UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q



þ☑		~~Quarterly report pursuant to Section~~QUARTERLY REPORT PURSUANT TO SECTION 13 orOR 15(d) ~~of the Securities Exchange Act of~~OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, ~~2017~~2019



¨☐		~~Transition report pursuant to Section~~TRANSITION REPORT PURSUANT TO SECTION 13 orOR 15(d) ~~of the Securities Exchange Act of~~OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from__________ to__________

Commission File ~~Number~~ Number: 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)



Minnesota		95-3409686
(State or other jurisdiction of incorporation or organization)		~~95–3409686~~ (I.R.S. Employer Identification No.)

3505 West Sam Houston Parkway North
Suite 400
Houston	Texas	77043
(Address of principal executive offices)		~~77043~~ (Zip Code)

~~(281)~~ (281) 618–0400

(Registrant's telephone number, including area code)

NOT APPLICABLE

(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:



Title of each 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 filerþ	☑	Accelerated filer ☐	~~Accelerated filer~~ ¨	Non-accelerated filer ¨☐	Smaller reporting company¨	☐	Emerging growth company¨
		~~(Do not check if a smaller reporting company)~~			☐

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

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

As of October ~~20, 2017, 147,720,399~~18, 2019, 148,809,467 shares of common stock were outstanding.

TABLE OF CONTENTS



PART I.	FINANCIAL INFORMATION	PAGE

Item 1.	Financial Statements:

	Condensed Consolidated Balance Sheets – September 30, ~~2017~~2019 (Unaudited) and December 31, ~~2016~~2018	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018	4

	Condensed Consolidated Statements of ~~Operations~~Comprehensive Income (Unaudited) – ~~Nine~~Three and nine months ended September 30, ~~2017~~2019 and ~~2016~~2018	5

	Condensed Consolidated Statements of ~~Comprehensive Income (Loss)~~Shareholders’ Equity (Unaudited) – Three ~~and nine~~ months ended September 30, ~~2017~~2019 and ~~2016~~2018	6

	Condensed Consolidated Statements of ~~Cash Flows~~Shareholders’ Equity (Unaudited) – Nine months ended September 30, ~~2017~~2019 and ~~2016~~2018	7

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine months ended September 30, 2019 and 2018	8

	Notes to Condensed Consolidated Financial Statements (Unaudited)	89

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	2931

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	4345

Item 4.	Controls and Procedures	4445

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	45

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	4546

Item 6.	Exhibits	4546

	Signatures	4647

Table of Contents

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			September 30, 2019			December 31, 2018
	(Unaudited)						(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	356,889		$	356,647		$	286,340		$	279,459
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively	90,480			101,825
Unbilled revenue and other	45,816			10,328
Current deferred tax assets	—			16,594
Trade, net of allowance for uncollectible accounts of $0							91,707			67,932
Unbilled and other							72,548			51,943
Other current assets	38,172			37,388			61,751			51,594
Total current assets	531,357			522,782			512,346			450,928
Property and equipment	2,612,407			2,450,890			2,819,932			2,785,778
Less accumulated depreciation	(878,248		)	(799,280		)	(1,022,138		)	(959,033		)
Property and equipment, net	1,734,159			1,651,610			1,797,794			1,826,745
Operating lease right-of-use assets							213,048			—
Other assets, net	100,974			72,549			90,323			70,057
Total assets	$	2,366,490		$	2,246,941		$	2,613,511		$	2,347,730

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	91,412		$	60,210		$	79,122		$	54,813
Accrued liabilities	60,761			58,614			71,982			85,594
Income tax payable	1,756			—			—			3,829
Current maturities of long-term debt	108,611			67,571			108,468			47,252
Current operating lease liabilities							52,840			—
Total current liabilities	262,540			186,395			312,412			191,488
Long-term debt	395,345			558,396			304,932			393,063
Operating lease liabilities							164,761			—
Deferred tax liabilities	154,158			167,351			110,118			105,862
Other non-current liabilities	42,736			52,985			39,008			39,538
Total liabilities	854,779			965,127			931,231			729,951
Commitments and contingencies
Redeemable noncontrolling interests							3,257			—
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 147,713 and 120,630 shares issued, respectively	1,281,747			1,055,934
Common stock, no par, 240,000 shares authorized, 148,802 and 148,203 shares issued, respectively							1,316,805			1,308,709
Retained earnings	302,326			322,854			437,418			383,034
Accumulated other comprehensive loss	(72,362		)	(96,974		)	(75,200		)	(73,964		)
Total shareholders’ equity	1,511,711			1,281,814			1,679,023			1,617,779
Total liabilities and shareholders’ equity	$	2,366,490		$	2,246,941
Total liabilities, redeemable noncontrolling interests and shareholders’ equity							$	2,613,511		$	2,347,730

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

(in thousands, except per share amounts)


	Three Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2019			2018			2019			2018

Net revenues	$	163,260		$	161,245		$	212,609		$	212,575		$	581,160		$	581,462
Cost of sales	142,119			121,061			157,535			160,582			469,898			473,589
Gross profit	21,141			40,184			55,074			51,993			111,262			107,873
Gain on disposition of assets, net							—			146			—			146
Selling, general and administrative expenses	(16,374		)	(18,714		)	(16,076		)	(20,762		)	(48,923		)	(52,986		)
Income from operations	4,767			21,470			38,998			31,377			62,339			55,033
Equity in losses of investment	(153		)	(122		)	(13		)	(107		)	(82		)	(378		)
Net interest expense	(3,615		)	(6,843		)	(1,901		)	(3,249		)	(6,204		)	(10,744		)
Gain on early extinguishment of long-term debt	—			244
Other income (expense), net	(551		)	830
Other income (expense) – oil and gas	303			(468		)
Loss on extinguishment of long-term debt							—			(2		)	(18		)	(1,183		)
Other expense, net							(2,285		)	(709		)	(2,430		)	(3,225		)
Royalty income and other							362			652			2,897			4,068
Income before income taxes	751			15,111			35,161			27,962			56,502			43,571
Income tax provision (benefit)	(1,539		)	3,649
Income tax provision							3,539			841			6,739			1,226
Net income	$	2,290		$	11,462		31,622			27,121			49,763			42,345
Net loss attributable to redeemable noncontrolling interests							(73		)	—			(104		)	—
Net income attributable to common shareholders							$	31,695		$	27,121		$	49,867		$	42,345

Earnings per share of common stock:
Basic	$	0.02		$	0.10		$	0.21		$	0.18		$	0.33		$	0.29
Diluted	$	0.02		$	0.10		$	0.21		$	0.18		$	0.33		$	0.29

Weighted average common shares outstanding:
Basic	145,958			113,680			147,575			146,700			147,506			146,679
Diluted	145,958			113,680			148,354			146,964			148,086			146,761

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~COMPREHENSIVE INCOME

(UNAUDITED)

(in ~~thousands, except per share amounts)~~thousands)

Nine Months Ended
September 30,
2017 2016

Net revenues $ 418,117
$ 359,551
Cost of sales 379,434
330,639
Gross profit 38,683
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 gas 3,196
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:
Basic 145,057
109,135
Diluted 145,057
109,135



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

Net income	$	31,622		$	27,121		$	49,763		$	42,345
Other comprehensive loss, net of tax:
Net unrealized gain (loss) on hedges arising during the period	(274		)	(88		)	(701		)	839
Reclassifications to net income	1,046			1,799			4,867			5,233
Income taxes on hedges	(156		)	(357		)	(838		)	(1,298		)
Net change in hedges, net of tax	616			1,354			3,328			4,774
Unrealized loss on note receivable arising during the period	—			—			—			(629		)
Income taxes on note receivable	—			—			—			132
Unrealized loss on note receivable, net of tax	—			—			—			(497		)
Foreign currency translation loss	(4,301		)	(1,421		)	(4,564		)	(4,277		)
Other comprehensive loss, net of tax	(3,685		)	(67		)	(1,236		)	—
Comprehensive income	27,937			27,054			48,527			42,345
Less comprehensive loss attributable to redeemable noncontrolling interests:
Net loss	(73		)	—			(104		)	—
Foreign currency translation loss	(78		)	—			(78		)	—
Comprehensive loss attributable to redeemable noncontrolling interests	(151		)	—			(182		)	—
Comprehensive income attributable to common shareholders	$	28,088		$	27,054		$	48,709		$	42,345

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

Table of Contents

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 period 2,297
4,418
Reclassification adjustments for loss on hedges included in net income 3,383
3,157
Income taxes on unrealized gain on hedges (1,992 ) (2,683 )
Unrealized gain on hedges, net of tax 3,688
4,892
Foreign currency translation gain (loss) 5,513
(3,611 )
Other comprehensive income, net of tax 9,201
1,281
Comprehensive income $ 11,491
$ 12,743



	Common Stock			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests
	Shares	Amount		Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests

Balance, June 30, 2019	148,759	$	1,314,163	$	405,748		$	(71,515	)	$	1,648,396		$	3,383
Net income (loss)	—	—		31,695			—			31,695			(73		)
Foreign currency translation adjustments	—	—		—			(4,301		)	(4,301		)	(78		)
Unrealized gain on hedges, net of tax	—	—		—			616			616			—
Accretion of redeemable noncontrolling interests	—	—		(25		)	—			(25		)	25
Activity in company stock plans, net and other	43	214		—			—			214			—
Share-based compensation	—	2,428		—			—			2,428			—
Balance, September 30, 2019	148,802	$	1,316,805	$	437,418		$	(75,200	)	$	1,679,023		$	3,257

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 period 4,141
5,450
Reclassification adjustments for loss on hedges included in net loss 10,822
9,651
Income taxes on unrealized gain on hedges (5,256 ) (5,236 )
Unrealized gain on hedges, net of tax 9,707
9,865
Foreign currency translation gain (loss) arising during the period 14,905
(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 tax 24,612
(14,673 )
Comprehensive income (loss) $ 4,084
$ (41,705 )



	Common Stock				Retained Earnings		Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests
	Shares	Amount			Retained Earnings		Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests

Balance, June 30, 2018	148,107	$	1,303,984		$	369,659	$	(71,249	)	$	1,602,394		$	—
Net income	—	—			27,121		—			27,121			—
Foreign currency translation adjustments	—	—			—		(1,421		)	(1,421		)	—
Unrealized gain on hedges, net of tax	—	—			—		1,354			1,354			—
Equity component of debt discount on convertible senior notes	—	(2		)	—		—			(2		)	—
Activity in company stock plans, net and other	40	213			—		—			213			—
Share-based compensation	—	2,509			—		—			2,509			—
Balance, September 30, 2018	148,147	$	1,306,703		$	396,781	$	(71,316	)	$	1,632,168		$	—

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)



	Common Stock				Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests
	Shares	Amount			Retained Earnings			Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests

Balance, December 31, 2018	148,203	$	1,308,709		$	383,034		$	(73,964	)	$	1,617,779		$	—
Net income (loss)	—	—			49,867			—			49,867			(104		)
Reclassification of deferred gain from sale and leaseback transaction to retained earnings	—	—			4,560			—			4,560			—
Foreign currency translation adjustments	—	—			—			(4,564		)	(4,564		)	(78		)
Unrealized gain on hedges, net of tax	—	—			—			3,328			3,328			—
Issuance of redeemable noncontrolling interests	—	—			—			—			—			3,396
Accretion of redeemable noncontrolling interests	—	—			(43		)	—			(43		)	43
Activity in company stock plans, net and other	599	(765		)	—			—			(765		)	—
Share-based compensation	—	8,861			—			—			8,861			—
Balance, September 30, 2019	148,802	$	1,316,805		$	437,418		$	(75,200	)	$	1,679,023		$	3,257



	Common Stock				Retained Earnings		Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests
	Shares	Amount			Retained Earnings		Accumulated Other Comprehensive Loss			Total Shareholders’ Equity			Redeemable Noncontrolling Interests

Balance, December 31, 2017	147,740	$	1,284,274		$	352,906	$	(69,787	)	$	1,567,393		$	—
Net income	—	—			42,345		—			42,345			—
Reclassification of stranded tax effect to retained earnings	—	—			1,530		(1,530		)	—			—
Foreign currency translation adjustments	—	—			—		(4,277		)	(4,277		)	—
Unrealized gain on hedges, net of tax	—	—			—		4,774			4,774			—
Unrealized loss on note receivable, net of tax	—	—			—		(497		)	(497		)	—
Equity component of debt discount on convertible senior notes	—	15,411			—		—			15,411			—
Activity in company stock plans, net and other	407	(438		)	—		—			(438		)	—
Share-based compensation	—	7,456			—		—			7,456			—
Balance, September 30, 2018	148,147	$	1,306,703		$	396,781	$	(71,316	)	$	1,632,168		$	—

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

Table of Contents

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

(in thousands)


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2019			2018
Cash flows from operating activities:
Net loss	$	(20,528	)	$	(27,032	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Net income							$	49,763		$	42,345
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	82,670			84,846			84,420			83,339
Amortization of debt discount	3,487			4,655
Amortization of debt discounts							4,642			4,238
Amortization of debt issuance costs	5,238			6,430			2,752			2,703
Share-based compensation	7,613			4,351			8,979			7,569
Deferred income taxes	(3,019		)	(6,726		)	2,347			(5,716		)
Equity in losses of investment	457			366			82			378
Loss on disposition of assets, net	39			—
(Gain) loss on early extinguishment of long-term debt	397			(546		)
Unrealized gain and ineffectiveness on derivative contracts, net	(4,291		)	(9,282		)
Changes in operating assets and liabilities:
Gain on disposition of assets, net							—			(146		)
Loss on extinguishment of long-term debt							18			1,183
Unrealized gain on derivative contracts, net							(2,351		)	(2,289		)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable, net	(21,709		)	(27,346		)	(45,399		)	(15,769		)
Other current assets	(12,145		)	(10,853		)	12,215			(5,662		)
Income tax receivable	2,742			20,576
Income tax payable, net of income tax receivable							(3,143		)	2,963
Accounts payable and accrued liabilities	30,675			(1,794		)	(14,765		)	6,968
Other non-current, net	(40,303		)	(22,201		)
Other, net							(9,683		)	28,723
Net cash provided by operating activities	31,323			15,444			89,877			150,827

Cash flows from investing activities:
Capital expenditures	(131,428		)	(79,353		)	(45,636		)	(55,431		)
Distribution from equity investment	—			1,200
Proceeds from sale of equity investment	—			25,000
STL acquisition, net							(4,081		)	—
Proceeds from sale of assets	10,000			10,887			2,550			25
Net cash used in investing activities	(121,428		)	(42,266		)	(47,167		)	(55,406		)

Cash flows from financing activities:
Issuance of Convertible Senior Notes due 2023							—			125,000
Repurchase of Convertible Senior Notes due 2032							—			(60,365		)
Proceeds from term loan	100,000			—			35,000			—
Repayment of term loan	(193,508		)	(30,500		)	(34,567		)	(62,872		)
Repayment of Nordea Q5000 Loan	(26,786		)	(26,786		)	(26,786		)	(26,786		)
Repayment of MARAD Debt	(6,222		)	(5,926		)	(6,858		)	(6,532		)
Repurchase of Convertible Senior Notes due 2032	—			(13,400		)
Debt issuance costs	(3,694		)	(1,230		)	(1,544		)	(3,867		)
Net proceeds from issuance of common stock	219,504			94,538
Payments related to tax withholding for share-based compensation	(1,306		)	(187		)	(1,345		)	(1,058		)
Proceeds from issuance of ESPP shares	432			708			462			506
Net cash provided by financing activities	88,420			17,217
Net cash used in financing activities							(35,638		)	(35,974		)

Effect of exchange rate changes on cash and cash equivalents	1,927			(2,481		)	(191		)	(947		)
Net increase (decrease) in cash and cash equivalents	242			(12,086		)
Net increase in cash and cash equivalents							6,881			58,500
Cash and cash equivalents:
Balance, beginning of year	356,647			494,192			279,459			266,592
Balance, end of period	$	356,889		$	482,106		$	286,340		$	325,092

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation and New Accounting Standards

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, ~~“Helix” or the “Company”)~~Helix). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements have been prepared pursuant to instructions for the Quarterly Report on Form 10-Q required to be filed with the Securities and Exchange Commission (the “SEC”), and do not include all information and footnotes normally included in annual financial statements prepared in accordance with U.S. generally accepted accounting principles (“~~U.S.~~ GAAP”).

The accompanying condensed consolidated financial statements have been prepared in conformity with GAAP in U.S. ~~GAAP~~dollars and are consistent in all material respects with those applied in our ~~2016~~2018 Annual Report on Form 10-K (“~~2016~~2018 Form 10-K”) with the exception of the impact of adopting the new lease accounting standard in 2019 (see below). The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. We have made all adjustments, ~~(which were~~which, unless otherwise disclosed, are of normal recurring ~~adjustments)~~nature, that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive income ~~(loss),~~ and statements of cash flows, as applicable. The operating results for the three- and nine-month periods ended September 30, ~~2017~~2019 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2017.~~2019. Our balance sheet as of December 31, ~~2016~~2018 included herein has been derived from the audited balance sheet as of December 31, ~~2016~~2018 included in our ~~2016~~2018 Form 10-K. These unaudited condensed consolidated financial statements should be read in conjunction with the annual audited consolidated financial statements and notes thereto included in our ~~2016~~2018 Form 10-K.

Certain reclassifications were made to previously reported amounts in the consolidated financial statements and notes thereto to make them consistent with the current presentation format.

New accounting standards adopted

In ~~May 2014,~~February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. ~~2014-09, “Revenue from Contracts with Customers~~2016-02, “Leases (Topic ~~606).~~842)” ~~This ASU provides~~(“ASC 842”), which was updated by subsequent amendments. ASC 842 requires a ~~five-step approach to account for revenue arising from contracts with customers. The ASU requires an entity~~lessee to recognize ~~revenue~~a lease right-of-use asset and related lease liability for most leases, including those classified as operating leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We adopted ASC 842 in ~~a way that depicts~~ the ~~transfer~~first quarter of ~~promised goods or services to customers in an amount that reflects~~2019 using the ~~consideration to which~~modified retrospective method. We also elected 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 licensespackage of ~~intellectual property. Additionally, these updates provide narrow-scope improvements and~~ practical expedients ~~as well as technical corrections and improvements to~~permitted under the ~~guidance. The new revenue standard permits~~transition guidance that, among other things, allows companies to ~~either apply the requirements retrospectively to all prior periods presented or apply the requirements~~carry forward their historical lease classification. Our adoption of ASC 842 resulted in the ~~year~~recognition of operating lease liabilities of $259.0 million and corresponding right-of-use (“ROU”) assets of $253.4 million (net of existing prepaid/deferred rent balances) as of January 1, 2019. In addition, we reclassified the remaining deferred gain of $4.6 million (net of deferred taxes of $0.9 million) on a 2016 sale and leaseback transaction to retained earnings. Subsequent to adoption, ~~through a cumulative adjustment. Our assessment at this stage~~leases in foreign currencies will generate foreign currency gains and losses, and we will no longer amortize the deferred gain from the aforementioned sale and leaseback transaction. Aside from these changes, ASC 842 is ~~that we do~~ not ~~expect the new revenue standard~~expected to have a material impact on our consolidated financial statements upon adoption. We continue working on expanded disclosure requirements and documentation of new policies, procedures and controls. We currently intend on adopting this guidance using the modified retrospective method.net earnings or cash flows.

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~~New 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 isissued but not yet 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.~~Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets ~~including~~(including trade ~~receivables~~receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. The guidance iswill be effective for ~~annual reporting periods beginning after December 15, 2019, including interim periods.~~us as of January 1, 2020. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

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~~any other recent accounting standards to have a material impact on our ~~consolidated~~ financial ~~statements.~~position, results of operations or cash flows.

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.

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Note 2 — Company Overview

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We ~~seek to~~ provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We provide services primarily in deepwater in the ~~U.S.~~ Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa ~~regions, and have expanded our operations into Brazil with the commencement of operations of the~~ ~~Siem Helix 1~~ ~~in mid-April 2017.~~regions. Our “life of field” services are segregated into ~~three~~3 reportable business segments: Well Intervention, Robotics and Production Facilities (Note ~~11)~~12).

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Our Well Intervention segment includes our vessels ~~and~~and/or equipment used to perform well intervention services primarily in the ~~U.S.~~ Gulf of Mexico, Brazil, the North Sea and ~~Brazil. Our Well Intervention segment also includes intervention riser systems (“IRSs”), some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”).~~West Africa. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and ~~two~~2 chartered monohull vessels, the Siem ~~Helix~~ 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,~~completion, the Q7000. Our well intervention equipment includes intervention riser systems (“IRSs”) and subsea intervention lubricators (“SILs”), some of which we provide on a stand-alone basis.

Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ~~ROVDrills~~a ROVDrill, which are designed to complement offshore construction and well intervention services, and ~~currently operates four chartered ROV~~3 robotics support vessels ~~including~~under long-term charter: the Grand Canyon, the Grand Canyon II and the Grand Canyon III ~~that went into service for us in May 2017.~~. We also utilize spot vessels as needed, including the Ross Candies, which is under a flexible charter agreement.

Our Production Facilities segment includes the Helix ProducerI (the “HP I”I”), a ship-shaped ~~dynamic positioning~~dynamically positioned floating production vessel, ~~and~~ the Helix Fast Response System (the “HFRS”), ~~which provides certain operators access to our~~ ~~Q4000~~ ~~and~~ ~~HP I~~ ~~vessels in the event of a well control incident in the Gulf of Mexico. The~~ ~~HP I~~ ~~has been under contract 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”) (Note 4), and ~~previously included~~several wells and related infrastructure associated with the Droshky Prospect that we acquired from Marathon Oil Corporation (“Marathon Oil”) on January 18, 2019. All of our ~~former ownership~~current production facilities activities are located in the Gulf of Mexico.

On May 29, 2019, we acquired a 70% controlling interest in ~~Deepwater Gateway, L.L.C.~~Subsea Technologies Group Limited (“~~Deepwater Gateway”~~STL”), a subsea engineering firm based in Aberdeen, Scotland, for $5.1 million, including $4.1 million in cash and $1.0 million that we ~~sold~~loaned to STL in ~~February 2016~~December 2018. The acquisition is expected to strengthen our supply of subsea intervention systems. The holders of the remaining 30% noncontrolling interest have the right to put their shares to us in June 2024. These redeemable noncontrolling interests have been recognized as temporary equity at their estimated fair value of $3.4 million at the acquisition date. We recognized $2.4 million of identifiable intangible assets and $6.9 million of goodwill, which are reflected in “Other assets” in the accompanying condensed consolidated balance sheet (Note 5)3). Goodwill is related to the synergies expected from the acquisition. The ultimate fair values of acquired assets, liabilities and noncontrolling interests are provisional and pending final assessment of the valuations. STL is included in our Well Intervention segment (Note 12) and its revenue and earnings are immaterial to our consolidated results.

Note 3 — Details of Certain Accounts

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



	September 30, 2019		December 31, 2018

Contract assets (Note 9)	$	580	$	5,829
Prepaids	14,876		10,306
Deferred costs (Note 9)	26,424		27,368
Other receivable (Note 13)	13,000		—
Other	6,871		8,091
Total other current assets	$	61,751	$	51,594

September 30,
2017 December 31,
2016

Note receivable ⁽¹⁾
$ —
$ 10,000
Prepaid insurance 2,432
4,426
Other prepaids 10,021
9,547
Deferred costs ⁽²⁾
20,704
7,971
Spare parts inventory 1,598
2,548
Income tax receivable —
880
Value added tax receivable 2,169
1,345
Other 1,248
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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Other assets, net consist of the following (in thousands):



	September 30, 2019		December 31, 2018

Prepaids	$	861	$	5,896
Deferred recertification and dry dock costs, net	16,678		8,525
Deferred costs (Note 9)	20,695		38,574
Charter deposit ⁽¹⁾	12,544		12,544
Other receivable (Note 13)	26,702		—
Goodwill (Note 2)	6,637		—
Intangible assets with finite lives, net (Note 2)	3,703		1,402
Other	2,503		3,116
Total other assets, net	$	90,323	$	70,057

September 30,
2017 December 31,
2016

Note receivable, net ⁽¹⁾
$ 3,129
$ 2,827
Prepaids 8,112
6,418
Deferred dry dock costs, net 14,260
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
Other 2,181
1,511
Total other assets, net $ 100,974
$ 72,549

(1)

~~In 2016, we entered into an agreement~~

This amount is deposited with ~~one~~the owner of ~~our customers~~the Siem Helix2 to ~~defer their~~offset certain payment obligations ~~until June 30, 2018. On March 30, 2017, we entered into a new agreement~~associated 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 customer~~vessel 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 Helix~~2.term.

Accrued liabilities consist of the following (in thousands):



	September 30, 2019		December 31, 2018

Accrued payroll and related benefits	$	25,853	$	43,079
Investee losses in excess of investment (Note 4)	7,638		5,125
Deferred revenue (Note 9)	10,814		10,103
Asset retirement obligations (Note 13)	11,556		—
Derivative liability (Note 17)	2,723		9,311
Other	13,398		17,976
Total accrued liabilities	$	71,982	$	85,594

September 30,
2017 December 31,
2016
��
Accrued payroll and related benefits $ 29,682
$ 20,705
Deferred revenue 8,664
8,911
Accrued interest 2,997
3,758
Derivative liability (Note 14) 9,927
18,730
Taxes payable excluding income tax payable 1,209
1,214
Other 8,282
5,296
Total accrued liabilities $ 60,761
$ 58,614

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



	September 30, 2019		December 31, 2018

Investee losses in excess of investment (Note 4)	$	—	$	6,035
Deferred gain on sale of property ⁽¹⁾	—		5,052
Deferred revenue (Note 9)	9,196		15,767
Asset retirement obligations (Note 13)	27,564		—
Derivative liability (Note 17)	—		884
Other	2,248		11,800
Total other non-current liabilities	$	39,008	$	39,538

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 revenue 8,827
8,598
Derivative liability (Note 14) 9,663
20,191
Other 9,491
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 ishad been amortized over a 15-year minimum lease ~~term.~~term prior to our adoption of ASC 842 on January 1, 2019. See Note 1 for the effect of ASC 842 on this deferred gain.

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Note 4 — ~~Statement of Cash Flow Information~~

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less. The following table provides supplemental cash flow information (in thousands):

Nine Months Ended
September 30,
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 as of September 30, 2017 and $10.1 million as of December 31, 2016.

~~Note 5 —~~ Equity Method 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~~We are committed to providing our pro-rata portion of ~~the losses reported by~~financial support for Independence Hub ~~exceeded~~to pay its obligations as they become due. The platform decommissioning process is currently underway and is expected to be substantially completed within the ~~carrying amount~~next 12 months. We had a liability of ~~our investment by $8.8~~$7.6 million ~~as of~~at September 30, ~~2017~~2019 and ~~$10.2~~$11.2 million at December 31, ~~2016 reflecting~~2018 for 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 “Accrued liabilities” and “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

Note 5 — Leases

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

Leases with a term greater than one year are recognized on our balance sheet as ROU assets and lease liabilities. We have elected to not recognize on our balance sheet leases with an initial term of one year or less. Lease liabilities and their corresponding ROU assets are recorded at the commencement date based on the present value of lease payments over the expected lease term. We use our incremental borrowing rate, which would be the rate incurred to borrow on a collateralized basis over a similar term in a similar economic environment, to calculate the present value of lease payments. ROU assets are adjusted for any initial direct costs paid or incentives received.

We separate our long-term vessel charters between their lease components and non-lease services. We estimate the lease component using the residual estimate approach by estimating the non-lease services, which are primarily crew, repair and maintenance, and regulatory certification costs. For all other leases, we have not separated the lease components and non-lease services. The lease term may include options to extend or terminate the lease when it is reasonably certain that we will exercise the option.

We recognize operating lease cost on a straight-line basis over the lease term for both (i) leases that are recognized on the balance sheet and (ii) short-term leases. We recognize lease cost related to variable lease payments that are not recognized on the balance sheet in the period in which the obligation is incurred. The following table details the components of our lease cost (in thousands):



	Three Months Ended			Nine Months Ended
	September 30, 2019			September 30, 2019

Operating lease cost	$	18,002		$	54,191
Variable lease cost	3,630			9,927
Short-term lease cost	5,587			14,549
Sublease income	(351		)	(1,077		)
Net lease cost	$	26,868		$	77,590

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Maturities of our operating lease liabilities as of September 30, 2019 are as follows (in thousands):



	Vessels			Facilities and Equipment			Total

Remainder of 2019	$	15,416		$	1,717		$	17,133
2020	59,942			6,391			66,333
2021	54,481			5,694			60,175
2022	52,105			5,103			57,208
2023	34,580			4,522			39,102
Thereafter	2,470			10,163			12,633
Total lease payments	$	218,994		$	33,590		$	252,584
Less: imputed interest	(28,272		)	(6,711		)	(34,983		)
Total operating lease liabilities	$	190,722		$	26,879		$	217,601

Current operating lease liabilities	$	47,914		$	4,926		$	52,840
Non-current operating lease liabilities	142,808			21,953			164,761
Total operating lease liabilities	$	190,722		$	26,879		$	217,601

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



	September 30, 2019

Weighted average remaining lease term	4.2 years
Weighted average discount rate	7.54	%

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



	Nine Months Ended
	September 30, 2019

Cash paid for operating lease liabilities	$	54,538
ROU assets obtained in exchange for new operating lease obligations	921

As previously disclosed in our 2018 Form 10-K and under the previous lease accounting standard, future minimum lease payments for our operating leases as of December 31, 2018 were as follows (in thousands):



	Vessels		Facilities and Equipment		Total

2019	$	116,620	$	5,881	$	122,501
2020	96,800		5,340		102,140
2021	89,216		5,185		94,401
2022	90,371		5,064		95,435
2023	51,266		4,533		55,799
Thereafter	—		10,448		10,448
Total lease payments	$	444,273	$	36,451	$	480,724

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Note 6 —Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of September 30, ~~2017~~2019 are as follows (in thousands):


	Term Loan ⁽¹⁾			2022 Notes			2032 Notes ⁽²⁾			MARAD Debt			Nordea Q5000 Loan			Total			Term Loan ⁽¹⁾			2022 Notes			2023 Notes			MARAD Debt			Nordea Q5000 Loan			Total

Less than one year	$	6,250		$	—		$	60,115		$	6,532		$	35,714		$	108,611		$	3,500		$	—		$	—		$	7,200		$	98,214		$	108,914
One to two years	11,250			—			—			6,858			35,714			53,822			3,500			—			—			7,560			—			11,060
Two to three years	81,250			—			—			7,200			98,215			186,665			27,125			125,000			—			7,937			—			160,062
Three to four years	—			—			—			7,560			—			7,560			—			—			125,000			8,333			—			133,333
Four to five years	—			125,000			—			7,937			—			132,937			—			—			—			8,749			—			8,749
Over five years	—			—			—			40,913			—			40,913			—			—			—			23,831			—			23,831
Gross debt																			34,125			125,000			125,000			63,610			98,214			445,949
Unamortized debt discounts ⁽²⁾																			—			(8,784		)	(15,376		)	—			—			(24,160		)
Unamortized debt issuance costs ⁽³⁾																			(438		)	(1,368		)	(2,478		)	(3,659		)	(446		)	(8,389		)
Total debt	98,750			125,000			60,115			77,000			169,643			530,508			33,687			114,848			107,146			59,951			97,768			413,400
Current maturities	(6,250		)	—			(60,115		)	(6,532		)	(35,714		)	(108,611		)
Long-term debt, less current maturities	92,500			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		)
Less: current maturities																			(3,500		)	—			—			(7,200		)	(97,768		)	(108,468		)
Long-term debt	$	90,685		$	108,018		$	(1,144	)	$	65,833		$	131,953		$	395,345		$	30,187		$	114,848		$	107,146		$	52,751		$	—		$	304,932


(1)	Term Loan ~~borrowing~~ pursuant to the Credit Agreement ~~(amended and restated in June 2017)~~(as defined below) matures in ~~June 2020.~~December 2021.


(2)	~~The holders of our remaining~~Our Convertible Senior Notes due ~~2032 may require us~~2022 and 2023 will increase to ~~repurchase the notes in March 2018. Accordingly, these notes are classified as current liabilities.~~their face amounts through accretion of their debt discounts to interest expense through May 2022 and September 2023, respectively.


(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.

Below is a summary of certain components of our indebtedness:

Credit Agreement

On June 30, 2017, we entered into an Amended and Restated Credit Agreement ~~(the~~(and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). ~~The~~On June 28, 2019, we amended ~~and restated credit facility is comprised of a $100 million~~our existing term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) under the Credit Agreement. The Credit Agreement is comprised of ~~up to $150~~a $35 million ~~(the “Revolving Loans”).~~Term Loan and a Revolving Credit Facility of $175 million. The Revolving Credit Facility permits ~~the Company~~us to obtain letters of credit up to a sublimit of $25 million. Pursuant to the Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may request aggregate commitments of up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans, or a combination thereof. 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. AtFacility. As of September 30, ~~2017,~~2019, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the ~~applicable~~ leverage ~~ratio covenant,~~ratios, totaled ~~$69.9~~$172.6 million, net of ~~$4.0~~$2.4 million of letters of credit issued under that facility.

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~~The Term Loan and~~Borrowings under the ~~Revolving Loans (together, the “Loans”),~~Credit Agreement bear interest, at our election, ~~bear interest~~at 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 ~~the~~Bank 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 5.29% as of September 30, 2019. Borrowings under the Revolving ~~Loans or portions thereof~~Credit Facility bearing interest at the base rate will bear interest at a per annum rate equal to ~~the~~Bank of America’s base rate plus a margin ranging from ~~1.75%~~1.50% to ~~3.25%~~2.50%. ~~The~~Borrowings under the Revolving ~~Loans or portions thereof~~Credit 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 ~~its~~the applicable margin for LIBOR rate ~~Loans times~~loans multiplied by the daily amount available to be drawn under the applicable letter of credit. Margins on borrowings under the Revolving ~~Loans~~Credit Facility will vary in relation to the ~~consolidated total leverage ratio~~Consolidated Total Leverage Ratio (as defined below) as provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of ~~our~~the Revolving Credit Facility.

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The Term Loan principal is required to be repaid in quarterly installments of ~~5% in~~2.5% of the ~~first loan year,~~ ~~10%~~ inaggregate principal amount of the ~~second loan year and~~ ~~15%~~ ~~in the third loan year,~~Term Loan, with a balloon payment at maturity. Installment amounts are subject to adjustment for any prepayments on the Term Loan. We may ~~elect to~~ prepay ~~amounts~~indebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay ~~amounts~~indebtedness outstanding under the Revolving Credit Facility without premium or penalty, and may reborrow any amounts prepaid up to the amount of the Revolving Credit Facility. ~~The Loans~~Borrowings under the Credit Agreement mature on ~~June 30, 2020.~~December 31, 2021.

The Credit Agreement and the other documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which 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”) and~~Ratio), funded debt to EBITDA ~~(“Consolidated~~(Consolidated Total Leverage ~~Ratio”),~~Ratio) and ~~provided that if there are no Loans outstanding, the~~secured 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:Ratio).


~~(a)~~	~~The minimum required Consolidated Interest Coverage Ratio:~~



~~Four Fiscal Quarters Ending~~	~~Minimum Consolidated~~ ~~Interest Coverage Ratio~~

~~September 30, 2017 and each fiscal quarter thereafter~~	~~2.50~~	~~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, 2017~~	~~6.00~~	~~to 1.00~~
~~December 31, 2017~~	~~5.75~~	~~to 1.00~~
~~March 31, 2018~~	~~5.50~~	~~to 1.00~~
~~June 30, 2018~~	~~5.25~~	~~to 1.00~~
~~September 30, 2018~~	~~5.00~~	~~to 1.00~~
~~December 31, 2018 through and including March 31, 2019~~	~~4.50~~	~~to 1.00~~
~~June 30, 2019 through and including September 30, 2019~~	~~4.25~~	~~to 1.00~~
~~December 31, 2019~~	~~4.00~~	~~to 1.00~~
~~March 31, 2020 and each fiscal quarter thereafter~~	~~3.50~~	~~to 1.00~~

~~Table of Contents~~


~~(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, 2018~~	~~3.00~~	~~to 1.00~~
~~September 30, 2018 and each fiscal quarter thereafter~~	~~2.50~~	~~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.

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 debt and EBITDA of the Unrestricted Subsidiaries with the exception of Helix Q5000 Holdings, S.à r.l. (“Q5000 Holdings”), a wholly owned subsidiary incorporated in Luxembourg, are not included in the calculations of our financial ~~covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”).~~covenants. Our obligations under the Credit Agreement, ~~are guaranteed by~~and those of 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 (i) most of ~~our~~the assets of the parent company, (ii) the shares of our domestic subsidiaries (other than Cal Dive I –- Title XI, Inc.) and of Helix Robotics Solutions Limited (formerly known as Canyon Offshore ~~Limited, as well as~~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 ~~two-thirds~~66% of the shares of certain foreign subsidiaries.

In ~~June 2017,~~March 2018, we prepaid $61 million of the then-existing term loan with a portion of the net proceeds from the 2023 Notes. We recognized a ~~$0.4~~$0.9 million loss to write off the related unamortized debt issuance costs. In June 2019, in connection with the amendment of the Credit Agreement we wrote off the remaining unamortized debt issuance costs ~~related to~~associated with a lender exiting the ~~lenders exiting from the term loan then outstanding under the credit facility prior to its June 2017 amendment and restatement, which loss is~~Credit Agreement. These losses are presented as “Loss on ~~early~~ extinguishment of long-term debt” in the accompanying condensed consolidated statements of operations.

In January 2019, contemporaneously with our purchase from Marathon Oil of several wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, we amended the Credit Agreement to permit the issuance of certain security to third parties for required plug and abandonment (“P&A”) obligations and to make certain capital expenditures in connection with ~~decreases in lenders’ commitments under our revolving credit facility, in June 2017~~acquired assets (Notes 2 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.13).

Convertible Senior Notes Due 2022 (“2022 Notes”)

On November 1, 2016, we completed a public offering and sale of ~~our Convertible Senior~~the 2022 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.

~~Table of Contents~~

The 2022 Notes bear interest at a rate of 4.25% per annum and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, ~~(as described in the Indenture governing the 2022 Notes)~~ the 2022 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain ~~circumstances as set forth in the Indenture governing the 2022 Notes.~~circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.

Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, if certain conditions are met, we may redeem all or any portion of the 2022 Notes ~~at our option, subject to certain conditions,~~ at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, and a “make-whole premium” ~~with a value equal to~~(as defined in the ~~present value of the remaining scheduled interest payments of~~indenture governing the 2022 ~~Notes to be redeemed through May 1, 2022.~~Notes). Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental ~~change,” as~~change” (as defined in the indenture governing the 2022 ~~Notes documentation.~~Notes).

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The ~~Indenture~~indenture governing the 2022 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the ~~Indenture~~indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2022 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a ~~principal~~significant subsidiary, the principal amount of the 2022 Notes together with any accrued and unpaid interest thereon will ~~automatically be and~~ become immediately due and payable.

The 2022 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million ($11.0 million net of tax) as ~~required under existing accounting rules. To arrive at this discount amount, we estimated~~a result of separating 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.equity component. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. ~~We recorded $11.0 million, net~~For the three- and nine-month periods ended September 30, 2019, interest expense (including amortization of ~~tax,~~the debt discount) related to the ~~carrying amount~~2022 Notes totaled $2.1 million and $6.2 million, respectively. For the three- and nine-month periods ended September 30, 2018, interest expense (including amortization of the ~~equity component of~~debt discount) related to the 2022 ~~Notes.~~Notes totaled $2.0 million and $6.1 million, respectively. The remaining unamortized ~~amount of the~~ debt discount of the 2022 Notes was ~~$14.6~~$8.8 million at September 30, ~~2017~~2019 and ~~$16.5~~$11.0 million at December 31, ~~2016.~~2018.

Convertible Senior Notes Due ~~2032~~ 2023 (“2023 Notes”)

InOn March ~~2012,~~20, 2018, we completed a public offering and sale of ~~our~~the 2023 Notes in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2023 Notes were approximately $121.0 million after deducting the underwriters’ discounts and commissions and estimated offering expenses. We used the net proceeds from the issuance of the 2023 Notes to fund the required repurchase by us of $59.3 million in principal of Convertible Senior Notes due 2032 (the “2032 Notes”) ~~in the aggregate principal amount of $200 million, $60~~described below and to prepay $61.0 million of ~~which are currently outstanding.~~ the then-existing term loan.

The ~~2032~~2023 Notes bear interest at a rate of ~~3.25%~~4.125% per annum and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, ~~2012.~~2018. The ~~2032~~2023 Notes mature on ~~March~~September 15, ~~2032~~2023 unless earlier converted, redeemed or repurchased. ~~The 2032~~During certain periods and subject to certain conditions, the 2023 Notes are convertible ~~in certain circumstances and during certain periods~~by the holders into shares of our common stock at an initial conversion rate of ~~39.9752~~105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately ~~$25.02~~$9.47 per share of common stock), subject to adjustment in certain ~~circumstances as set forth in the Indenture governing the 2032 Notes.~~circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.

~~Table of Contents~~

Prior to March ~~20, 2018,~~15, 2021, the ~~2032~~2023 Notes are not redeemable. On or after March ~~20, 2018,~~15, 2021, if certain conditions are met, we ~~at our option,~~ may redeem ~~some~~all or ~~all~~any portion of the ~~2032~~2023 Notes ~~in cash, at any time upon at least 30 days’ notice,~~ at a redemption price payable in cash equal to 100% of the principal amount to be redeemed, plus accrued and unpaid interest, ~~(including contingent interest, if any) up to but excluding~~and a “make-whole premium” (as defined in the ~~redemption date. In addition,~~indenture governing the ~~holders~~2023 Notes). Holders of the ~~2032~~2023 Notes may require us to ~~purchase~~repurchase the notes following a “fundamental change” (as defined in ~~cash some~~the indenture governing the 2023 Notes).

The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2023 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be immediately due and payable. In the case of ~~their 2032 Notes at~~certain events of bankruptcy, insolvency or reorganization relating to us or a ~~repurchase price equal to 100% of~~significant subsidiary, the principal amount of the ~~2032~~2023 Notes ~~plus~~together with any accrued and unpaid interest ~~(including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022~~thereon will become immediately due 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, 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 amount of the 2032 Notes in June, July and November of 2016, respectively. For the three- and nine-month periods ended September 30, 2016, we recognized gains related to the repurchase of the 2032 Notes 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.payable.

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The 2023 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the ~~2032~~2023 Notes, we recorded a debt discount of ~~$35.4~~$20.1 million ($15.9 million net of tax) as ~~required under existing accounting rules. To arrive at this discount amount we estimated~~a result of separating the fair value of the liability component of the 2032 Notes 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 at 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 2032 Notes (March 15, 2018).equity component. The effective interest rate for the ~~2032~~2023 Notes is ~~6.9%~~7.8% after considering the effect of the accretion of the related debt discount that represented the equity component of the ~~2032~~2023 Notes at their inception. ~~We recorded $22.5 million, net~~For the three- and nine-month periods ended September 30, 2019, interest expense (including amortization of ~~tax,~~the debt discount) related to the ~~carrying amount~~2023 Notes totaled $2.1 million and $6.3 million, respectively. For the three- and nine-month periods ended September 30, 2018, interest expense (including amortization of the ~~equity component of~~debt discount) related to the ~~2032 Notes.~~2023 Notes totaled $2.1 million and $4.3 million, respectively. The remaining unamortized ~~amount of the~~ debt discount of the ~~2032~~2023 Notes was ~~$1.1~~$15.4 million at September 30, ~~2017~~2019 and ~~$2.6~~$17.8 million at December 31, ~~2016.~~2018.

MARAD Debt

This U.S. ~~government guaranteed~~government-guaranteed financing (the “MARAD Debt”), pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. The MARAD Debt is payable in equal semi-annual installments, ~~beginning in August 2002 and~~ matures in February 2027 and ~~initially bore~~bears 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 a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in an amount of up to $250 million. The Nordea Q5000 Loan was funded in the amount of $250 million in April 2015 at the time the Q5000 ~~vessel~~ was delivered to us. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.

The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. The remaining principal balance and unamortized debt issuance costs related to the Nordea Q5000 Loan are classified as current. Q5000 Holdings may elect to prepay ~~amounts~~indebtedness outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Quarterly principal installments are subject to adjustment for any prepayments on this debt. In June 2015, we entered into ~~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)~~17). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under ~~our~~the Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.

~~Table of Contents~~

The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.

Convertible Senior Notes Due 2032

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

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Other

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

Interest expense	$	7,694		$	8,171		$	23,635		$	24,511
Interest income	(652		)	(994		)	(2,085		)	(2,263		)
Capitalized interest	(5,141		)	(3,928		)	(15,346		)	(11,504		)
Net interest expense	$	1,901		$	3,249		$	6,204		$	10,744

Three Months Ended
September 30, Nine Months Ended
September 30,
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 7 — Income Taxes

We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation, and the outcomes of tax disputes are inherently ~~uncertain, and~~uncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.

The effective tax rates for the three- and nine-month periods ended September 30, ~~2017~~2019 were ~~(204.9)%~~10.1% and ~~5.2%~~11.9%, respectively. The effective tax rates for the three- and nine-month periods ended September 30, ~~2016~~2018 were ~~24.1%~~3.0% and ~~26.7%~~2.8%, respectively. The ~~variance was~~increases were primarily attributable to ~~the earnings mix between our higher and lower tax rate jurisdictions and a change~~improvements in ~~tax position related to our foreign taxes.~~

We continued recording income taxes using a year-to-date effective tax rate method for the three- and nine-month periods ended September 30, 2017. The use of this method was based on our expectations at September 30, 2017 that a small change in our estimated ordinary income could result in a large changeprofitability 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.~~U.S. year over year.

~~Table of Contents~~

Income taxes are provided based on the U.S. statutory rate ~~of 35%~~ and at the local statutory rate for each foreign jurisdiction adjusted for items that are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes. The primary differences between the U.S. statutory rate and our effective rate are as follows:



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

U.S. statutory rate	21.0	%	21.0	%	21.0	%	21.0	%
Foreign provision	(10.1	)	(18.5	)	(9.7	)	(19.1	)
Other	(0.8	)	0.5		0.6		0.9
Effective rate	10.1	%	3.0	%	11.9	%	2.8	%

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

U.S. statutory rate 35.0 % 35.0 % 35.0 % 35.0 %
Foreign provision (241.5 ) (10.8 ) 2.8
(8.8 )
Change in tax position ⁽¹⁾
—
—
(29.3 ) —
Other 1.6
(0.1 ) (3.3 ) 0.5
Effective rate (204.9 )% 24.1 % 5.2 % 26.7 %

~~(1)~~

We consider all available evidence, both positive and negative, when determining whether a valuation allowance is required against deferred tax assets. Due to weaker near term outlook and financial results primarily associated with our Robotics segment, we currently do not anticipate generating sufficient 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.

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Note 8 —Shareholders’ Equity

On January 10, 2017, we completed an underwritten public offering (the “Offering”) of 26,450,000 shares of our common stock at a public offering price of $8.65 per share. The net proceeds from the Offering approximated $220 million, after deducting underwriting discounts and commissions and estimated offering expenses. We used the net proceeds from the Offering for general corporate purposes, including debt repayment, capital expenditures, working capital and investments in our subsidiaries.

The components of ~~Accumulated Other Comprehensive Income (Loss)~~accumulated other comprehensive loss (“accumulated OCI”) are as follows (in thousands):

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 )



	September 30, 2019			December 31, 2018

Cumulative foreign currency translation adjustment	$	(74,419	)	$	(69,855	)
Net unrealized loss on hedges, net of tax ⁽¹⁾	(781		)	(4,109		)
Accumulated OCI	$	(75,200	)	$	(73,964	)


(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 (Note 17) and ~~are~~is net of deferred income taxes totaling ~~$4.5~~$0.2 million at September 30, ~~2017~~2019 and ~~$9.7~~$1.0 million at December 31, ~~2016 (Note 14).~~2018.

Note 9 —Revenue from Contracts with Customers

Disaggregation of Revenue

Our revenues are derived primarily from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities. The following table provides information about disaggregated revenue by contract duration (in thousands):



	Well Intervention		Robotics		Production Facilities		Intercompany Eliminations ⁽¹⁾			Total Revenue
Three months ended September 30, 2019
Short-term	$	53,018	$	26,809	$	—	$	—		$	79,827
Long-term ⁽²⁾	117,188		25,100		13,777		(23,283		)	132,782
Total	$	170,206	$	51,909	$	13,777	$	(23,283	)	$	212,609

Three months ended September 30, 2018
Short-term	$	39,548	$	29,877	$	—	$	—		$	69,425
Long-term ⁽²⁾	114,893		24,463		15,877		(12,083		)	143,150
Total	$	154,441	$	54,340	$	15,877	$	(12,083	)	$	212,575


Nine months ended September 30, 2019
Short-term	$	145,611	$	80,440	$	—	$	—		$	226,051
Long-term ⁽²⁾	305,900		55,956		44,651		(51,398		)	355,109
Total	$	451,511	$	136,396	$	44,651	$	(51,398	)	$	581,160

Nine months ended September 30, 2018
Short-term	$	143,510	$	74,050	$	—	$	—		$	217,560
Long-term ⁽²⁾	302,259		46,519		48,541		(33,417		)	363,902
Total	$	445,769	$	120,569	$	48,541	$	(33,417	)	$	581,462

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(1)	Intercompany revenues among our business segments are under agreements that are considered long-term.


(2)	Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.

Contract Balances

Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable that have been billed to customers are recorded as trade accounts receivable while accounts receivable that have not been billed to customers are recorded as unbilled accounts receivable.

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” on the accompanying condensed consolidated balance sheets (Note 3). Contract assets were $0.6 million at September 30, 2019 and $5.8 million at December 31, 2018. We incurred no impairment losses on our accounts receivable and contract assets for the three- and nine-month periods ended September 30, 2019 and 2018.

Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to 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” on the accompanying condensed consolidated balance sheets (Note 3). Contract liabilities totaled $20.0 million at September 30, 2019 and $25.9 million at December 31, 2018. Revenue recognized for the three- and nine-month periods ended September 30, 2019 included $4.0 million and $7.4 million, respectively, that were included in the contract liability balance at the beginning of each period. Revenue recognized for the three- and nine-month periods ended September 30, 2018 included $7.4 million and $10.8 million, respectively, that were included in the contract liability balance at the beginning of each period.

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

Performance Obligations

As of September 30, 2019, $833.8 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $114.5 million in 2019, $443.2 million in 2020 and $276.1 million in 2021 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 September 30, 2019.

For the three- and nine-month periods ended September 30, 2019 and 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

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Contract Fulfillment Costs

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

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

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Note 910 — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. ~~Holders~~Shares of restricted stock are considered participating securities because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common ~~stock and~~stock. We are required to compute earnings per share (“EPS”) under the ~~shares of restricted stock are thus considered participating securities.~~two-class method in periods in which we have earnings. Under ~~applicable accounting guidance,~~the two-class method, the undistributed earnings for each period are allocated based on the participation rights of both ~~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 class~~two-class method as holders of our restricted shares are not obligated to share in such losses.

The presentation of basic EPS ~~amounts~~ on the face of the accompanying condensed consolidated statements of operations is computed by dividing net income or loss by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the ~~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, 2019				Three Months Ended September 30, 2018
	Income			Shares	Income			Shares
Basic:
Net income attributable to common shareholders	$	31,695			$	27,121
Less: Undistributed earnings allocated to participating securities	(261		)		(260		)
Accretion of redeemable noncontrolling interests	(25		)		—
Net income available to common shareholders, basic	$	31,409		147,575	$	26,861		146,700


Diluted:
Net income available to common shareholders, basic	$	31,409		147,575	$	26,861		146,700
Effect of dilutive securities:
Share-based awards other than participating securities	—			779	—			264
Undistributed earnings reallocated to participating securities	1			—	—			—
Net income available to common shareholders, diluted	$	31,410		148,354	$	26,861		146,964

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

We had net losses for the nine-month periods ended September 30, 2017 and 2016. 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 awards 364
308
Total 145,421
109,443

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~~In addition, the~~



	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
	Income			Shares	Income			Shares
Basic:
Net income attributable to common shareholders	$	49,867			$	42,345
Less: Undistributed earnings allocated to participating securities	(435		)		(407		)
Accretion of redeemable noncontrolling interests	(43		)		—
Net income available to common shareholders, basic	$	49,389		147,506	$	41,938		146,679


Diluted:
Net income available to common shareholders, basic	$	49,389		147,506	$	41,938		146,679
Effect of dilutive securities:
Share-based awards other than participating securities	—			580	—			82
Undistributed earnings reallocated to participating securities	2			—	—			—
Net income available to common shareholders, diluted	$	49,391		148,086	$	41,938		146,761

The following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2032 Notes were excluded from the diluted EPS calculation ~~because we have the right and the intention to settle any such future conversions in cash (Note 6)~~as they were anti-dilutive (in thousands):



	Three Months Ended September 30,		Nine Months Ended September 30,
	2019	2018	2019	2018

2022 Notes	8,997	8,997	8,997	8,997
2023 Notes	13,202	13,202	13,202	9,381
2032 Notes ⁽¹⁾	—	—	—	701

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

2022 Notes 8,997
—
8,997
—
2032 Notes 2,403
7,493
2,403
7,814


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

Note 1011 — Employee Benefit Plans

Long-Term Incentive ~~Stock-Based~~ Plan

We currently have 1 active long-term incentive plan: the 2005 Long-Term Incentive Plan, as amended and restated (the “2005 Incentive Plan”). On May 15, 2019, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan to: (i) authorize 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy, (ii) establish a maximum award limit applicable to independent members of our Board of Directors (our “Board”) under the 2005 Incentive Plan, (iii) require, subject to certain exceptions, that all awards under the 2005 Incentive Plan have a minimum vesting or restriction period of one year and (iv) remove certain requirements with respect to performance-based compensation under Section 162(m) of the Internal Revenue Code that were repealed by the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”). As of September 30, ~~2017,~~2019, there were ~~2.4~~8.5 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”).~~Plan. During the nine-month period ended September 30, ~~2017,~~2019, the following grants of share-based awards were made under the 2005 Incentive Plan:

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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



Date of Grant	Shares/ Units	Grant Date Fair Value Per Share/Unit		Vesting Period

January 2, 2019 ⁽¹⁾	688,540	$	5.41	33% per year over three years
January 2, 2019 ⁽²⁾	688,540	7.60		100% on January 2, 2022
January 2, 2019 ⁽³⁾	11,841	5.41		100% on January 1, 2021
April 1, 2019 ⁽³⁾	7,625	7.91		100% on January 1, 2021
July 1, 2019 ⁽³⁾	8,727	8.63		100% on January 1, 2021
August 1, 2019 ⁽⁴⁾	7,151	8.76		100% on August 1, 2020


(1)	Reflects grants of restricted stock to our executive officers and select management employees.

(2)

Reflects grants of performance share units (“PSUs”) to our executive officers and select management employees. The PSUs provide for an award based on the performance of our common stock over a three-year period with the maximum amount of the award being 200% of the original ~~awarded PSUs~~PSU awards and the minimum amount being ~~zero. For the 2017 awards, vested PSUs can only be settled in shares of our common stock.~~0.


(3)	Reflects grants of restricted stock to certain independent members of our Board ~~of Directors (the “Board”)~~ who have ~~made an election~~elected to take their quarterly fees in stock in lieu of cash.


(4)	Reflects a grant of restricted stock made to a new independent member of our Board upon her joining our Board.

Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting ~~periods~~period on a straight-line basis. ~~We elected to account for forfeitures when~~Forfeitures are recognized as they ~~occur upon the adoption of the new guidance for employee share-based payment accounting (Note 1).~~occur. For the three- and nine-month periods ended September 30, ~~2017, $1.7~~2019, $1.2 million and ~~$5.4~~$4.9 million respectively, were recognized as share-based compensation related to restricted stock. For the three- and nine-month periods ended September 30, ~~2016, $1.4~~2018, $1.5 million and ~~$4.3~~$4.5 million, respectively, were recognized as share-based compensation related to restricted stock.

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The estimated fair value of PSUs is determined using a Monte Carlo simulation model. PSUs granted prior to 2017 could be settled in either cash or shares of our common stock and were accounted for as liability awards. Beginning in 2017, PSUs granted are to be settled solely in shares of our common stock and therefore are accounted for as equity awards. Compensation cost for PSUs that are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line ~~basis. PSUs that are accounted for~~basis 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. Cumulative compensation cost for vested liability PSU awards equals the actual cash payout amount upon vesting. The 2017 awards are accounted for as equity awards whereas awards made prioran increase to ~~2017 are accounted for as liability awards.~~equity. For the three- and nine-month periods ended September 30, ~~2017, $4.0~~2019, $1.2 million and ~~$5.8~~$3.9 million, respectively, were recognized as share-based compensation related to PSUs. For the three- and nine-month periods ended September 30, ~~2016, $2.5~~2018, $6.3 million and ~~$5.3~~$11.5 million, respectively, were recognized as share-based compensation related to PSUs. The liability balance for previously unvested PSUs granted in January 2016 was ~~$10.2 million at September 30, 2017 and $7.1~~$11.1 million at December 31, ~~2016. We paid $0.6 million~~2018, which we settled in cash ~~to settle the 2014 grant of~~when those PSUs ~~when they~~ vested in January ~~2017.~~2019.

Additionally in 2019 and 2018, we granted fixed-value cash awards of $4.6 million and $5.2 million, respectively, to select management employees under the 2005 Incentive Plan. The value of fixed value cash awards is recognized on a straight-line basis over a vesting period of three years. For the three- and nine-month periods ended September 30, 2019, $0.8 million and $2.4 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2018, $0.5 million and $1.3 million, respectively, were recognized as compensation cost.

Employee Stock Purchase Plan

We have an employee stock purchase plan (the “ESPP”). ~~The~~On May 15, 2019, our shareholders approved an amendment to and restatement of the ESPP ~~has 1.5 million~~to: (i) increase the shares authorized for issuance by 1.5 million shares and (ii) delegate to an internal administrator the authority to establish the maximum shares purchasable during a purchase period. As of ~~which 0.6~~September 30, 2019, 2.0 million shares were available for issuance ~~as of September 30, 2017. In February 2016, we suspended~~under the ESPP. The ESPP ~~purchases for the January through April 2016 purchase period and indefinitely imposed~~currently has a purchase limit of ~~130~~260 shares per employee ~~for subsequent~~per purchase ~~periods.~~period.

For more information regarding our employee benefit plans, including ~~our long-term incentive stock-based~~the 2005 Incentive Plan and ~~cash plans and our employee stock purchase plan,~~the ESPP, see Note 12 to our ~~2016~~2018 Form 10-K.

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Note 1112 — Business Segment Information

We have ~~three~~3 reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels ~~and~~and/or equipment used to perform well intervention services 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 Seawell, the Well Enhancer, and the chartered Siem Helix 1 and Siem Helix 2 vessels. ~~The~~ ~~Siem Helix 1~~ ~~commenced its operations for Petrobras in mid-April 2017.~~Our well intervention equipment includes IRSs and SILs, some of which we provide on a stand-alone basis. Our Robotics segment includes ROVs, trenchers and ~~ROVDrills~~a ROVDrill, which are designed to complement offshore construction and well intervention services, 3 robotics support vessels under long-term charter: the Grand Canyon, the Grand Canyon IIand ~~currently operates four chartered ROV support~~the Grand Canyon III, and spot vessels, including the ~~Grand Canyon III~~ ~~that went into service for us in May 2017.~~Ross Candies, which is under a flexible charter agreement. Our Production Facilities segment includes the HP I, the HFRS, ~~and~~ our ~~investment~~ownership interest in Independence Hub ~~that is accounted for under the equity method,~~(Note 4) and ~~previously included~~ our ~~former~~ ownership ~~interest in Deepwater Gateway~~of certain oil and gas properties that we ~~sold~~acquired from Marathon Oil in ~~February 2016~~January 2019 (Note 5)13). All material intercompany transactions between the segments have been eliminated.

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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 September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
Net revenues —
Well Intervention	$	170,206		$	154,441		$	451,511		$	445,769
Robotics	51,909			54,340			136,396			120,569
Production Facilities	13,777			15,877			44,651			48,541
Intercompany eliminations	(23,283		)	(12,083		)	(51,398		)	(33,417		)
Total	$	212,609		$	212,575		$	581,160		$	581,462

Income (loss) from operations —
Well Intervention	$	37,689		$	34,427		$	74,002		$	82,774
Robotics	8,876			5,601			7,921			(12,818		)
Production Facilities	3,050			6,694			11,907			20,919
Segment operating income	49,615			46,722			93,830			90,875
Corporate, eliminations and other	(10,617		)	(15,345		)	(31,491		)	(35,842		)
Total	$	38,998		$	31,377		$	62,339		$	55,033

Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016
Net revenues —
Well Intervention $ 111,522
$ 108,287
$ 299,219
$ 214,262
Robotics 47,049
48,897
102,078
119,805
Production Facilities 16,380
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 Facilities 7,660
8,312
20,724
25,225
Corporate and other (10,633 ) (10,288 ) (29,296 ) (28,784 )
Intercompany elimination 199
(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. Intercompany segment revenues are as follows (in thousands):



	Three Months Ended September 30,				Nine Months Ended September 30,
	2019		2018		2019		2018

Well Intervention ⁽¹⁾	$	15,318	$	4,379	$	28,355	$	10,546
Robotics	7,965		7,704		23,043		22,871
Total	$	23,283	$	12,083	$	51,398	$	33,417


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

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Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

Well Intervention $ 3,765
$ 2,898
$ 8,033
$ 5,740
Robotics 7,926
10,169
23,112
23,343
Total $ 11,691
$ 13,067
$ 31,145
$ 29,083

Segment assets are comprised of all assets attributable to each reportable segment. Corporate and other includes all assets not directly identifiable with our business segments, most notably the majority of our cash and cash equivalents. The following table reflects total assets by reportable segment (in thousands):



	September 30, 2019		December 31, 2018

Well Intervention	$	2,133,205	$	1,916,638
Robotics	183,125		147,602
Production Facilities	159,225		120,845
Corporate and other	137,956		162,645
Total	$	2,613,511	$	2,347,730

Note 13 — Asset Retirement Obligations

Our asset retirement obligations (“AROs”) consist of estimated costs for subsea infrastructure P&A activities. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations.

The following table describes the changes in our AROs (both current and long-term) (in thousands):

September 30,
2017 December 31,
2016

Well Intervention $ 1,774,821
$ 1,596,517
Robotics 179,777
186,901
Production Facilities 141,739
158,192
Corporate and other 270,153
305,331
Total $ 2,366,490
$ 2,246,941



AROs at January 1, 2019	$	—
Liability incurred during the period ⁽¹⁾	53,294
Liability settled during the period	(15,944		)
Accretion expense	1,770
AROs at September 30, 2019	$	39,120

(1)

In connection with the acquisition on January 18, 2019 of certain assets related to the Droshky Prospect (Note 2), we assumed the AROs for the required P&A of those assets in exchange for agreed-upon amounts to be paid by Marathon Oil as the P&A work is completed. We initially recognized $53.3 million of ARO liability, $50.8 million of receivables and $2.5 million of acquired property for this transaction.

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Note 1214 — 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 December~~30, 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 monohull~~the Siem Helix 1 and Siem Helix 2 vessels ~~the~~ ~~Siem Helix~~1 ~~and the~~ ~~Siem Helix~~2.used in connection with our contracts with Petróleo Brasileiro S.A. (“Petrobras”) to perform well intervention work offshore Brazil. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates with options to extend. We have long-term charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The ~~initial term~~charter agreements expire in October 2019 for the Grand Canyon, in April 2021 for the Grand Canyon II and in May 2023 for the Grand Canyon III.

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In September 2013, we entered into a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the ~~agreements with Petrobras is for four years with Petrobras’s options to extend.~~

~~The~~ ~~Siem Helix~~1 ~~vessel~~contract price was ~~delivered to us~~paid upon the signing of the contract, 20% was paid in each of 2016, 2017 and 2018, and the 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 inremaining 20% is due upon the ~~third quarter as we addressed most~~delivery of the ~~items identified in~~vessel. We have informed the shipyard of our intent to take delivery of the vessel ~~acceptance process. The~~ ~~Siem Helix~~2 ~~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.~~November 2019. At September 30, ~~2017,~~2019, our total investment in the ~~topside equipment~~Q7000 was $446.4 million, including $276.8 million of installment payments to the shipyard. The vessel is currently in the final preparation phase for ~~the two vessels was $304.1 million.~~work expected to commence in early 2020.

Contingencies and Claims

We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations orand cash flows.

Litigation

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

Note 1315 — Statement of Cash Flow Information



	Nine Months Ended September 30,
	2019		2018

Interest paid, net of interest capitalized	$	2,404	$	6,620
Income taxes paid	7,535		4,699

Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions totaled $14.0 million at September 30, 2019 and $9.9 million at December 31, 2018.

Note 16 — Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

Level 1.1 — Observable inputs such as quoted prices in active markets;

Level 2.2 — Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

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Level 3.3 — 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.~~Approach — Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.


(b)	Cost ~~Approach.~~Approach — Amount that would be required to replace the service capacity of an asset (replacement cost).


(c)	Income ~~Approach.~~Approach — Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

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Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and ~~various~~ derivative instruments. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. The ~~net carrying amount~~fair value of our ~~long-term note receivable also approximates its fair value.~~derivative instruments (Note 17) reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation, volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. The following tables provide additional information relating to ~~other~~those financial instruments measured at fair value on a recurring basis (in thousands):


	Fair Value Measurements at September 30, 2017 Using									Fair Value at September 30, 2019
	Level 1		Level 2 ⁽¹⁾		Level 3		Total		Valuation Approach	Level 1		Level 2		Level 3		Total		Valuation Approach
Assets:
Interest rate swaps	$	—	$	374	$	—	$	374	(c)	$	—	$	108	$	—	$	108	(c)

Liabilities:
Foreign exchange contracts	—		19,508		—		19,508		(c)
Interest rate swaps	—		82		—		82		(c)
Total liability	$	—	$	19,216	$	—	$	19,216
Foreign exchange contracts — hedging instruments										—		1,089		—		1,089		(c)
Foreign exchange contracts — non-hedging instruments										—		1,634		—		1,634		(c)
Total net liability										$	—	$	2,615	$	—	$	2,615



	Fair Value at December 31, 2018
	Level 1		Level 2		Level 3		Total		Valuation Approach
Assets:
Interest rate swaps	$	—	$	1,064	$	—	$	1,064	(c)

Liabilities:
Foreign exchange contracts — hedging instruments	—		6,211		—		6,211		(c)
Foreign exchange contracts — non-hedging instruments	—		3,984		—		3,984		(c)
Total net liability	$	—	$	9,131	$	—	$	9,131

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 values~~principal amount and estimated fair ~~values~~value of our long-term debt are as follows (in thousands):



	September 30, 2019				December 31, 2018
	Principal Amount ⁽¹⁾		Fair Value ^{(2) (3)}		Principal Amount ⁽¹⁾		Fair Value ^{(2) (3)}

Term Loan (previously scheduled to mature June 2020)	$	—	$	—	$	33,693	$	33,314
Term Loan (matures December 2021)	34,125		33,698		—		—
Nordea Q5000 Loan (matures April 2020)	98,214		98,214		125,000		122,500
MARAD Debt (matures February 2027)	63,610		68,972		70,468		74,406
2022 Notes (mature May 2022)	125,000		126,094		125,000		114,298
2023 Notes (mature September 2023)	125,000		146,719		125,000		114,688
Total debt	$	445,949	$	473,697	$	479,161	$	459,206

September 30, 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 value~~Principal amount includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 6 for additional disclosures on our long-term debt.

(2)

The estimated fair value of the 2022 Notes and the ~~2032~~2023 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the term loans, 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 party~~third-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.


(3)	The principal amount and estimated fair value of the 2022 Notes and the 2023 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.

Note 1417 — 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~~mitigate 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~~Cash flow ~~exposure~~hedges are entered into to hedge ~~a forecasted transaction or~~ the variability of cash flows related to a forecasted transaction or to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are ~~deferred to the extent the hedges are effective.~~reported in OCI. These changes are ~~recorded as a component of Accumulated OCI (a component of shareholders’ equity) until~~subsequently reclassified into earnings when the hedged transactions ~~occur and are recognized in~~affect earnings. ~~The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change~~Changes in the fair value of a derivative instrument that does not qualify for hedge accounting isare recorded in earnings in the period in which the change occurs.

For additional information regarding our accounting for derivative instruments and hedging activities, see Notes 2 and 18 to our ~~2016~~2018 Form 10-K.

Interest Rate Risk

From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into ~~various~~ interest rate swap contracts to fix the interest rate on $187.5 million of ~~our~~the 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.~~reported in accumulated OCI (net of tax). These changes are ~~recorded as a component of Accumulated OCI until~~subsequently reclassified into earnings when 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~~accumulated OCI (net of tax). ~~Reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations are changes~~Changes in unrealized losses associated with the foreign currency exchange contracts that are ~~no longer~~not designated as cash flow ~~hedges. Hedge ineffectiveness also is~~hedges are reflected in “Other ~~income (expense),~~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, 2019			December 31, 2018
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Asset Derivative Instruments:
Interest rate swaps	Other current assets	$	108	Other current assets	$	863
Interest rate swaps	Other assets, net	—		Other assets, net	201
		$	108		$	1,064

Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	1,089	Accrued liabilities	$	5,857
Foreign exchange contracts	Other non-current liabilities	—		Other non-current liabilities	354
		$	1,089		$	6,211

September 30, 2017 December 31, 2016

Balance Sheet
Location

Fair
Value

Balance Sheet
Location

Fair
Value
Asset Derivative Instruments:
Interest rate swaps Other assets, net $ 374
Other assets, net $ 451
$ 374
$ 451

Liability Derivative Instruments:
Foreign exchange contracts Accrued liabilities $ 6,945
Accrued liabilities $ 14,056
Interest rate swaps Accrued liabilities 82
Accrued liabilities 751
Foreign exchange contracts Other non-current liabilities 6,123
Other non-current liabilities 13,383
$ 13,150
$ 28,190

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The following table presents the balance sheet location and fair value of our derivative instruments that were not designated as hedging instruments (in thousands):



	September 30, 2019			December 31, 2018
	Balance Sheet Location	Fair Value		Balance Sheet Location	Fair Value
Liability Derivative Instruments:
Foreign exchange contracts	Accrued liabilities	$	1,634	Accrued liabilities	$	3,454
Foreign exchange contracts	Other non-current liabilities	—		Other non-current liabilities	530
		$	1,634		$	3,984

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September 30, 2017 December 31, 2016

Balance Sheet
Location

Fair
Value

Balance Sheet
Location

Fair
Value
Liability Derivative Instruments:
Foreign exchange contracts Accrued liabilities $ 2,900
Accrued liabilities $ 3,923
Foreign exchange contracts Other 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~~accumulated OCI (net of tax) and our condensed consolidated statements of operations (in thousands). We estimate that as of September 30, ~~2017, $4.6~~2019, $0.8 million of net losses in ~~Accumulated~~accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.



	Unrealized Gain (Loss) Recognized in OCI
	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018

Foreign exchange contracts	$	(280	)	$	(164	)	$	(338	)	$	(35	)
Interest rate swaps	6			76			(363		)	874
	$	(274	)	$	(88	)	$	(701	)	$	839

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 swaps 68
643
366
(880 )
$ 3,688
$ 4,892
$ 9,707
$ 9,865



	Location of Gain (Loss) Reclassified from Accumulated OCI into Earnings	Gain (Loss) Reclassified from Accumulated OCI into Earnings
		Three Months Ended September 30,						Nine Months Ended September 30,
		2019			2018			2019			2018

Foreign exchange contracts	Cost of sales	$	(1,197	)	$	(1,957	)	$	(5,460	)	$	(5,538	)
Interest rate swaps	Net interest expense	151			158			593			305
		$	(1,046	)	$	(1,799	)	$	(4,867	)	$	(5,233	)

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 contracts Cost of sales $ (3,288 ) $ (2,663 ) $ (10,280 ) $ (8,033 )
Interest rate swaps Net 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 Loss Recognized in Earnings	Loss Recognized in Earnings
		Three Months Ended September 30,						Nine Months Ended September 30,
		2019			2018			2019			2018

Foreign exchange contracts	Other expense, net	$	(371	)	$	(83	)	$	(413	)	$	(26	)
		$	(371	)	$	(83	)	$	(413	)	$	(26	)

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 contracts Other 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 expectations and beliefs concerning future events. This forward-looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange ~~Act.~~Act of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated herein by reference that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking ~~statements.~~statements although not all forward-looking statements contain such identifying words. Included in forward-looking statements are, among other things:

statements regarding our business strategy orand any other business plans, forecasts or objectives, any or all of which are subject to change;

~~statements regarding the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of our~~ ~~Q7000~~ ~~vessel;~~

~~statements regarding the commencement of commercial operations of the~~ ~~Siem Helix~~2 ~~chartered vessel to be used in connection with our contracts to provide well intervention services offshore Brazil;~~

statements regarding projections of revenues, gross ~~margin,~~margins, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;

statements regarding our backlog and ~~long-term~~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 acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto, including the construction, completion and mobilization of the Q7000;

statements regarding any financing transactions or arrangements, or our ability to enter into such ~~transactions;~~transactions or arrangements;

statements regarding ~~anticipated~~potential legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;

statements regarding our trade receivables and their collectability;

statements regarding ~~anticipated~~potential developments, industry trends, performance or industry ranking;

statements regarding general economic or political conditions, whether international, national or in the regional ~~and~~or local ~~market areas~~markets 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 impact of any potential cancellation, deferral or modification of our work or contracts by our customers;

~~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 Helix~~2~~, which is to be used to perform contracted well intervention work offshore Brazil;~~

the ability to ~~continue to work through~~effectively bid and perform our contracts, including the ~~items identified in the~~ ~~Siem Helix~~1 ~~acceptance process and the timing thereof;~~

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, including the~~ ~~Q4000, the~~ ~~Q5000~~ ~~and the~~ ~~Siem Helix~~1;

assets;

unexpected future capital expenditures, including the amount and nature thereof;

the effectiveness and timing of completion of our vessel and/or system upgrades and major maintenance items;

unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;

the effects of our indebtedness and our ability to reduce capital commitments;

the results of our continuing efforts to control costs and improve performance;

the success of our risk management activities;

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the effects of competition;

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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;~~developments, such as the 2017 Tax Act;

the impact of the ~~vote in the~~ U.K. to potentially exit the European Union, ~~(the “EU”),~~ known as Brexit, on our business, operations and financial condition, which is unknown at this time;

the effect of adverse weather conditions and/or other risks associated with marine operations;

the impact of foreign currency exchange controls and exchange rate fluctuations;

the effectiveness of our current and future hedging activities;

the potential impact of a loss of one or more key employees; and

the impact of general, market, industry or business conditions.

Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described inunder Item 1A. “Risk Factors” and Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our ~~2016~~2018 Form 10-K. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements or provide reasons why actual results may differ.

EXECUTIVE SUMMARY

Business Strategy

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We believe that focusing on these services ~~will~~should deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities and/or the regions in which we operate, or add capacity to existing services in our key operating regions. ~~Our~~We expect our well intervention fleet ~~expanded following the delivery of the~~ ~~Siem Helix~~ ~~2 chartered vessel in February 2017 and is expected~~ to ~~further~~ expand ~~following~~with the completion and delivery in 2019 of the Q7000, a newbuild semi-submersible ~~vessel, in 2018.~~vessel. Chartering newer vessels with additional capabilities, ~~including~~such as the three Grand Canyon ~~III~~ ~~chartered vessel that went into service for us in May 2017,~~vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit byfrom our fixed fee agreement for the HP I ~~servicing~~, a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator, until at least June 1, 2023. With the acquisition of certain oil and gas properties from Marathon Oil in January 2019, we expect improved utilization of our well intervention fleet in the Gulf of Mexico as we perform the P&A of the acquired assets as our schedule permits, subject to regulatory timelines.

In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the ~~parties’ strategic alliance~~parties 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~~leverages the parties’ capabilities to provide a unique, fully integrated offering to ~~customers,~~clients, combining marine support with well access and control technologies. ~~In April 2015, we~~We and OneSubsea ~~agreed to~~ jointly ~~develop and ordered~~developed a 15,000 working p.s.i. ~~IRS, which is expected to be completed mid-fourth quarter of 2017 for~~intervention riser system (“15K IRS”), each owning a ~~total cost of approximately $28 million (approximately $14 million for our~~ 50% ~~interest). At September 30, 2017, our total investment in the~~interest. The 15K IRS was ~~$11.6 million.~~completed and placed into service in January 2018. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) ~~for an estimated cost of approximately $12 million (approximately $6 million for our~~, each owning a 50% ~~interest). At September 30, 2017, our total investment in~~interest. Final acceptance testing on the ROAM ~~was $1.9 million. The ROAM~~has been completed and the system is currently expected to be available to customers in ~~the first quarter of 2018.~~2020.

Economic Outlook and Industry Influences

Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities ~~as well as~~and capital projects. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including:

worldwide economic activity and general economic and business conditions, including available access to global capital and capital markets;

the global supply and demand for oil and natural ~~gas, especially in the United States, Europe, China~~gas;

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political and ~~India;~~

economic uncertainty and geopolitical unrest, including regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;

actions taken by the Organization of Petroleum Exporting Countries;

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the availability and discovery rate of new oil and natural gas reserves in offshore areas;

the exploration and production of onshore shale oil and natural gas;

the cost of offshore exploration for and production and transportation of oil and natural gas;

the level of excess production capacity;

the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;

the sale and expiration dates of offshore leases in the ~~United States~~U.S. and overseas;

technological advances affecting energy exploration, production, transportation and consumption;

potential acceleration of the development of alternative fuels;

shifts in end-customer preferences toward fuel efficiency and the use of natural gas;

weather conditions and natural disasters;

environmental and other governmental regulations; and

domestic and international tax laws, regulations and policies.

~~The significant decline~~West Texas Intermediate oil prices have been volatile, fluctuating between $50 and $60 per barrel throughout most of the first nine months of 2019. Volatility in oil prices ~~since mid-year 2014~~ and imbalance in the ~~resulting difficult industry environment has had a significant adverse impact on investments~~supply and demand for oil create uncertainty in oil and gas exploration and ~~production. Many~~production activities. For instance, an increase in oil and gas exploration and production activities (shale oil production in particular) is expected when major oil producing countries including the U.S. increase output as a result of rising oil prices. Increased supply without adequate levels of increase in demand, however, may weaken oil prices and industry prospects. The resulting industry environment may discourage oil and gas companies ~~have terminated or not renewed contracts for many of their contracted rigs and have drastically cut~~from making longer-term investments in offshore exploration and production as well as other offshore 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 limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects us, as drilling rigs historically have been the asset class used for offshore well intervention work. This rig overhang combined with lower volumes of work ~~may~~continues to affect 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 current volatile~~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 impact of Brexit and any exit agreements as they are negotiated, but the impact from Brexit on our business and operations will depend on the outcome of tariff, tax treaties, trade, regulatory and other negotiations, as well as the impact of Brexit on macroeconomic growth and currency volatility, which are uncertain at this time.

Many oil and gas companies are increasingly focusing on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that ~~when~~as oil and gas companies begin to increase overall spending levels, it likely will ~~likely~~ be ~~for~~weighted towards production enhancement activities rather than ~~for~~ exploration projects. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide ~~abandonment~~P&A services at the end of the life of a field as required by governmental regulations. Thus, ~~over the longer term,~~ we believe that fundamentals for our business remain favorable over the longer term as the need ~~for prolongation of~~to prolong well life in oil and gas production is ~~the~~a primary driver of demand for our services.

Our current strategy is to be positioned for future market recovery while ~~coping with~~managing through a sustained period of weak activity. This strategy is based on ~~the following factors:~~multiple factors, including: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as ~~plug and abandonment~~P&A costs are considered; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling as well as extending and enhancing the commercial life of subsea wells; and (3) in past cycles, well intervention and workover have been some of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.

~~Helix Fast Response System~~

We ~~developed~~could see the ~~HFRS in 2011 as a culmination~~beginnings of ~~our experience as a responder~~an upturn in the ~~2010 Macondo well control and containment efforts. The HFRS centers on two of~~demand for our ~~vessels, the~~ ~~HP I~~ ~~and the~~ ~~Q4000, both of which played a key role in the Macondo well control and containment efforts and are currently operating~~services in the Gulf of ~~Mexico. The HFRS provides industry participants with a response resource~~Mexico, which are primarily driven by three factors: (1) long-term rig contracts are not being renewed thus removing some of the rig overhang that was considered by our customers to be ~~named in permit applications to federal and state agencies in exchange for~~ a ~~retainer fee. The HFRS agreements specify the day rates~~sunk cost; (2) previously deferred work on aging wells is less likely to be ~~charged should~~further deferred as well performance declines; and (3) North America customer spending shifts from unconventional onshore oil and gas to conventional offshore development and enhancement as returns from onshore investment opportunities diminish.

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Business Activity Summary

On January 16, 2019, we renewed the ~~HFRS be deployed in connection~~agreements that provide various operators with ~~a well control incident. The agreement providing~~ access to the HFRS ~~was amended effective February 1, 2017 to reduce~~for well control purposes through March 31, 2020 on newly agreed-upon rates and terms. These agreements automatically renew on an annual basis absent proper notice of termination.

On January 18, 2019, we acquired from Marathon Oil several wells and related infrastructure associated with the ~~retainer fee and to extend the term~~Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244. As part of the ~~agreement by one year~~transaction, Marathon Oil will pay us agreed-upon amounts for the required P&A of the acquired assets, which we can perform as our schedule permits, subject to ~~March 31, 2019.~~regulatory timelines. There is limited production associated with two wells that were acquired as part of the transaction.

31On May 29, 2019, we acquired a 70% controlling interest in STL, an Aberdeen-based subsea engineering company that specializes in the design and manufacture of subsea pressure control equipment, including well intervention, well control and subsea control systems.

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RESULTS OF OPERATIONS

We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our consolidated results of operations.

We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We ~~operate~~provide services primarily in deepwater in the ~~U.S.~~ Gulf of Mexico, Brazil, 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.~~regions. In addition to ~~servicing~~serving the oil and gas market, our Robotics ~~operations~~assets are contracted for the development of renewable energy projects (wind farms). As of September 30, ~~2017,~~2019, our consolidated backlog that is supported by written agreements or contracts totaled ~~$1.7 billion,~~$834 million, of which ~~$135.3~~$115 million is expected to be performed over the remainder of ~~2017.~~2019. The substantial majority of our backlog is associated with our Well Intervention business segment. As of September 30, ~~2017,~~2019, our well intervention backlog was ~~$1.3 billion,~~$627 million, including ~~$94.9~~$92 million expected to be performed over the remainder of ~~2017.~~2019. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petrobras to provide well intervention services offshore Brazil with the Siem Helix1 and Siem Helix2 chartered vessels, and our fixed fee agreement for the HP I represent approximately ~~87%~~86% of our total backlog as of September 30, ~~2017.~~2019. Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be added or subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable ~~sometimes~~ without penalty. ~~In addition, if~~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 ~~measure~~measures that isare commonly used but isare not a recognized accounting ~~term~~terms 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 ~~measure~~measures of EBITDA ~~provides~~and free cash flow provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand ~~our operating performance~~ and compare our results to other companies that have different financing, capital and tax structures.

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

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Other companies may calculate their measures of EBITDA, ~~and~~ Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. ~~Because~~EBITDA, Adjusted EBITDA and ~~Adjusted EBITDA are not financial measures calculated in accordance with U.S. GAAP, they~~free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with ~~U.S.~~ GAAP. The reconciliation of our net ~~loss~~income to EBITDA and Adjusted EBITDA is as follows (in thousands):


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2017			2016			2019			2018			2019			2018

Net income (loss)	$	2,290		$	11,462		$	(20,528	)	$	(27,032	)
Net income													$	31,622		$	27,121		$	49,763		$	42,345
Adjustments:
Income tax provision (benefit)	(1,539		)	3,649			(1,117		)	(9,858		)
Income tax provision													3,539			841			6,739			1,226
Net interest expense	3,615			6,843			15,480			25,007			1,901			3,249			6,204			10,744
(Gain) loss on early extinguishment of long-term debt	—			(244		)	397			(546		)
Other (income) expense, net	551			(830		)	619			(4,018		)
Loss on extinguishment of long-term debt													—			2			18			1,183
Other expense, net													2,285			709			2,430			3,225
Depreciation and amortization	26,293			27,607			82,670			84,846			27,908			27,680			84,420			83,339
EBITDA	31,210			48,487			77,521			68,399			67,255			59,602			149,574			142,062
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		)
Gain on disposition of assets, net													—			(146		)	—			(146		)
Realized losses from foreign exchange contracts not designated as hedging instruments													(982		)	(820		)	(2,763		)	(2,316		)
Other than temporary loss on note receivable													—			—			—			(1,129		)
Adjusted EBITDA	$	30,452		$	46,701		$	74,801		$	62,655		$	66,273		$	58,636		$	146,811		$	138,471

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



	Nine Months Ended September 30,
	2019			2018

Cash flows from operating activities	$	89,877		$	150,827
Less: Capital expenditures, net of proceeds from sale of assets	(43,086		)	(55,406		)
Free cash flow	$	46,791		$	95,421

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Comparison of Three Months Ended September 30, ~~2017~~2019 and ~~2016~~2018

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


	Three Months Ended September 30,						Increase/ (Decrease)			Three Months Ended September 30,						Increase/ (Decrease)
	2017			2016						2019			2018			Amount			Percent
Net revenues —
Well Intervention	$	111,522		$	108,287		$	3,235		$	170,206		$	154,441		$	15,765		10	%
Robotics	47,049			48,897			(1,848		)	51,909			54,340			(2,431		)	(4	)%
Production Facilities	16,380			17,128			(748		)	13,777			15,877			(2,100		)	(13	)%
Intercompany elimination	(11,691		)	(13,067		)	1,376
Intercompany eliminations										(23,283		)	(12,083		)	(11,200		)
	$	163,260		$	161,245		$	2,015		$	212,609		$	212,575		$	34		—	%

Gross profit (loss) —
Well Intervention	$	20,642		$	28,174		$	(7,532	)	$	41,014		$	37,833		$	3,181		8	%
Robotics	(6,991		)	4,953			(11,944		)	10,998			8,089			2,909			36	%
Production Facilities	7,780			8,413			(633		)	3,481			6,831			(3,350		)	(49	)%
Corporate and other	(489		)	(483		)	(6		)
Intercompany elimination	199			(873		)	1,072
Corporate, eliminations and other										(419		)	(760		)	341
	$	21,141		$	40,184		$	(19,043	)	$	55,074		$	51,993		$	3,081		6	%

Gross margin —
Well Intervention	19%			26%						24%			24%
Robotics	(15)%			10%						21%			15%
Production Facilities	47%			49%						25%			43%
Total company	13%			25%						26%			24%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	5/88%			5/76%						6/97%			6/91%
Robotics assets	60/46%			60/57%
Robotics assets ⁽³⁾										51/44%			54/42%
Chartered robotics vessels	5/80%			3/81%						4/96%			4/98%


(1)	Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters, and excluding acquired vessels prior to their in-service dates and vessels disposed of and/or taken out of ~~service prior to their disposition and vessels jointly owned with a third party.~~service.

(2)

Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of available calendar days in the applicable period. The average utilization rates of chartered robotics vessels during the three-month periods ended September 30, 2019 and 2018 included 28 and 113 spot vessel days, respectively, at near full utilization.


(3)	Consists of ROVs, trenchers and ROVDrill.


	Three Months Ended September 30,				Increase/ (Decrease)			Three Months Ended September 30,				Increase/ (Decrease)
	2017		2016		Increase/ (Decrease)			2019		2018		Increase/ (Decrease)

Well Intervention	$	3,765	$	2,898	$	867		$	15,318	$	4,379	$	10,939
Robotics	7,926		10,169		(2,243		)	7,965		7,704		261
	$	11,691	$	13,067	$	(1,376	)	$	23,283	$	12,083	$	11,200

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Net Revenues. Our total net revenues ~~increased by 1%~~ for the three-month period ended September 30, ~~2017~~2019 were consistent with those for the same period in 2018 reflecting a mix of higher revenues from our Well Intervention business segment, lower revenues from our Robotics and Production Facilities business segments, and higher intercompany eliminations.

Our Well Intervention revenues increased by 10% for the three-month period ended September 30, 2019 as compared to the same period in ~~2016. Increased revenues for the three-month period~~2018 reflecting increases in ~~2017 reflected higher~~ revenues in ~~our Well Intervention segment,~~the Gulf of Mexico and Brazil, partially offset ~~in part~~ by ~~revenue decreases in our Robotics and Production Facilities segments.~~

~~Our Well Intervention~~lower revenues increased by 3% for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting revenues generated from our well intervention operations in Brazil, offset in part by operational downtime experienced by the ~~Well Enhancer~~ in the North ~~Sea and $15.6 million we recognized in the third quarter of 2016 associated with a work scope cancellation under a “take or pay” contract originally scheduled to be performed by the~~ ~~Q4000~~ ~~in late 2016. In Brazil, the~~ ~~Siem Helix~~1 ~~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.~~Sea. In the Gulf of Mexico, the Q4000 generated higher revenues due to higher utilization and a higher number of integrated service projects. IRS rental revenues were also higher in the third quarter of 2019. Revenue increases from the Q4000 and IRS rental were partially offset by lower revenues from the Q5000 ~~was 75% utilized~~ due to lower utilization. Our Well Intervention revenues in the Gulf of Mexico during the third quarter of ~~2017~~2019 also included $10.6 million associated with P&A work on the Droshky wells for our Production Facilities segment, for which Marathon Oil remitted payment to us in September 2019. The increase in revenues in Brazil was primarily ~~due to 18 idle days~~a result of the Siem Helix2 achieving 99% utilization during the ~~off-hire period~~third quarter of ~~the BP contract. The vessel was 84% utilized~~2019 as compared to 90% during the same period in ~~2016.~~2018. The ~~Q4000~~decrease in revenues in the North Sea was ~~86% utilized during~~primarily attributable to lower rates and a weaker British pound as compared to the third quarter of ~~2017 as compared to being 93% utilized during the same period in 2016.~~2018.

Robotics revenues decreased by 4% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016.~~2018. The decrease primarily reflected lower ~~utilization of our robotics assets~~trenching activity and ~~accepting work at reduced rates,~~spot vessel utilization, offset in part by ~~the addition of the~~ higher rates on our Grand Canyon ~~III~~ ~~to our robotics fleet~~II chartered vessel and ~~30 additional days of spot vessel~~higher ROV utilization 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~~three-month period ended September 30, 2019 as ~~a result of~~compared to the ~~oil and gas industry downturn.~~same period in 2018.

Our Production Facilities revenues decreased by 4%13% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016, which reflected reduced retainer fees~~2018 primarily reflecting lower revenues from the ~~amended~~ HFRS ~~agreement~~during the third quarter of 2019, offset in part by production revenues from the oil and gas properties that ~~became effective February 1, 2017.~~we acquired from Marathon Oil in January 2019 (Note 2).

The increase in intercompany eliminations was primarily the result of $10.6 million in revenue that our Well Intervention business segment earned associated with its completion of P&A work on behalf of our Production Facilities segment.

Gross Profit (Loss). Our total gross profit ~~decreased~~increased by ~~47%~~6% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016.~~ 2018 reflecting higher gross profit generated by our Well Intervention and Robotics business segments, offset in part by lower gross profit in our Production Facilities business segment.

The gross profit related to our Well Intervention segment ~~decreased~~increased by ~~27%~~8% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily ~~reflecting~~as a result of higher revenues in the ~~$15.6 million~~Gulf of Mexico and Brazil, partially offset by lower revenues in ~~third quarter 2016 revenues associated with a take-or-pay contract.~~the North Sea.

The gross profit ~~associated with~~related to our Robotics segment ~~decreased~~increased by ~~241%~~36% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting ~~decreased utilization for~~higher revenues generated by our ~~robotics assets, accepting work with~~Grand CanyonII chartered vessel and lower ~~profit margins and increased~~costs due to the expiration in July 2019 of foreign currency exchange contracts to hedge the vessel’s charter payments (Note 17), offset in part by lower spot vessel ~~costs associated with the addition of the~~ ~~Grand Canyon III~~ ~~in May 2017.~~activity.

The gross profit related to our Production Facilities segment decreased by 8%49% for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting revenue decreases for the HFRS.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by ~~$2.3~~$4.7 million for the three-month period ended September 30, ~~2017 primarily attributable~~2019 as compared to ~~a $2.7 million charge in~~ the same period in ~~2016~~2018. The decrease was primarily attributable to compensation costs in the third quarter of 2018 that ~~was associated with the provision for uncertain collection of a portion of our note receivable~~were related to ~~our Robotics segment.~~liability PSU awards, which settled in January 2019 (Note 11).

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Net Interest Expense. Our net interest expense decreased by ~~$3.2~~$1.3 million for the three-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting ~~a decrease in interest expense and an increase in~~higher 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~~$5.1 million for the three-month period ended September 30, ~~2017~~2019 as compared to ~~$3.1~~$3.9 million for the same period in ~~2016.~~2018 as a result of the construction and completion of the Q7000.

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Other ~~Income (Expense),~~Expense, Net. ~~We reported~~ Net other expense ~~net, of $0.6~~increased by $1.6 million for the three-month period ended September 30, ~~2017~~2019 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~~2018 primarily reflecting a $1.3 million increase in 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).losses.

Income Tax ~~Provision (Benefit).~~Provision. Income tax ~~benefit~~provision was ~~$1.5~~$3.5 million for the three-month period ended September 30, ~~2017~~2019 as compared to ~~income tax provision of $3.6~~$0.8 million for the same period in ~~2016. The variance primarily reflected decreased profitability in the current year period.~~2018. The effective tax rate was ~~(204.9)%~~10.1% for the three-month period ended September 30, ~~2017~~2019 as compared to ~~24.1%~~3.0% for the same period in ~~2016.~~2018. The ~~variance~~increase was primarily attributable to improvements in profitability in the ~~earnings mix between our higher and lower tax rate jurisdictions.~~U.S. year over year (Note 7).

Comparison of Nine Months Ended September 30, ~~2017~~2019 and ~~2016~~2018

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


	Nine Months Ended September 30,						Increase/ (Decrease)			Nine Months Ended September 30,						Increase/ (Decrease)
	2017			2016						2019			2018			Amount			Percent
Net revenues —
Well Intervention	$	299,219		$	214,262		$	84,957		$	451,511		$	445,769		$	5,742		1	%
Robotics	102,078			119,805			(17,727		)	136,396			120,569			15,827			13	%
Production Facilities	47,965			54,567			(6,602		)	44,651			48,541			(3,890		)	(8	)%
Intercompany elimination	(31,145		)	(29,083		)	(2,062		)
Intercompany eliminations										(51,398		)	(33,417		)	(17,981		)
	$	418,117		$	359,551		$	58,566		$	581,160		$	581,462		$	(302	)	—	%

Gross profit (loss) —
Well Intervention	$	47,757		$	17,195		$	30,562		$	84,761		$	93,554		$	(8,793	)	(9	)%
Robotics	(29,376		)	(12,008		)	(17,368		)	14,546			(5,294		)	19,840			375	%
Production Facilities	21,031			25,634			(4,603		)	13,152			21,282			(8,130		)	(38	)%
Corporate and other	(1,370		)	(1,367		)	(3		)
Intercompany elimination	641			(542		)	1,183
Corporate, eliminations and other										(1,197		)	(1,669		)	472
	$	38,683		$	28,912		$	9,771		$	111,262		$	107,873		$	3,389		3	%

Gross margin —
Well Intervention	16%			8%						19%			21%
Robotics	(29)%			(10)%						11%			(4)%
Production Facilities	44%			47%						29%			44%
Total company	9%			8%						19%			19%

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	5/79%			5/52%						6/88%			6/84%
Robotics assets	60/42%			60/48%
Robotics assets ⁽³⁾										51/42%			54/37%
Chartered robotics vessels	5/61%			3/63%						4/92%			4/76%

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(1)	Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters, and excluding acquired vessels prior to their in-service dates and vessels disposed of and/or taken out of ~~service 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 nine-month periods ended September 30, 2019 and 2018 included 137 and 208 spot vessel days, respectively, at near full utilization.


(3)	Consists of ROVs, trenchers and ROVDrill.

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	Nine Months Ended September 30,				Increase/ (Decrease)			Nine Months Ended September 30,				Increase/ (Decrease)
	2017		2016		Increase/ (Decrease)			2019		2018		Increase/ (Decrease)

Well Intervention	$	8,033	$	5,740	$	2,293		$	28,355	$	10,546	$	17,809
Robotics	23,112		23,343		(231		)	23,043		22,871		172
	$	31,145	$	29,083	$	2,062		$	51,398	$	33,417	$	17,981

Net Revenues. Our total net revenues ~~increased by 16%~~ for the nine-month period ended September 30, ~~2017~~2019 were consistent with those for the same period in 2018 reflecting a mix of higher revenues from our Well Intervention and Robotics business segments, lower revenues from our Production Facilities business segment, and higher intercompany eliminations.

Our Well Intervention revenues increased by 1% for the nine-month period ended September 30, 2019 as compared to the same period in ~~2016. Increased revenues for the nine-month period in 2017 reflected~~2018, primarily reflecting higher revenues in ~~our Well Intervention segment,~~the Gulf of Mexico and Brazil, partially offset by lower revenues in ~~part~~the North Sea. The increase in revenues in the Gulf of Mexico was primarily attributable to higher utilization of the Q4000 during the first nine months of 2019 as compared to the same period in 2018. This revenue increase was offset by ~~revenue decreases~~a reduction in ~~our Robotics and Production Facilities segments.~~

IRS rental revenues during the comparative year-over-year periods. Our Well Intervention revenues in the Gulf of Mexico during the first nine months of 2019 also included $15.9 million associated with P&A work on the Droshky wells for our Production Facilities segment, for which Marathon Oil remitted payment to us in September 2019. The increase in revenues in Brazil was primarily a result of both the Siem Helix1 and the Siem Helix2 improving their utilization during the first nine months of 2019. The decrease in revenues in the North Sea primarily reflected a weaker British pound and lower rates as compared to the same period in 2018.

Robotics revenues increased by ~~40%~~13% for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018. The increase primarily ~~reflecting~~reflected higher ~~revenues generated from all of the well intervention vessels except for the~~ ~~Q4000. In Brazil, the~~ ~~Siem Helix~~1~~’s financial performance has improved since it commenced services for Petrobras in mid-April 2017, achieving year-to-date~~trenching activities that contributed to increased utilization of ~~96%. In the North Sea, the~~ ~~Well Enhancer~~ ~~was 81% utilized~~our chartered vessels (from 76% during the first nine months of ~~2017 while the vessel was 60% utilized~~2018 to 92% during the same period in ~~2016. The~~ ~~Seawell~~ ~~was 84% utilized during~~2019). Our robotics assets also achieved higher utilization in the first nine months of ~~2017 whereas it was 41% utilized during~~2019 as compared to 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.~~2018.

~~Robotics~~Our Production Facilities revenues decreased by ~~15%~~8% for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016. The decrease~~2018 primarily ~~reflected~~reflecting lower ~~utilization of our robotics assets and accepting work at reduced rates. Some of our ROV units have been affected~~revenues from the HFRS during the nine-month period ended September 30, 2019, offset in part by ~~other industry participants laying up vessels or canceling work as a result of~~production revenues from the oil and gas ~~industry downturn.~~properties that we acquired from Marathon Oil in January 2019 (Note 2).

~~Our~~The increase in intercompany eliminations was primarily the result of $15.9 million in revenue that our Well Intervention business segment earned associated with its completion of P&A work on behalf of our Production Facilities ~~revenues decreased~~segment.

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Gross Profit (Loss). Our total gross profit increased by ~~12%~~3% for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017~~2018 reflecting improvements in our Robotics business segment, offset in part by lower gross profit in our Well Intervention and ~~lower revenues from the fixed fee agreement with the Phoenix field operator for the~~ ~~HP I~~ ~~that commenced June 1, 2016.~~Production Facilities business segments.

~~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.~~ The gross profit related to our Well Intervention business segment ~~increased~~decreased by ~~178%~~9% for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting ~~higher revenues~~lower IRS rental unit utilization in ~~our~~the Gulf of Mexico as well as reduced operating results in the North Sea, ~~region.~~offset in part by improved operating results in Brazil.

~~The~~Our Robotics segment achieved a gross profit ~~associated with our Robotics segment decreased by 145%~~of $14.5 million for the nine-month period ended September 30, ~~2017~~2019 as compared to a gross loss of $5.3 million for the same period in ~~2016~~2018 primarily reflecting ~~decreased~~higher trenching revenues, with increased utilization for our chartered vessels and our robotics assets, and ~~accepting work with lower profit margins.~~a reduction in vessel charter costs.

The gross profit related to our Production Facilities segment decreased by ~~18%~~38% for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting revenue decreases for the ~~HFRS and the~~ ~~HP I~~.HFRS.

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Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by ~~$1.0~~$4.1 million for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016.~~2018. The ~~nine-month periods ended September 30, 2017 and 2016 included charges~~decrease was primarily attributable to compensation costs in the first nine months of ~~$1.2 million and $2.7 million, respectively,~~2018 that were ~~associated with the provision for uncertain collection of a portion of our receivables~~ related to ~~our Robotics segment.~~liability PSU awards, which settled in January 2019 (Note 11).

Net Interest Expense. Our net interest expense decreased by ~~$9.5~~$4.5 million for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016~~2018 primarily reflecting ~~increases in interest income and~~higher capitalized interest and a decrease in interest ~~expense. Interest income~~expense due to a reduction in our overall debt levels. Capitalized interest totaled ~~$2.1~~$15.3 million for the nine-month period ended September 30, ~~2017~~2019 as compared to ~~$1.7~~$11.5 million for the same period in ~~2016. Interest on debt used to finance capital projects is capitalized~~2018 as a result of the construction and ~~thus reduces overall interest expense. Capitalized interest totaled $12.6 million for~~completion of the nine-month period ended September 30, 2017 as compared to $7.5 million for the same period in 2016. 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. 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)Q7000.

~~Gain (Loss)~~Loss on ~~Early~~ Extinguishment of Long-Term Debt. The ~~$0.4~~$1.2 million loss for the nine-month period ended September 30, ~~2017~~2018 was ~~associated with~~attributable to the write-off of the unamortized debt issuance costs related to the ~~lenders exiting from~~prepayment of $61 million of the then-existing term loan ~~then outstanding under the credit agreement prior to its June 2017 amendment~~in March 2018 and ~~restatement (Note 6). The $0.5 million gain for the nine-month period ended September 30, 2016 was~~costs associated with ~~the repurchases totaling $14.9~~our repurchase of $59.3 million in aggregate principal amount of ~~our~~the 2032 Notes ~~in June and July of 2016.~~(Note 6).

Other ~~Income (Expense),~~Expense, Net. ~~We reported~~ Net other expense ~~net, of $0.6~~decreased by $0.8 million for the nine-month period ended September 30, ~~2017~~2019 as compared to ~~other income, net, of $4.0 million for~~ the same period in ~~2016. Net~~2018 primarily reflecting a $1.1 million other ~~income (expense) for~~than temporary loss on a note receivable during the nine-month ~~periods~~period ended September 30, 2017 and 2016 included 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 related to the contracts that were not designated as cash flow hedges (Note 14).2018.

Income Tax ~~Benefit.~~Provision. Income tax ~~benefit~~provision was ~~$1.1~~$6.7 million for the nine-month period ended September 30, ~~2017~~2019 as compared to ~~$9.9~~$1.2 million for the same period in ~~2016. The variance primarily reflected a 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.~~2018. The effective tax rate was ~~5.2%~~11.9% for the nine-month period ended September 30, ~~2017~~2019 as compared to ~~26.7%~~2.8% for the same period in ~~2016.~~2018. The ~~variance~~increase was primarily attributable to improvements in profitability in the ~~earnings mix between our higher and lower tax rate jurisdictions and the change in tax position related to our foreign taxes~~U.S. year over year (Note 7).

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LIQUIDITY AND CAPITAL RESOURCES

Overview

The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):


	September 30, 2017		December 31, 2016		September 30, 2019		December 31, 2018

Net working capital	$	268,817	$	336,387	$	199,934	$	259,440
Long-term debt ⁽¹⁾	$	395,345	$	558,396	304,932		393,063
Liquidity ⁽²⁾	$	426,741	$	375,504	458,971		426,813


(1)	Long-term debt does not include the current maturities portion of our long-term debt as that amount is included in net working capital. ItLong-term debt is also net of unamortized debt ~~discount~~discounts and debt issuance costs. See Note 6 for information relating to our ~~existing~~long-term debt.

(2)

Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under ~~our~~the Revolving Credit Facility, which capacity is reduced by letters of credit drawn against ~~the~~that facility. Our liquidity at September 30, ~~2017~~2019 included cash and cash equivalents of ~~$356.9~~$286.3 million ~~(including $100 million of minimum cash balance required by our Credit Agreement)~~ and ~~$69.9~~$172.6 million of available borrowing capacity under ~~our~~the Revolving Credit Facility (Note 6). Our liquidity at December 31, ~~2016~~2018 included cash and cash equivalents of ~~$356.6~~$279.5 million and ~~$18.9~~$147.4 million of available borrowing capacity under our ~~Revolving Credit Facility.~~then-existing revolving credit facility.

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


	September 30, 2017		December 31, 2016		September 30, 2019		December 31, 2018

Term Loan (previously scheduled to mature June 2018)	$	—	$	190,867
Term Loan (previously scheduled to mature June 2020)					$	—	$	33,321
Term Loan (matures December 2021)					33,687		—
Nordea Q5000 Loan (matures April 2020)	167,667		193,879		97,768		123,980
Term Loan (matures June 2020)	96,935		—
MARAD Debt (matures February 2027)	72,365		78,221		59,951		66,443
2022 Notes (mature May 2022) ⁽¹⁾	108,018		105,697		114,848		112,192
2032 Notes (mature March 2032) ⁽²⁾	58,971		57,303
2023 Notes (mature September 2023) ⁽¹⁾					107,146		104,379
Total debt	$	503,956	$	625,967	$	413,400	$	440,315


(1)	The 2022 Notes ~~will increase to their face amount through accretion of non-cash interest charges through May 1, 2022.~~


~~(2)~~	~~The 2032~~and the 2023 Notes will increase to their face ~~amount~~amounts through accretion of ~~non-cash interest charges~~their debt discounts through ~~March~~May 1, 2022 and September 15, ~~2018, which is the first date on which the holders may require us to repurchase the notes.~~2023, respectively.

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


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2019			2018
Cash provided by (used in):
Operating activities	$	31,323		$	15,444		$	89,877		$	150,827
Investing activities	$	(121,428	)	$	(42,266	)	(47,167		)	(55,406		)
Financing activities	$	88,420		$	17,217		(35,638		)	(35,974		)

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Our current requirements for cash primarily reflect the need to fund capital spending for our current lines of business and to service our debt. Historically, we have funded our capital program with cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives. As of September 30, 2019, the remaining principal balance of the Nordea Q5000 Loan was classified to current as its maturity date is April 30, 2020. Although we currently have no plans to do so, we have the ability to fund the repayment of the Nordea Q5000 Loan when due with available borrowing capacity under the Revolving Credit Facility.

As a further response to ~~the~~ industry-wide spending reductions, we continue to remain ~~even more~~ focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, defer or cancel certain planned capital expenditures. We believe that our cash on hand, internally generated cash flows and ~~available borrowing capacity~~availability under ~~our~~the Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.

In accordance with ~~our~~the Credit Agreement, the 2022 Notes, the ~~2032~~2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of a minimum cash balance, net worth, working capital and debt-to-equity requirements. ~~Our~~The 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~~the MARAD Debt and ~~our~~the Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. ~~Our~~The 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~~the Credit Agreement). As of September 30, ~~2017~~2019 and December 31, ~~2016,~~2018, we were in compliance with all of the covenants in our long-term debt agreements.

A prolonged period of weak industry activity may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to fully access ~~our~~the Revolving Credit Facility may be impacted. At September 30, ~~2017,~~2019, our available borrowing capacity under ~~our~~the Revolving Credit Facility, based on the applicable leverage ratio covenant, was ~~restricted to $69.9~~$172.6 million, net of ~~$4.0~~$2.4 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrow under ~~our~~the Revolving Credit Facility other than for ~~issuances~~the issuance of letters of credit. Our ability to comply with loan agreement covenants and other restrictions is affected by economic conditions and other events beyond our control. ~~If we fail~~Our failure 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 of up to $25 million under ~~our~~the Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding ~~our~~the Credit Agreement ~~including~~and related covenants and collateral.

The 2022 Notes and the ~~2032~~2023 Notes can be converted into our common stock by the holders or redeemed by us prior to their stated maturity ~~upon~~under certain ~~triggering events~~circumstances specified in the applicable ~~Indenture~~indenture governing the notes. ~~The holders~~We can settle any conversion in cash, shares of ~~the remaining 2032 Notes may require us to repurchase these notes~~our common stock or a combination thereof.

We repurchased $59.3 million in ~~March 2018. Accordingly,~~aggregate principal amount of the 2032 Notes ~~are classified as current liabilities~~ on ~~our consolidated balance sheet at September 30, 2017. No conversion triggers were met during~~March 20, 2018 and redeemed the ~~nine-month periods ended September 30, 2017 and 2016.~~remaining $0.8 million outstanding on May 4, 2018.

Operating Cash Flows

Total cash flows from operating activities ~~increased~~decreased by ~~$15.9~~$61.0 million for the nine-month period ended September 30, ~~2017~~2019 as compared to the same period in ~~2016. This increase was~~2018 primarily ~~attributable~~reflecting the timing of cash receipts from our customers and other increases in net working capital during the first nine months of 2019 as well as higher regulatory certification costs for our vessels and systems, which included costs related to ~~improvements in~~planned dry docks for three of our ~~operating results.~~vessels.

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Investing Activities

Capital expenditures ~~consist~~represent 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 sources (uses) of cash associated with investing activities are as follows (in thousands):

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	Nine Months Ended September 30,						Nine Months Ended September 30,
	2017			2016			2019			2018
Capital expenditures:
Well Intervention	$	(130,649	)	$	(79,147	)	$	(44,323	)	$	(54,845	)
Robotics	(691		)	(504		)	(388		)	(89		)
Production Facilities	—			(74		)	(123		)	(113		)
Other	(88		)	372			(802		)	(384		)
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
STL acquisition, net							(4,081		)	—
Proceeds from sale of assets							2,550			25
Net cash used in investing activities	$	(121,428	)	$	(42,266	)	$	(47,167	)	$	(55,406	)


~~(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~~Our capital expenditures ~~associated with our business~~above primarily ~~have~~ included payments associated with the construction and completion of ~~our~~ the 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~~entered into 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~~to be built to North Sea standards. ~~This $346.0 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 each of 2016, 2017 and 2018, and the remaining 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~~due upon the delivery of the ~~vessel, which at our option can be deferred until December30, 2018.~~vessel. We ~~agreed to pay~~have informed the shipyard ~~its incremental costs in connection with the contract amendments~~of our intent to ~~extend the scheduled~~take delivery of the ~~Q7000~~ ~~and to defer certain payment obligations.~~vessel in November 2019. At September 30, ~~2017,~~2019, our total investment in the Q7000 was ~~$213.6~~$446.4 million, including ~~$138.4~~$276.8 million of installment payments to the shipyard. We plan to incur approximately ~~$77~~$80 million ~~of costs~~ related to the ~~construction of the~~ Q7000 over the remainder of ~~2017.~~

~~In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil.~~2019, including the final shipyard payment of $69.2 million. The ~~initial term of the agreements with Petrobras~~vessel 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~~final preparation phase for work expected to ~~invest approximately $9 million~~commence in ~~the topside equipment over the remainder of 2017.~~early 2020.

Financing Activities

Cash flows from financing activities consist primarily of proceeds from debt and equity ~~financing activities~~transactions and repayments of our long-term debt. ~~Total~~Net cash ~~flows~~outflows from financing activities ~~increased by $71.2~~of $35.6 million for the nine-month period ended September 30, ~~2017~~2019 primarily reflected the repayment of $68.2 million of our indebtedness and $35.0 million in proceeds from the Term Loan (Note 6). Net cash outflows from financing activities of $36.0 million for the nine-month period ended September 30, 2018 primarily reflected the repayment of $156.6 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of $125 million of the 2023 Notes (Note 6).

Free Cash Flow

Free cash flow decreased by $48.6 million for the nine-month period ended September 30, 2019 as compared to the same period in ~~2016~~2018 primarily ~~reflecting net proceeds of approximately $220 million we received from our underwritten public equity offering~~attributable to the decrease in ~~January 2017 (Note 8) and the $100 million proceeds from our Term Loan borrowings in June 2017,~~operating cash flows, slightly 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 receivedreduced capital expenditures in the ~~nine-month period ended September 30, 2016 from the sale~~first nine months of ~~our common stock under at-the-market equity offering programs.~~2019.

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Outlook

We anticipate that our capital expenditures, including capitalized interest and ~~deferred dry dock~~regulatory certification costs for ~~2017~~our vessels and systems, will approximate ~~$245 million.~~$150 million for 2019. We believe that ~~our~~ cash on hand, internally generated cash flows and availability under ~~our~~the Revolving Credit Facility will provide the capital necessary to continue funding our ~~2017~~2019 capital ~~spending.~~obligations and to meet our debt obligations due in 2019. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the level of our planned capital expenditures given a prolonged industry downturn.

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Contractual Obligations and Commercial Commitments

The following table summarizes our contractual cash obligations as of September 30, ~~2017~~2019 and the scheduled years in which the obligations are contractually due (in thousands):


	Total ⁽¹⁾		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years		Total ⁽¹⁾		Less Than 1 Year		1-3 Years		3-5 Years		More Than 5 Years

Term Loan	$	98,750	$	6,250	$	92,500	$	—	$	—	$	34,125	$	3,500	$	30,625	$	—	$	—
Nordea Q5000 Loan	169,643		35,714		133,929		—		—		98,214		98,214		—		—		—
MARAD Debt	77,000		6,532		14,058		15,497		40,913		63,610		7,200		15,497		17,082		23,831
2022 Notes ⁽²⁾	125,000		—		—		125,000		—		125,000		—		125,000		—		—
2032 Notes ⁽³⁾	60,115		60,115		—		—		—
2023 Notes ⁽³⁾											125,000		—		—		125,000		—
Interest related to debt ⁽⁴⁾	78,706		23,411		35,804		14,614		4,877		55,365		18,620		26,941		8,207		1,597
Property and equipment ⁽⁵⁾	262,626		113,149		149,477		—		—		80,261		80,261		—		—		—
Operating leases ⁽⁶⁾	694,257		140,345		250,424		207,824		95,664		405,123		110,197		193,669		94,408		6,849
Total cash obligations	$	1,566,097	$	385,516	$	676,192	$	362,935	$	141,454	$	986,698	$	317,992	$	391,732	$	244,697	$	32,277


(1)	Excludes unsecured letters of credit outstanding at September 30, ~~2017~~2019 totaling ~~$4.0~~$2.4 million. These letters of credit may be issued to support various obligations, such as contractual obligations, contract bidding and insurance activities.

(2)

Notes mature in May 2022. The 2022 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $18.06 per share, which is 130% of ~~their issuance price on that 30th trading day (i.e., $18.06 per share).~~the conversion price. At September 30, ~~2017,~~2019, the conversion trigger was not met. See Note 6 for additional information.

(3)

Notes mature ~~March 2032.~~in September 2023. The ~~2032~~2023 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $12.31 per share, which is 130% of ~~their issuance price on that 30th trading day (i.e., $32.53 per share).~~the conversion price. At September 30, ~~2017,~~2019, 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.~~ See Note 6 for additional information.


(4)	Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at September 30, ~~2017~~2019 for variable rate debt.


(5)	Primarily reflects costs associated with ~~our~~ the Q7000 ~~semi-submersible well intervention vessel~~, which is currently under ~~construction and the topside equipment for the~~ ~~Siem Helix 2~~ ~~chartered vessel~~completion (Note ~~12)~~14).

(6)

Operating leases include vessel charters and facility and equipment leases. At September 30, ~~2017,~~2019, our commitment related to long-term vessel ~~charter commitments~~charters totaled approximately ~~$652.3~~$366.2 million, ~~including~~of which $147.2 million is related to the ~~Grand Canyon III~~non-lease (services) components that ~~went into service for us~~are 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 late in the fourth quarter of 2017.~~

operating lease liabilities on our balance sheet.

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CRITICAL ACCOUNTING POLICIES AND ESTIMATES

Our discussion and analysis of our financial condition and results of operations are based upon our condensed consolidated financial statements. We prepare these financial statements and related footnotes in conformity with ~~accounting principles generally accepted in the United States.~~GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes.

For ~~additional~~ information regarding our critical accounting policies and estimates, please read our “Critical Accounting Policies and Estimates” as disclosed in our ~~2016~~2018 Form 10-K.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are ~~currently~~ exposed to market ~~risk in two areas:~~risks associated with interest rates and foreign currency exchange rates.

Interest Rate Risk. As of September 30, ~~2017, $268.4~~2019, $132.3 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may continue to rise, thereby increasing our interest expense and related cash outlay. In June 2015, we entered into various interest rate swap contracts to fix the interest rate on ~~$187.5 million~~a portion of ~~our~~the Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. As of September 30, 2019, the interest rate on $73.6 million of the Nordea Q5000 Loan was hedged. Debt subject to variable rates after considering hedging activities was $58.7 million. The impact of interest rate risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional ~~$1.5~~$0.5 million in interest expense for the nine-month period ended September 30, ~~2017.~~2019.

Foreign Currency Exchange Rate Risk. Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. As such, our earnings are ~~subject to~~impacted 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, we generally pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts provide for collections from customers in U.S. dollars. During the nine-month period ended September 30, ~~2017,~~2019, we recognized losses of ~~$2.2~~$2.0 million related to foreign currency transactions in “Other ~~income (expense),~~expense, net” in our condensed consolidated statement of operations.

Our cash flows are subject to fluctuations resulting from changes in foreign currency exchange rates. Fluctuations in exchange rates are likely to impact our results of operations and cash flows. As a result, we entered into various foreign currency exchange contracts to stabilize expected cash outflows related to certain vessel charters denominated in Norwegian kroners. In 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~~various 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~~A portion of ~~our~~these 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~~qualifies for cash flow hedge accounting treatment. ~~There was no foreign currency hedge ineffectiveness for the nine-month period ended September 30, 2017.~~

~~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.~~2019. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of September 30, ~~2017~~2019 to ensure that information that is required to be disclosed by us in the reports we file or submit under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms; and (ii) accumulated and communicated to our management, as appropriate, to allow timely decisions regarding required disclosure.

(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, ~~2017~~2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

~~Table of Contents~~

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 1214 to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Table of Contents

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

Issuer Purchases of Equity Securities

~~Period~~

~~(a)~~

~~Total number~~

~~of shares~~

~~purchased~~

~~(b)~~

~~Average~~

~~price paid~~

~~per share~~

~~(c)~~

~~Total number~~

~~of shares~~

~~purchased as~~

~~part of publicly~~

~~announced~~

~~program~~

~~(d)~~

~~Maximum~~

~~number of shares~~

~~that may yet be~~

~~purchased under~~

~~the program~~ ⁽¹⁾

~~July 1 to July 31, 2017~~

—

~~3,079,889~~

~~August 1 to August 31, 2017~~

—

~~3,079,889~~

~~September 1 to September 30, 2017~~

—

~~3,108,697~~

—



Period	(a) Total number of shares purchased ⁽¹⁾	(b) Average price paid per share		(c) Total number of shares purchased as part of publicly announced program	(d) Maximum number of shares that may yet be purchased under the program ⁽²⁾
July 1 to July 31, 2019	—	$	—	—	4,707,227
August 1 to August 31, 2019	2,255	7.34		—	4,714,378
September 1 to September 30, 2019	—	—		—	4,743,694
	2,255	$	7.34	—


(1)	Includes shares forfeited in satisfaction of tax obligations upon vesting of restricted shares.


(2)	Under the terms of our stock repurchase program, the issuance of shares to members of our Board and to certain employees, including shares issued under the ESPP to participating employees (Note ~~10)~~11), increases the ~~amount~~number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 109 to our ~~2016~~2018 Form 10-K.

Item 6. Exhibits



Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1	2005 Amended and Restated Articles of Incorporation of ~~Helix.~~Helix Energy Solutions Group, Inc.	Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)
3.2	Second Amended and Restated By-Laws of ~~Helix.~~Helix Energy Solutions Group, Inc.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
31.1	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.	Filed herewith
31.2	Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer.	Filed herewith
32.1	Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the ~~Sarbanes —~~ Sarbanes–Oxley Act of 2002.	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	XBRL Schema Document.	Filed herewith
101.CAL	XBRL Calculation Linkbase Document.	Filed herewith
101.PRE	XBRL Presentation Linkbase Document.	Filed herewith
101.DEF	XBRL Definition Linkbase Document.	Filed herewith
101.LAB	XBRL Label Linkbase Document.	Filed herewith

4546

Table of Contents

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~~23, 2019	By:	/s/ Owen Kratz
			Owen Kratz President and Chief Executive Officer (Principal Executive Officer)

Date:	October ~~24, 2017~~23, 2019	By:	/s/ Erik Staffeldt
			Erik Staffeldt ~~Senior~~Executive Vice President and Chief Financial Officer (Principal Financial Officer)

4647



	September 30, 2017		December 31, 2016

Note receivable ⁽¹⁾	$	—	$	10,000
Prepaid insurance	2,432		4,426
Other prepaids	10,021		9,547
Deferred costs ⁽²⁾	20,704		7,971
Spare parts inventory	1,598		2,548
Income tax receivable	—		880
Value added tax receivable	2,169		1,345
Other	1,248		671
Total other current assets	$	38,172	$	37,388



	September 30, 2017		December 31, 2016

Note receivable, net ⁽¹⁾	$	3,129	$	2,827
Prepaids	8,112		6,418
Deferred dry dock costs, net	14,260		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
Other	2,181		1,511
Total other assets, net	$	100,974	$	72,549



	September 30, 2017		December 31, 2016
			��
Accrued payroll and related benefits	$	29,682	$	20,705
Deferred revenue	8,664		8,911
Accrued interest	2,997		3,758
Derivative liability (Note 14)	9,927		18,730
Taxes payable excluding income tax payable	1,209		1,214
Other	8,282		5,296
Total accrued liabilities	$	60,761	$	58,614



	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



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



	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



	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 contracts	Cost of sales	$	(3,288	)	$	(2,663	)	$	(10,280	)	$	(8,033	)
Interest rate swaps	Net interest expense	(95		)	(494		)	(542		)	(1,618		)
		$	(3,383	)	$	(3,157	)	$	(10,822	)	$	(9,651	)



	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 contracts	Other income (expense), net	$	1,050	$	1,309	$	1,531	$	3,375
		$	1,050	$	1,309	$	1,531	$	3,375