general provision for current expected credit losses, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, 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 the condensed consolidated financial statements unless otherwise noted.

The reconciliation of our net loss to EBITDA and Adjusted EBITDA is as follows (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Net loss

$

(3,050)

$

(13,928)

Adjustments:

 

  

 

  

Income tax provision (benefit)

 

116

 

(21,093)

Net interest expense

 

6,053

 

5,746

Other (income) expense, net

 

(1,617)

 

10,427

Depreciation and amortization

 

34,566

 

31,598

Goodwill impairment

 

 

6,689

EBITDA

 

36,068

 

19,439

Adjustments:

 

  

 

  

General provision for current expected credit losses

 

100

 

586

Realized losses from foreign exchange contracts not designated as hedging instruments

 

 

(682)

Adjusted EBITDA

$

36,168

$

19,343

The reconciliation of our cash flows from operating activities to free cash flow is as follows (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Cash flows from operating activities

$

39,869

$

(17,222)

Less: Capital expenditures, net of proceeds from sale of assets

 

(1,329)

 

(12,389)

Free cash flow

$

38,540

$

(29,611)

31

 Three Months Ended
September 30,
 Nine Months Ended
September 30,
 2017 2016 2017 2016
        
Net income (loss)$2,290
 $11,462
 $(20,528) $(27,032)
Adjustments:       
Income tax provision (benefit)(1,539) 3,649
 (1,117) (9,858)
Net interest expense3,615
 6,843
 15,480
 25,007
(Gain) loss on early extinguishment of long-term debt
 (244) 397
 (546)
Other (income) expense, net551
 (830) 619
 (4,018)
Depreciation and amortization26,293
 27,607
 82,670
 84,846
EBITDA31,210
 48,487
 77,521
 68,399
Adjustments:       
Loss on disposition of assets, net
 
 39
 
Realized losses from cash settlements of ineffective foreign currency exchange contracts(758) (1,786) (2,759) (5,744)
Adjusted EBITDA$30,452
 $46,701
 $74,801
 $62,655

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Comparison of Three Months Ended September 30, 2017March 31, 2021 and 2016 

2020

The following table details various financial and operational highlights for the periods presented (dollars in thousands):

Three Months Ended

Increase/

 

March 31, 

(Decrease)

 

    

2021

    

2020

    

Amount

    

Percent

 

Net revenues —

 

  

 

  

 

  

 

  

Well Intervention

$

133,768

$

140,652

$

(6,884)

 

(5)

%

Robotics

 

22,156

 

35,258

 

(13,102)

 

(37)

%

Production Facilities

 

16,447

 

15,541

 

906

 

6

%

Intercompany eliminations

 

(8,956)

 

(10,430)

 

1,474

 

  

$

163,415

$

181,021

$

(17,606)

 

(10)

%

Gross profit (loss) —

 

  

 

  

 

  

 

  

Well Intervention

$

8,726

$

(1,256)

$

9,982

 

795

%

Robotics

 

(933)

 

(467)

 

(466)

 

100

%

Production Facilities

 

7,213

 

4,207

 

3,006

 

71

%

Corporate, eliminations and other

 

(382)

 

(474)

 

92

 

  

$

14,624

$

2,010

$

12,614

 

628

%

Gross margin —

 

  

 

  

 

  

 

  

Well Intervention

 

7

%  

 

(1)

%  

 

  

 

Robotics

 

(4)

%  

 

(1)

%  

 

  

 

  

Production Facilities

 

44

%  

 

27

%  

 

  

 

  

Total company

 

9

%  

 

1

%  

 

  

 

  

��

Number of vessels or robotics assets (1) / Utilization (2)

 

  

 

  

 

  

 

  

Well Intervention vessels

 

7 / 70

%  

 

7 / 72

%  

 

  

 

  

Robotics assets (3)

 

47 / 24

%  

 

49 / 34

%  

 

  

 

  

Chartered robotics vessels

 

3 / 90

%  

 

6 / 89

%  

 

  

 

  

 Three Months Ended
September 30,
 
Increase/
(Decrease)
 2017 2016 
Net revenues —     
Well Intervention$111,522
 $108,287
 $3,235
Robotics47,049
 48,897
 (1,848)
Production Facilities16,380
 17,128
 (748)
Intercompany elimination(11,691) (13,067) 1,376
 $163,260
 $161,245
 $2,015
      
Gross profit (loss) —     
Well Intervention$20,642
 $28,174
 $(7,532)
Robotics(6,991) 4,953
 (11,944)
Production Facilities7,780
 8,413
 (633)
Corporate and other(489) (483) (6)
Intercompany elimination199
 (873) 1,072
 $21,141
 $40,184
 $(19,043)
      
Gross margin —     
Well Intervention19%
 26%
  
Robotics(15)%
 10%
  
Production Facilities47%
 49%
  
Total company13%
 25%
  
      
Number of vessels or robotics assets (1) / Utilization (2)
     
Well Intervention vessels5/88%
 5/76%
  
Robotics assets60/46%
 60/57%
  
Chartered robotics vessels5/80%
 3/81%
  
(1)Represents the number of vessels or robotics assets as of the end of the period, including spot vessels and those under long-term charter, and excluding acquired vessels prior to their in-service dates and vessels or assets disposed of and/or taken out of service prior to their disposition and vessels jointly owned with a third party.service.
(2)Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of available calendar days in the applicable period. The average utilization rates of chartered robotics vessels during the three-month periods ended March 31, 2021 and 2020 included three and 272 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.segments. Intercompany segment revenues are as follows (in thousands):

 Three Months Ended
September 30,
 
Increase/
(Decrease)
 2017 2016 
      
Well Intervention$3,765
 $2,898
 $867
Robotics7,926
 10,169
 (2,243)
 $11,691
 $13,067
 $(1,376)

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Three Months Ended

March 31, 

Increase/

    

2021

    

2020

    

(Decrease)

Well Intervention

$

2,587

$

3,304

$

(717)

Robotics

 

6,369

 

7,126

 

(757)

$

8,956

$

10,430

$

(1,474)

Net Revenues.Our totalconsolidated net revenues increased by 1% for the three-month period ended September 30, 2017March 31, 2021 decreased by 10% as compared to the same period in 2016. Increased2020, reflecting lower revenues for the three-month period in 2017 reflected higher revenues infrom our Well Intervention segment,and Robotics segments, offset in part by revenue decreases inhigher revenues from our Robotics and Production Facilities segments.segment.

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Our Well Intervention revenues increaseddecreased by 3%5% for the three-month period ended September 30, 2017March 31, 2021 as compared to the same period in 20162020, primarily reflecting revenues generated from our well intervention operations in Brazil, offset in part by operational downtime experienced by the Well Enhancerlower vessel utilization in the North Sea and $15.6 million we recognizedWest Africa during the quarter, offset in part by higher utilization in the third quarterGulf of 2016 associated with a work scope cancellation under a “take or pay” contract originally scheduled to be performed by the Q4000Mexico. Utilization in late 2016. In Brazil, the Siem Helix1 was 96% utilized during the third quarter of 2017. Our day rates improved in the third quarter as we addressed most of the items identified in the vessel acceptance process. In the North Sea, the Well Enhancer was 84% utilized during the third quarter of 2017 while the vessel was 91% utilized during the same period in 2016. The Seawell was 97% utilized during the third quarter of 2017 as compared to being 98% utilized during the same period in 2016. In the Gulf of Mexico the Q5000 was 75% utilized during the thirdfirst quarter of 2017 primarily2020 was lower due to 18 idle days duringour scheduled regulatory certification inspections for the off-hire period ofQ4000 and the BP contract. The vessel was 84% utilized during the same period in 2016. The Q4000 was 86% utilized during the third quarter of 2017 as compared to being 93% utilized during the same period in 2016.

Q5000.

Robotics revenues decreased by 4%37% for the three-month period ended September 30, 2017March 31, 2021 as compared to the same period in 2016. The decrease2020, primarily reflected lowerreflecting a reduction in vessel days as well as decreased utilization of our robotics assetsROVs and accepting work at reduced rates,ROVDrill, offset in part by an increase in trenching activities. Our results included 165 vessel days and 72 trenching days during the addition ofthree-month period ended March 31, 2021 as compared to 405 vessel days and 42 trenching days during the Grand Canyon III to our robotics fleet and 30 additional days of spot vessel utilizationsame period in the comparable quarter-over-quarter periods. Some of our ROV units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn.

2020.

Our Production Facilities revenues decreasedincreased by 4%6% for the three-month period ended September 30, 2017March 31, 2021 as compared to the same period in 2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017.

2020, primarily reflecting higher oil and gas production revenues.

Gross Profit (Loss).Our totalconsolidated gross profit decreasedincreased by 47%$12.6 million for the three-month period ended September 30, 2017March 31, 2021 as compared to the same period in 2016. The2020, primarily reflecting higher gross profit related to our Well Intervention segment decreased by 27% for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting the $15.6 million in third quarter 2016 revenues associated with a take-or-pay contract.

The gross profit associated with our Robotics segment decreased by 241% for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting decreased utilization for our robotics assets, accepting work with lower profit margins and increased vessel costs associated with the addition of the Grand Canyon III in May 2017.
The gross profit related to our Production Facilities segment decreased by 8% for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting revenue decreases for the HFRS.
Selling, General and Administrative Expenses.  Our selling, general and administrative expenses decreased by $2.3 million for the three-month period ended September 30, 2017 primarily attributable to a $2.7 million charge in the same period in 2016 that was associated with the provision for uncertain collection of a portion of our note receivable related to our Robotics segment.
Net Interest Expense.  Our net interest expense decreased by $3.2 million for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting a decrease in interest expense and an increase in capitalized interest. The decrease in interest expense was primarily attributable to a significant reduction in our debt levels including the $80 million principal reduction of our term loan in June 2017 (Note 6). Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $3.9 million for the three-month period ended September 30, 2017 as compared to $3.1 million for the same period in 2016.

35



Other Income (Expense), Net.  We reported other expense, net, of $0.6 million for the three-month period ended September 30, 2017 as compared to other income, net, of $0.8 million for the same period in 2016. Net other income (expense) for the three-month periods ended September 30, 2017 and 2016 included foreign currency transaction losses totaling $1.6 million and $0.5 million, respectively. Also included in the comparable quarter-over-quarter periods were net gains of $1.1 million and $1.3 million, respectively, associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 14).
Income Tax Provision (Benefit).  Income tax benefit was $1.5 million for the three-month period ended September 30, 2017 as compared to income tax provision of $3.6 million for the same period in 2016. The variance primarily reflected decreased profitability in the current year period. The effective tax rate was (204.9)% for the three-month period ended September 30, 2017 as compared to 24.1% for the same period in 2016. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions.
Comparison of Nine Months Ended September 30, 2017 and 2016 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
 Nine Months Ended
September 30,
 
Increase/
(Decrease)
 2017 2016 
Net revenues —     
Well Intervention$299,219
 $214,262
 $84,957
Robotics102,078
 119,805
 (17,727)
Production Facilities47,965
 54,567
 (6,602)
Intercompany elimination(31,145) (29,083) (2,062)
 $418,117
 $359,551
 $58,566
      
Gross profit (loss) —     
Well Intervention$47,757
 $17,195
 $30,562
Robotics(29,376) (12,008) (17,368)
Production Facilities21,031
 25,634
 (4,603)
Corporate and other(1,370) (1,367) (3)
Intercompany elimination641
 (542) 1,183
 $38,683
 $28,912
 $9,771
      
Gross margin —     
Well Intervention16%
 8%
  
Robotics(29)%
 (10)%
  
Production Facilities44%
 47%
  
Total company9%
 8%
  
      
Number of vessels or robotics assets (1) / Utilization (2)
     
Well Intervention vessels5/79%
 5/52%
  
Robotics assets60/42%
 60/48%
  
Chartered robotics vessels5/61%
 3/63%
  
(1)Represents number of vessels or robotics assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party.
(2)Represents average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period.

36



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)
 2017 2016 
      
Well Intervention$8,033
 $5,740
 $2,293
Robotics23,112
 23,343
 (231)
 $31,145
 $29,083
 $2,062
Net Revenues.  Our total net revenues increased by 16% for the nine-month period ended September 30, 2017 as compared to the same period in 2016. Increased revenues for the nine-month period in 2017 reflected higher revenues in our Well Intervention segment,and Production Facilities segments, offset in part by revenue decreaseshigher gross loss in our Robotics and Production Facilities segments.
Our Well Intervention revenues increased by 40% for the nine-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues generated from all of the well intervention vessels except for the Q4000. In Brazil, the Siem Helix1’s financial performance has improved since it commenced services for Petrobras in mid-April 2017, achieving year-to-date utilization of 96%. In the North Sea, the Well Enhancer was 81% utilized during the first nine months of 2017 while the vessel was 60% utilized during the same period in 2016. The Seawell was 84% utilized during the first nine months of 2017 whereas it was 41% utilized during the same period in 2016. In the Gulf of Mexico, the Q5000 was 88% utilized during the first nine months of 2017 as compared to being 56% utilized during the same period in 2016. The Q4000 was 77% utilized during the first nine months of 2017 as compared to being 97% utilized during the same period in 2016. Additionally in the third quarter of 2016, we recognized $15.6 million associated with a work scope cancellation under a contract containing “take or pay” provisions for 42 days of work originally scheduled to be performed by the Q4000 in late 2016.
Robotics revenues decreased by 15% for the nine-month period ended September 30, 2017 as compared to the same period in 2016. The decrease primarily reflected lower utilization of our robotics assets and accepting work at reduced rates. Some of our ROV units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn.
Our Production Facilities revenues decreased by 12% for the nine-month period ended September 30, 2017 as compared to the same period in 2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017 and lower revenues from the fixed fee agreement with the Phoenix field operator for the HP I that commenced June 1, 2016.
Gross Profit (Loss).  Our total gross profit increased by 34% for the nine-month period ended September 30, 2017 as compared to the same period in 2016. segment.

The gross profit related to our Well Intervention segment increased by 178%$10.0 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to the same period in 20162020, primarily reflecting higher revenues on the Q5000 and cost reduction efforts associated with lower utilization in ourthe North Sea region.

and West Africa during idle periods.

The gross profit associated withloss related to our Robotics segment decreasedincreased by 145%$0.5 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to the same period in 20162020, primarily reflecting decreased utilization for our robotics assets and accepting work with lower profit margins.

revenues, offset in part by lower operating costs.

The gross profit related to our Production Facilities segment decreasedincreased by 18%$3.0 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to the same period in 20162020, primarily reflecting revenue decreases forhigher oil and gas production revenues and a reduction in direct costs.

Goodwill Impairment. The $6.7 million charge in the HFRS andthree-month period ended March 31, 2020 reflects the HP I.


37



the entire goodwill balance, which related to our acquisition of a controlling interest in STL (Note 10).

Selling, General and Administrative Expenses.Our selling, general and administrative expenses decreased by $1.0were $15.2 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to the same period in 2016. The nine-month periods ended September 30, 2017 and 2016 included charges of $1.2 million and $2.7 million, respectively, that were associated with the provision for uncertain collection of a portion of our receivables related to our Robotics segment.

Net Interest Expense.  Our net interest expense decreased by $9.5 million for the nine-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting increases in interest income and capitalized interest and a decrease in interest expense. Interest income totaled $2.1 million for the nine-month period ended September 30, 2017 as compared to $1.7$16.3 million for the same period in 2016.2020, primarily reflecting lower credit loss reserves and lower employee compensation costs.

Net Interest on debt used to finance capital projects is capitalized and thus reduces overallExpense. Our net interest expense. Capitalized interestexpense totaled $12.6$6.1 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to $7.5$5.7 million for the same period in 2016. The decrease2020, primarily reflecting the cessation of interest capitalization with the completion of the Q7000 in interest expense was primarily attributable to a significant reduction in our debt levels including the $80 million principal reduction of our term loan in June 2017. Interestfirst quarter 2020. Net interest expense for the nine-month periods ended September 30, 2017 and 2016 also included charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments in our revolving credit facility were reduced (Note 6).

Gain (Loss) on Early Extinguishment of Long-Term Debt.  The $0.4 million loss for the nine-monththree-month period ended September 30, 2017 wasMarch 31, 2020 excluded $1.2 million in capitalized interest associated with the write-off of the unamortized debt issuance costs related to the lenders exiting from the term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatementQ7000 (Note 6)5). The $0.5 million gain for the nine-month period ended September 30, 2016 was associated with the repurchases totaling $14.9 million in aggregate principal amount of our 2032 Notes in June and July of 2016.

Other Income (Expense), Net.  We reportedNet other expense, net, of $0.6income was $1.6 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to net other income, net,expense of $4.0$10.4 million for the same period in 2016. Net other income (expense) for the nine-month periods ended September 30, 2017 and 2016 included2020, primarily reflecting foreign currency transaction gains (losses) of $(2.2) million and $0.5 million, respectively. Also included in the comparable year-over-year periods were net gains of $1.5 million and $3.5 million, respectively, associated with our foreign currency exchange contracts primarily reflecting gains relateddue to the contracts that were not designated as cash flow hedges (Note 14).

strengthening of the British pound.

Income Tax Benefit.Provision (Benefit). Income tax benefitprovision was $1.1$0.1 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to $9.9an income tax benefit of $21.1 million for the same period in 2016.2020. The variance primarily reflected aeffective tax rates for the three-month periods ended March 31, 2021 and 2020 were (4.0)% and 60.2%, respectively. The decrease in pretax loss in the current year period as well as a tax charge attributable to a change in tax position related to our foreign taxes. The effective tax rate was 5.2% forprimarily attributable to the nine-month period ended September 30, 2017 as compared to 26.7% forabsence of tax benefits derived from the CARES Act recorded in the same period in 2016. The variance was primarily attributablelast year, which included the carrying back of certain net operating losses to prior periods with higher income tax rates, as well as the result of the consolidation of certain U.S. branch operations with the Helix U.S. consolidated tax group and the earnings mix between our higher and lower tax rate jurisdictions and the change in tax position related to our foreign taxes (Note 7)6).


33

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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, 

December 31, 

    

2021

    

2020

Net working capital (1)

$

270,504

$

246,338

Long-term debt (1)

 

299,560

 

258,912

Liquidity (2)

 

376,992

 

451,532

 September 30,
2017
 December 31,
2016
    
Net working capital$268,817
 $336,387
Long-term debt (1)
$395,345
 $558,396
Liquidity (2)
$426,741
 $375,504
(1)Long-term debt does not include the currentCurrent maturities portion of our long-term debt as that amount isof $36.5 million and $90.7 million, respectively, are included in net working capital. Itcapital and excluded from long-term debt. Long-term debt as of March 31, 2021 is also net of unamortized debt discountissuance costs. Long-term debt as of December 31, 2020 is net of unamortized debt discounts and debt issuance costs. See Note 65 for information relating to our existing debt.long-term debt, including the impact of our adoption of ASU No. 2020-06.
(2)Liquidity, as defined by us, is equal to cash and cash equivalents, excluding restricted cash, plus available capacity under ourthe Revolving Credit Facility, which capacity is reduced by letters of credit drawn against the facility.Facility. Our liquidity at September 30, 2017March 31, 2021 included cash and cash equivalents of $356.9$204.8 million (including $100 million of minimum cash balance required by our Credit Agreement) and $69.9$172.2 million of available borrowing capacity under ourthe Revolving Credit Facility (Note 6)5). Our liquidity at March 31, 2021 excluded $65.6 million of restricted cash securing a project related letter of credit (short-term), the restriction from which is expected to be released upon completion of the project. Our liquidity at December 31, 20162020 included cash and cash equivalents of $356.6$291.3 million and $18.9$160.2 million of available borrowing capacity under ourthe Revolving Credit Facility.

The carrying amountamounts of our long-term debt including current maturities, net of unamortized debt discount and debt issuance costs, isare as follows (in thousands):

March 31, 

December 31, 

    

2021

    

2020

Term Loan (matures December 2021)

$

28,732

$

29,559

Nordea Q5000 Loan (matured January 2021) (1)

 

 

53,532

MARAD Debt (matures February 2027)

 

49,749

 

53,361

2022 Notes (mature May 2022) (2)

 

34,794

 

33,477

2023 Notes (mature September 2023) (2)

 

29,555

 

26,922

2026 Notes (mature February 2026) (2)

 

193,208

 

152,712

Total debt (3)

336,038

349,563

Less current maturities

(36,478)

(90,651)

Long-term debt

$

299,560

$

258,912

 September 30,
2017
 December 31,
2016
    
Term Loan (previously scheduled to mature June 2018)$
 $190,867
Nordea Q5000 Loan (matures April 2020)167,667
 193,879
Term Loan (matures June 2020)96,935
 
MARAD Debt (matures February 2027)72,365
 78,221
2022 Notes (mature May 2022) (1)
108,018
 105,697
2032 Notes (mature March 2032) (2)
58,971
 57,303
Total debt$503,956
 $625,967
(1)The 2022 Notes will increase to their face amount through accretion of non-cash interest charges through May 1, 2022.Nordea Q5000 Loan was fully repaid upon maturity in January 2021 (Note 5).
(2)The 2032As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount associated with the 2022 Notes, will increase to their face amount through accretionthe 2023 Notes and the 2026 Notes (Note 1).
(3)Amounts include current maturities and are net of non-cash interest charges through March 15, 2018, which is the first date on which the holders may require us to repurchase the notes.any unamortized debt discounts and debt issuance costs.

The following table provides summary data from our condensed consolidated statements of cash flows (in thousands):

Three Months Ended

March 31, 

    

2021

    

2020

Cash provided by (used in):

 

  

 

Operating activities

$

39,869

$

(17,222)

Investing activities

 

(1,329)

 

(12,389)

Financing activities

 

(59,885)

 

(18,391)

34

 Nine Months Ended
September 30,
 2017 2016
Cash provided by (used in):   
Operating activities$31,323
 $15,444
Investing activities$(121,428) $(42,266)
Financing activities$88,420
 $17,217

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Our current requirements for cash primarily reflect the need to fund our operations and capital spending for our current lines of business and to service our debt. Historically,

The ongoing COVID-19 pandemic, challenging market conditions and industry-wide spending cuts have impacted our revenues and we have fundedexpect these events to continue to impact our capital program withresults into the near future. Our operating cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives.

As a further responseare impacted to the industry-wide spending reductions,extent we cannot replace those revenues or reduce costs. Despite these challenges, we remain even more focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, deferWe have reduced, deferred or cancelcancelled certain planned capital expenditures.expenditures and reduced our overall cost structure commensurate with our level of activities. In 2020, we extended our debt maturity profile with refinancing a portion of our 2022 Notes and 2023 Notes in favor of the 2026 Notes. Notwithstanding, we have at the same time continued to de-lever our balance sheet with the repayment of our Nordea Q5000 Loan in January 2021. We have reduced operating costs through various measures including warm stacking our vessels when idle. These costs should return with increases in activity. 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 and service our debt over at least the next 12 months.
In accordance with

The ongoing COVID-19 pandemic and its impact on the energy and financial markets have contributed to rising yields on our Credit Agreement,existing debt as well as volatility in our stock price, both of which increase our cost of capital. The yield on the 2026 Notes is significantly higher than that of the 2022 Notes the 2032 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required2023 Notes. The COVID-19 pandemic has also contributed to comply withlimited access to certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. Our 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 our MARAD Debt and our Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. Our Credit Agreement also permits our Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as defined in our Credit Agreement). As of September 30, 2017 and December 31, 2016, we were in compliance with all of the covenants in our long-term debt agreements.

A prolongedmarkets.

An ongoing period of weak, or continued decreases in, industry activity may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt. Furthermore, during any perioddebt, and our failure to comply with these covenants and other restrictions could lead to an event of sustained weak economic activitydefault. Current global and reducedmarket conditions have increased the potential for that difficulty and are expected to negatively impact the terms on which we secure a replacement of, or our lenders’ willingness to continue to participate in, our credit facility, which expires December 2021. Decreases in our revenues and EBITDA, including as may be attributable to the fallout from the ongoing COVID-19 pandemic, may also limit our ability to fully access ourthe Revolving Credit Facility may be impacted.Facility. At September 30, 2017,March 31, 2021, our available borrowing capacity under ourthe Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $69.9$172.2 million, net of $4.0$2.8 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrowdo not anticipate borrowing under ourthe Revolving Credit Facility other than for issuancesthe 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. If we fail to comply with these covenants and other restrictions, that failure 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 up to $25 million under our Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding our Credit Agreement, including covenants and collateral.
The 2022 Notes and the 2032 Notes can be converted into our common stock prior to their stated maturity upon certain triggering events specified in the applicable Indenture governing the notes. The holders of the remaining 2032 Notes may require us to repurchase these notes in March 2018. Accordingly, the 2032 Notes are classified as current liabilities on our consolidated balance sheet at September 30, 2017. No conversion triggers were met during the nine-month periods ended September 30, 2017 and 2016.

Operating Cash Flows

Total

Net cash flows fromprovided by operating activities increased by $15.9were $39.9 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 as compared to net cash flows used by operating activities of $17.2 million for the same period in 2016. This2020. The $57.1 million increase wasin operating cash flows primarily attributable to improvementsreflects lower operating loss and decreases in our operating results.

working capital.

Investing Activities

Capital expenditures consistrepresent cash paid principally offor 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 (uses) sources (uses) of cash associated with investing activities are as follows (in thousands):


40


Table of Contents

 Nine Months Ended
September 30,
 2017 2016
Capital expenditures:   
Well Intervention$(130,649) $(79,147)
Robotics(691) (504)
Production Facilities
 (74)
Other(88) 372
Distribution from equity investment
 1,200
Proceeds from sale of equity investment (1)

 25,000
Proceeds from sale of assets (2)
10,000
 10,887
Net cash used in investing activities$(121,428) $(42,266)
(1)Amount in 2016 reflected cash received from the sale of our former ownership interest in Deepwater Gateway (Note 5).
(2)Amount in 2017 reflected cash received from the sale of our Ingleside spoolbase (Note 3). Amount in 2016 reflected cash received from the sale of our office and warehouse property located in Aberdeen, Scotland.
Capital

Three Months Ended

March 31, 

    

2021

    

2020

Capital expenditures:

 

  

 

Well Intervention

$

(1,259)

$

(12,263)

Robotics

 

 

(44)

Production Facilities

 

(70)

 

Other

 

 

(82)

Net cash used in investing activities

$

(1,329)

$

(12,389)

Our capital expenditures associated with our businessduring the three-month period ended March 31, 2020 primarily have included payments associated with the construction and completion of our Q7000 vessel (see below) and the investment in the topside well intervention equipment for the Siem Helix 1 and Siem Helix 2 vessels chartered to perform our agreements with Petrobras (see below).

In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000 for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being built to North Sea standards. This $346.0 million shipyard contract represents the majoritycommenced operations in January 2020.

35

Table of the expected costs associated with the construction of the Q7000. Pursuant to the original contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% is to be paid upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% is to be paid upon the delivery of the vessel, which at our option can be deferred until December30, 2018. We agreed to pay the shipyard its incremental costs in connection with the contract amendments to extend the scheduled delivery of the Q7000 and to defer certain payment obligations. At September 30, 2017, our total investment in the Q7000 was $213.6 million, including $138.4 million of installment payments to the shipyard. We plan to incur approximately $77 million of costs related to the construction of the Q7000 over the remainder of 2017.Contents

In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem for two newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2. The Siem Helix 1 commenced its operations for Petrobras in mid-April 2017. We currently expect the Siem Helix 2 to be in service for Petrobras late in the fourth quarter of 2017. We have invested $304.1 million as of September 30, 2017 and plan to invest approximately $9 million in the topside equipment over the remainder of 2017.

Financing Activities

Cash flows from financing activities consist primarily of proceeds from debt and equity financing activities and repayments ofrelated to our long-term debt. TotalNet cash flowsoutflows from financing activities increased by $71.2of $59.9 million for the nine-monththree-month period ended September 30, 2017March 31, 2021 primarily reflect the repayment of $58.2 million of scheduled maturities related to our indebtedness, including the final maturity of $53.6 million of our Nordea Q5000 Loan (Note 5). Net cash outflows from financing activities of $18.4 million for the three-month period ended March 31, 2020 primarily reflect the repayment of $13.4 million of our indebtedness (Note 5).

Free Cash Flow

Free cash flow increased by $68.2 million for the three-month period ended March 31, 2021 as compared to the same period in 20162020. The increase was primarily reflecting net proceeds of approximately $220 million we received from our underwritten public equity offeringattributable to the increase in January 2017 (Note 8) and the $100 million proceeds from our Term Loan borrowings in June 2017, offset in part by early repayment of the approximately $180 million term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement (Note 6) and net proceeds of approximately $95 million we received in the nine-month period ended September 30, 2016 from the sale of our common stock under at-the-market equity offering programs.


41



Outlook 
We anticipate that our capital expenditures and deferred dry dock costs for 2017 will approximate $245 million. We believe that our cash on hand, internally generatedoperating cash flows and availability under our Revolving Credit Facility will provide the decrease in capital necessary to continue funding our 2017 capital spending. Our estimateexpenditures.

Free cash flow is a non-GAAP financial measure. See “RESULTS OF OPERATIONS” above for the definition and calculation 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.

free cash flow.

Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of September 30, 2017March 31, 2021 and the scheduled years in which the obligations are contractually due (in thousands):

Less Than

More Than

    

Total (1)

    

1 Year

    

1-3 Years

    

3-5 Years

    

5 Years

Term Loan

$

28,875

$

28,875

$

$

$

MARAD debt

 

52,676

 

7,746

 

16,672

 

18,377

 

9,881

2022 Notes (2)

 

35,000

 

 

35,000

 

 

2023 Notes (3)

 

30,000

 

 

30,000

 

 

2026 Notes (4)

 

200,000

 

 

 

200,000

 

Interest related to debt (5)

 

80,319

 

20,126

 

32,621

 

27,285

 

287

Property and equipment

 

6,184

 

6,078

 

106

 

 

Operating leases (6)

 

242,043

 

97,752

 

134,611

 

5,796

 

3,884

Total cash obligations

$

675,097

$

160,577

$

249,010

$

251,458

$

14,052

 
Total (1)
 
Less Than
1 Year
 1-3 Years 3-5 Years 
More Than
5 Years
          
Term Loan$98,750
 $6,250
 $92,500
 $
 $
Nordea Q5000 Loan169,643
 35,714
 133,929
 
 
MARAD Debt77,000
 6,532
 14,058
 15,497
 40,913
2022 Notes (2)
125,000
 
 
 125,000
 
2032 Notes (3)
60,115
 60,115
 
 
 
Interest related to debt (4)
78,706
 23,411
 35,804
 14,614
 4,877
Property and equipment (5)
262,626
 113,149
 149,477
 
 
Operating leases (6)
694,257
 140,345
 250,424
 207,824
 95,664
Total cash obligations$1,566,097
 $385,516
 $676,192
 $362,935
 $141,454
(1)Excludes unsecured letters of credit outstanding at September 30, 2017March 31, 2021 totaling $4.0$2.8 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 130% of their issuance price on that 30th trading day (i.e., $18.06 per share). At September 30, 2017, the conversion trigger was not met. See Note 65 for additional information.
(3)Notes mature March 2032. The 2032 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 130% of their issuance price on that 30th trading day (i.e., $32.53 per share). At September 30, 2017, the conversion trigger was not met. The first date that the holders of these notes may require us to repurchase the notes is March 15, 2018.2023. See Note 65 for additional information.
(4)Notes mature in February 2026. See Note 5 for additional information.
(5)Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at September 30, 2017March 31, 2021 for variable rate debt.
(5)
Primarily reflects costs associated with our Q7000 semi-submersible well intervention vessel currently under construction and the topside equipment for the Siem Helix 2 chartered vessel (Note 12).
(6)
Operating leases include vessel charters and facility and equipment leases. At September 30, 2017,March 31, 2021, our commitment related to long-term vessel charter commitmentscharters totaled approximately $652.3$215.8 million, includingof which $86.9 million was related to the Grand Canyon IIInon-lease (services) components that went into service for usare not included in May 2017, the Siem Helix 1, which commenced operations for Petrobras in mid-April 2017, and the Siem Helix 2, which we currently expect to be in service for Petrobras lateoperating lease liabilities in the fourth quartercondensed consolidated balance sheet as of 2017.
March 31, 2021.

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CRITICAL ACCOUNTING POLICIESESTIMATES AND ESTIMATES

POLICIES

Our discussion and analysis of our financial condition and results of operations, are based upon ouras reflected in the condensed consolidated financial statements. We prepare these financial statements and related footnotes, are prepared 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 additional information regarding our critical accounting policiesestimates and estimates,policies, please read our “Critical Accounting PoliciesEstimates and Estimates”Policies” as disclosed in our 20162020 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are currently

As of March 31, 2021, we were exposed to market risk in two areas:risks associated with interest rates and foreign currency exchange rates.

Interest Rate Risk.As of September 30, 2017, $268.4March 31, 2021, $28.9 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may 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 $187.5 million of our Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. 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 $1.5$0.1 million in interest expense for the nine-monththree-month period ended September 30, 2017.

March 31, 2021.

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 subject toimpacted by movements in foreign currency exchange rates when (i) transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency of the relevant Helix entity or (ii) the functional currency of our subsidiaries which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the United States,U.S., we generallyendeavor to 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 are denominated, and provide for collections from customers, in U.S. dollars. During

Assets and liabilities of our subsidiaries that do not have the nine-monthU.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our condensed consolidated balance sheets. For the three-month period ended September 30, 2017,March 31, 2021, we recognized losses of $2.2 million related torecorded foreign currency transactionstranslation gains of $4.6 million to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments since we consider our undistributed earnings (when applicable) of our non-U.S. subsidiaries without operations in the U.S. to be permanently reinvested.

When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the condensed consolidated statements of operations as a component of “Other income (expense), net” in our condensed consolidated statement of operations.

Our cash flows are subject to fluctuations resulting from changes innet.” For the three-month period ended March 31, 2021, we recorded foreign currency exchange rates. Fluctuations in exchange rates are likely to impact our resultstransaction gains of operations and cash flows. As a result, we entered into various foreign currency exchange contracts to stabilize expected cash outflows$1.6 million, primarily related to certain vessel charters denominatedour subsidiaries in Norwegian kroners. In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and Grand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. In December 2015, we re-designated the hedging relationship between a portion of our foreign currency exchange contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring (Note 14). The foreign currency exchange contracts associated with the Grand Canyon charter payments and the re-designated contracts associated with the Grand Canyon II and Grand Canyon III charter payments currently qualify for cash flow hedge accounting treatment. There was no foreign currency hedge ineffectiveness for the nine-month period ended September 30, 2017.

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U.K.

37

Table of Contents


Item 4.Controls and Procedures

(a)  Evaluation of disclosure controls and procedures. Our management, with the participation of our principal executive officer and principal financial officer, has evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act, as of September 30, 2017.March 31, 2021. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, 2017March 31, 2021 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(b)Changes in internal control over financial reporting. There have been no changes in our internal control over financial reporting that occurred during the quarter ended September 30, 2017March 31, 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.


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Table of Contents

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 12 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

Issuer Purchases of Equity Securities

(c)

Total number

(d)

of shares

Maximum

(a)

(b)

purchased as

number of shares

Total number

Average

part of publicly

that may yet be

of shares

price paid

announced

purchased under

Period

    

purchased (1)

    

per share

    

program

    

the program (2)

January 1 to January 31, 2021

 

447,139

$

4.43

 

 

7,734,655

February 1 to February 28, 2021

 

 

 

 

7,734,655

March 1 to March 31, 2021

 

 

 

 

7,734,655

 

447,139

$

4.43

 

Period
(a)
Total number
of shares
purchased
(b)
Average
price paid
per share
(c)
Total number
of shares
purchased as
part of publicly
announced
program
(d)
Maximum
number of shares
that may yet be
purchased under
the program (1)
July 1 to July 31, 2017
$

3,079,889
August 1 to August 31, 2017


3,079,889
September 1 to September 30, 2017


3,108,697

$

(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 ofwe may repurchase shares to members of our Boardcommon stock in an amount equal to any equity granted to our employees, officers and to certain employees,directors under our share-based compensation plans, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our ESPP (Note 9), and such shares increase the ESPP to participating employees (Note 10), increases the amountnumber of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 1011 to our 20162020 Form 10-K.

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Table of Contents

Item 6. Exhibits

Exhibit Number

Description

Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)

3.1

Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)

3.2

Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)

31.1

Filed herewith

31.2

Filed herewith

32.1

Furnished herewith

101.INS

XBRL Instance Document.

Filed herewith

The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document

101.SCH

Inline XBRL Taxonomy Extension Schema Document.

Filed herewith

101.CAL

Inline XBRL Taxonomy Extension Calculation Linkbase Document.

Filed herewith

101.PRE

101.DEF

Inline XBRL Taxonomy Extension Definition Linkbase Document.

Filed herewith

101.LAB

Inline XBRL Taxonomy Extension Label Linkbase Document.

Filed herewith

101.PRE

Inline XBRL Taxonomy Extension Presentation Linkbase Document.

Filed herewith

101.DEF

104

Cover Page Interactive Data File (formatted as inline XBRL Definition Linkbase Document.and contained in Exhibit 101).

Filed herewith

101.LABXBRL Label Linkbase Document.Filed herewith



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39


SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

HELIX ENERGY SOLUTIONS GROUP, INC.

(Registrant)

Date:

October 24, 2017

By: 

(Registrant)

Date: April 28, 2021

By:

/s/ Owen Kratz

Owen Kratz

President and Chief Executive Officer

(Principal Executive Officer)

Date: April 28, 2021

October 24, 2017

By:

By: 

/s/ Erik Staffeldt

Erik Staffeldt

Senior

Executive Vice President and

Chief Financial Officer

(Principal Financial Officer)


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