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~~

2023



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

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

~~(281)~~

(281) 618–0400

(~~Registrant's~~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, no par value	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.

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~~2023, 150,711,229 shares of common stock were outstanding.

Table of Contents

TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION	PAGE
~~PART I.~~	~~FINANCIAL INFORMATION~~	~~PAGE~~
Item 1.	Financial Statements:	3
~~Item 1.~~	~~Financial Statements:~~

	Condensed Consolidated Balance Sheets – September 30, ~~2017~~2023 (Unaudited) and December 31, ~~2016~~2022	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three and nine months ended September 30, ~~2017~~2023 and ~~2016~~2022	4

	~~Condensed Consolidated Statements of Operations (Unaudited) –~~ ~~Nine months ended September 30, 2017 and 2016~~	5

	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three and nine months ended September 30, ~~2017~~2023 and ~~2016~~2022	6 4

	Condensed Consolidated Statements of Shareholders’ Equity (Unaudited) – Three and nine months ended September 30, 2023 and 2022	5

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Nine months ended September 30, ~~2017~~2023 and ~~2016~~2022	7 6

	Notes to Condensed Consolidated Financial Statements (Unaudited)	8 7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	29 24

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	43 39

Item 4.	Controls and Procedures	44 39

PART II.	OTHER INFORMATION	40

Item 1.	Legal Proceedings	45 40

Item 1A.	Risk Factors	40

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45 40

Item 6.3.	~~Exhibits~~Defaults Upon Senior Securities	45 40

Item 4.	~~Signatures~~Mine Safety Disclosures	40

46Item 5.	Other Information	40

Item 6.	Exhibits	41

	Signatures	42

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
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents $ 356,889
$ 356,647
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively 90,480
101,825
Unbilled revenue and other 45,816
10,328
Current deferred tax assets —
16,594
Other current assets 38,172
37,388
Total current assets 531,357
522,782
Property and equipment 2,612,407
2,450,890
Less accumulated depreciation (878,248 ) (799,280 )
Property and equipment, net 1,734,159
1,651,610
Other assets, net 100,974
72,549
Total assets $ 2,366,490
$ 2,246,941

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable $ 91,412
$ 60,210
Accrued liabilities 60,761
58,614
Income tax payable 1,756
—
Current maturities of long-term debt 108,611
67,571
Total current liabilities 262,540
186,395
Long-term debt 395,345
558,396
Deferred tax liabilities 154,158
167,351
Other non-current liabilities 42,736
52,985
Total liabilities 854,779
965,127
Commitments and contingencies

Shareholders’ equity:

Common stock, no par, 240,000 shares authorized, 147,713 and 120,630 shares issued, respectively 1,281,747
1,055,934
Retained earnings 302,326
322,854
Accumulated other comprehensive loss (72,362 ) (96,974 )
Total shareholders’ equity
1,511,711
1,281,814
Total liabilities and shareholders’ equity
$ 2,366,490
$ 2,246,941


	September 30,		December 31,
	2023		2022
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	168,370	$	186,604
Restricted cash		—		2,507
Accounts receivable, net of allowance for credit losses of $3,297 and $2,277, respectively		308,023		212,779
Other current assets		78,584		58,699
Total current assets		554,977		460,589
Property and equipment		3,049,952		3,016,312
Less accumulated depreciation		(1,475,042)		(1,374,697)
Property and equipment, net		1,574,910		1,641,615
Operating lease right-of-use assets		181,610		197,849
Deferred recertification and dry dock costs, net		75,778		38,778
Other assets, net		47,477		50,507
Total assets	$	2,434,752	$	2,389,338

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	142,217	$	135,267
Accrued liabilities		178,118		73,574
Current maturities of long-term debt		8,749		38,200
Current operating lease liabilities		61,191		50,914
Total current liabilities		390,275		297,955
Long-term debt		218,508		225,875
Operating lease liabilities		129,455		154,686
Deferred tax liabilities		105,823		98,883
Other non-current liabilities		60,173		95,230
Total liabilities		904,234		872,629
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 150,706 and 151,935 shares issued, respectively		1,290,940		1,298,740
Retained earnings		340,783		323,288
Accumulated other comprehensive loss		(101,205)		(105,319)
Total shareholders’ equity		1,530,518		1,516,709
Total liabilities and shareholders’ equity	$	2,434,752	$	2,389,338

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,
2017 2016

Net revenues $ 163,260
$ 161,245
Cost of sales 142,119
121,061
Gross profit 21,141
40,184
Selling, general and administrative expenses (16,374 ) (18,714 )
Income from operations 4,767
21,470
Equity in losses of investment (153 ) (122 )
Net interest expense (3,615 ) (6,843 )
Gain on early extinguishment of long-term debt —
244
Other income (expense), net (551 ) 830
Other income (expense) – oil and gas 303
(468 )
Income before income taxes 751
15,111
Income tax provision (benefit) (1,539 ) 3,649
Net income $ 2,290
$ 11,462

Earnings per share of common stock:
Basic $ 0.02
$ 0.10
Diluted $ 0.02
$ 0.10

Weighted average common shares outstanding:
Basic 145,958
113,680
Diluted 145,958
113,680


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Net revenues	$	395,670	$	272,547	$	954,571	$	585,284
Cost of sales		315,125		233,332		803,493		566,032
Gross profit		80,545		39,215		151,078		19,252
Gain on disposition of assets, net		—		—		367		—
Acquisition and integration costs		—		(762)		(540)		(2,349)
Change in fair value of contingent consideration		(16,499)		(2,664)		(31,319)		(2,664)
Selling, general and administrative expenses		(27,818)		(23,563)		(71,456)		(53,966)
Income (loss) from operations		36,228		12,226		48,130		(39,727)
Equity in earnings of investment		—		78		—		8,262
Net interest expense		(4,152)		(4,644)		(12,567)		(14,617)
Other expense, net		(8,257)		(20,271)		(10,553)		(37,623)
Royalty income and other		78		348		2,116		3,286
Income (loss) before income taxes		23,897		(12,263)		27,126		(80,419)
Income tax provision		8,337		6,500		9,631		10,074
Net income (loss)	$	15,560	$	(18,763)	$	17,495	$	(90,493)

Earnings (loss) per share of common stock:
Basic	$	0.10	$	(0.12)	$	0.12	$	(0.60)
Diluted	$	0.10	$	(0.12)	$	0.11	$	(0.60)

Weighted average common shares outstanding:
Basic		150,550		151,331		151,031		151,226
Diluted		153,622		151,331		153,936		151,226

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 (LOSS)

(UNAUDITED)

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

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

thousands)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Net income (loss)	$	15,560	$	(18,763)	$	17,495	$	(90,493)
Other comprehensive income (loss), net of tax:
Foreign currency translation gain (loss)		(16,603)		(33,453)		4,114		(79,939)
Other comprehensive income (loss), net of tax		(16,603)		(33,453)		4,114		(79,939)
Comprehensive income (loss)	$	(1,043)	$	(52,216)	$	21,609	$	(170,432)

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

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 )


						Accumulated
						Other		Total
	Common Stock			Retained		Comprehensive		Shareholders’
	Shares	Amount		Earnings		Loss		Equity
Balance, June 30, 2023	150,810	$	1,291,307	$	325,223	$	(84,602)	$	1,531,928
Net income	—		—		15,560		—		15,560
Foreign currency translation adjustments	—		—		—		(16,603)		(16,603)
Settlement of convertible debt conversion	—		(415)		—		—		(415)
Repurchases of common stock	(174)		(1,939)		—		—		(1,939)
Activity in company stock plans, net and other	70		481		—		—		481
Share-based compensation	—		1,506		—		—		1,506
Balance, September 30, 2023	150,706	$	1,290,940	$	340,783	$	(101,205)	$	1,530,518

Balance, June 30, 2022	151,714	$	1,295,016	$	339,342	$	(102,568)	$	1,531,790
Net loss	—		—		(18,763)		—		(18,763)
Foreign currency translation adjustments	—		—		—		(33,453)		(33,453)
Activity in company stock plans, net and other	94		274		—		—		274
Share-based compensation	—		2,006		—		—		2,006
Balance, September 30, 2022	151,808	$	1,297,296	$	320,579	$	(136,021)	$	1,481,854


						Accumulated
						Other		Total
	Common Stock			Retained		Comprehensive		Shareholders’
	Shares	Amount		Earnings		Loss		Equity
Balance, December 31, 2022	151,935	$	1,298,740	$	323,288	$	(105,319)	$	1,516,709
Net income	—		—		17,495		—		17,495
Foreign currency translation adjustments	—		—		—		4,114		4,114
Settlement of convertible debt conversion	—		(415)		—		—		(415)
Repurchases of common stock	(1,584)		(12,068)		—		—		(12,068)
Activity in company stock plans, net and other	355		185		—		—		185
Share-based compensation	—		4,498		—		—		4,498
Balance, September 30, 2023	150,706	$	1,290,940	$	340,783	$	(101,205)	$	1,530,518

Balance, December 31, 2021	151,124	$	1,292,479	$	411,072	$	(56,082)	$	1,647,469
Net loss	—		—		(90,493)		—		(90,493)
Foreign currency translation adjustments	—		—		—		(79,939)		(79,939)
Activity in company stock plans, net and other	684		(673)		—		—		(673)
Share-based compensation	—		5,490		—		—		5,490
Balance, September 30, 2022	151,808	$	1,297,296	$	320,579	$	(136,021)	$	1,481,854

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,
2017 2016
Cash flows from operating activities:
Net loss $ (20,528 ) $ (27,032 )
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization 82,670
84,846
Amortization of debt discount 3,487
4,655
Amortization of debt issuance costs 5,238
6,430
Share-based compensation 7,613
4,351
Deferred income taxes (3,019 ) (6,726 )
Equity in losses of investment 457
366
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:
Accounts receivable, net (21,709 ) (27,346 )
Other current assets (12,145 ) (10,853 )
Income tax receivable 2,742
20,576
Accounts payable and accrued liabilities 30,675
(1,794 )
Other non-current, net (40,303 ) (22,201 )
Net cash provided by operating activities 31,323
15,444

Cash flows from investing activities:
Capital expenditures (131,428 ) (79,353 )
Distribution from equity investment —
1,200
Proceeds from sale of equity investment —
25,000
Proceeds from sale of assets 10,000
10,887
Net cash used in investing activities (121,428 ) (42,266 )

Cash flows from financing activities:
Proceeds from term loan 100,000
—
Repayment of term loan (193,508 ) (30,500 )
Repayment of Nordea Q5000 Loan (26,786 ) (26,786 )
Repayment of MARAD Debt (6,222 ) (5,926 )
Repurchase of Convertible Senior Notes due 2032 —
(13,400 )
Debt issuance costs (3,694 ) (1,230 )
Net proceeds from issuance of common stock 219,504
94,538
Payments related to tax withholding for share-based compensation (1,306 ) (187 )
Proceeds from issuance of ESPP shares 432
708
Net cash provided by financing activities 88,420
17,217

Effect of exchange rate changes on cash and cash equivalents 1,927
(2,481 )
Net increase (decrease) in cash and cash equivalents 242
(12,086 )
Cash and cash equivalents:
Balance, beginning of year 356,647
494,192
Balance, end of period $ 356,889
$ 482,106


	Nine Months Ended
	September 30,
	2023		2022
Cash flows from operating activities:
Net income (loss)	$	17,495	$	(90,493)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		120,013		102,590
Amortization of debt issuance costs		1,840		1,744
Share-based compensation		4,765		5,630
Deferred income taxes		6,940		2,876
Equity in earnings of investment		—		(8,262)
Gain on disposition of assets, net		(367)		—
Unrealized foreign currency loss		11,587		38,374
Change in fair value of contingent consideration		31,319		2,664
Changes in operating assets and liabilities:
Accounts receivable, net		(96,027)		(50,268)
Other current assets		(16,774)		(19,888)
Income tax payable, net of income tax receivable		(2,518)		1,818
Accounts payable and accrued liabilities		31,142		42,953
Deferred recertification and dry dock costs, net		(59,216)		(25,583)
Other, net		7,521		(2,759)
Net cash provided by operating activities		57,720		1,396

Cash flows from investing activities:
Alliance acquisition, net of cash acquired		—		(112,625)
Capital expenditures		(16,165)		(4,990)
Distribution from equity investment, net		—		7,840
Proceeds from sale of assets		365		—
Net cash used in investing activities		(15,800)		(109,775)

Cash flows from financing activities:
Payments related to convertible senior notes		(30,415)		(35,000)
Repayment of MARAD Debt		(8,333)		(7,937)
Debt issuance costs		(236)		(550)
Repurchases of common stock		(11,988)		—
Payments related to tax withholding for share-based compensation		(1,385)		(1,525)
Proceeds from issuance of ESPP shares		982		575
Net cash used in financing activities		(51,375)		(44,437)

Effect of exchange rate changes on cash and cash equivalents and restricted cash		(11,286)		(9,537)
Net decrease in cash and cash equivalents and restricted cash		(20,741)		(162,353)
Cash and cash equivalents and restricted cash:
Balance, beginning of year		189,111		327,127
Balance, end of period	$	168,370	$	164,774

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

Note 1 — Basis of Presentation and New Accounting Standards

The accompanying condensed consolidated financial statements include the accounts of Helix Energy Solutions Group, Inc. and its subsidiaries (collectively, “Helix” ~~or the “Company”~~). Unless the context indicates otherwise, the terms “we,” “us” and “our” in this report refer collectively to Helix and its subsidiaries. All material intercompany accounts and transactions have been eliminated. These unaudited condensed consolidated financial statements in U.S. dollars have been prepared ~~pursuant to~~in accordance with 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 U.S. GAAP and are consistent in all material respects with those applied in our 2016 Annual Report on Form 10-K (“2016 Form 10-K”).

The preparation of these financial statements requires us to make estimates and judgments that affect the amounts reported in the financial statements and the related disclosures. Actual results may differ from our estimates. 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),~~loss, statements of shareholders’ equity and statements of cash flows, as applicable. The operating results for the three- and nine-month periods ended September 30, ~~2017~~2023 are not necessarily indicative of the results that may be expected for the year ending December 31, ~~2017.~~2023. Our balance sheet as of December 31, ~~2016~~2022 included herein has been derived from the audited balance sheet as of December 31, ~~2016~~2022 included in our ~~2016~~2022 Annual Report on Form ~~10-K.~~10-K (our “2022 Form 10-K”). These unaudited condensed consolidated financial statements should be read in conjunction with the audited annual ~~audited~~ consolidated financial statements and notes thereto included in our ~~2016~~2022 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.

In May 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU provides a five-step approach to account for revenue arising from contracts with customers. The ASU requires an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This revenue standard was originally effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods, and was subsequently deferred by one year to annual reporting periods beginning after December 15, 2017. The FASB also issued several subsequent updates containing implementation guidance on principal versus agent considerations (gross versus net revenue presentation), identifying performance obligations and accounting for licenses of intellectual property. Additionally, these updates provide narrow-scope improvements and practical expedients as well as technical corrections and improvements to the guidance. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. Our assessment at this stage is that we

We do not expect ~~the new revenue standard~~any recently issued accounting standards to have a material impact on our ~~consolidated~~ financial ~~statements upon adoption. We continue working on expanded disclosure requirements and documentation~~position, results of ~~new policies, procedures and controls. We currently intend on adopting this guidance using the modified retrospective method.~~

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

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In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU amends the existing accounting standards for leases. The amendments are intended to increase transparency and comparability among organizations by requiring recognition of lease assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. The guidance is required to be adopted at the earliest period presented using a modified retrospective approach. We expect to adopt this guidance in the first quarter of 2019. We are currently evaluating the impact these amendments will have on our consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equityoperations or ~~liabilities, and classification in the statement of~~ cash flows. Our share-based awards typically vest in the beginning of each year. The adoption of this guidance had no material impact on our consolidated financial statements for the three- and nine-month periods ended September 30, 2017.

In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU replaces the current incurred loss model for measurement of credit losses on financial assets including trade receivables with a forward-looking expected loss model based on historical experience, current conditions and reasonable and supportable forecasts. The guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

In October 2016, the FASB issued ASU No. 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” This ASU eliminates the exception in current guidance that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. Under the new ASU, an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventoryflows when the transfer occurs. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

In May 2017, the FASB issued ASU No. 2017-09, “Scope of Modification Accounting.” This ASU provides guidance about which changes to the terms or conditions of a share-based payment award require application of modification accounting. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We do not expect this ASU to have a material impact on our consolidated financial statements.

In August 2017, the FASB issued ASU No. 2017-12, “Targeted Improvements to Accounting for Hedging Activities.” This ASU improves the financial reporting of hedging relationships to better align risk management activities in financial statements and makes certain targeted improvements to simplify the application of the hedge accounting guidance in current GAAP. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.

they become effective.

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, robotics and ~~robotics~~decommissioning operations. ~~We seek to provide~~Our services ~~and methodologies that we believe~~ are ~~critical to maximizing production economics.~~ centered on a three-legged business model well positioned for a global energy transition:

●

Production maximization — our assets and methodologies are specifically designed to efficiently enhance and extend the lives of existing oil and gas reserves; we also offer an alternative to take over end-of-life reserves in preparation for their abandonment;

●

Decommissioning — we are a full-field abandonment contractor and believe that regulatory push for plug and abandonment (“P&A”) and transition to renewable energy will facilitate the continued growth of the abandonment market; and

●

Renewable energy support — we are an established global leader in jet trenching and provide specialty support services to offshore wind farm developments, including boulder removal and unexploded ordnance clearance.

We provide services primarily in ~~deepwater in~~ the ~~U.S.~~ Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa ~~regions, and have~~regions. We expanded our ~~operations into Brazil~~service capabilities to the Gulf of Mexico shelf with the ~~commencement~~acquisition of Alliance group of companies (collectively “Alliance”) on July 1, 2022 (Note 3), which we re-branded as Helix Alliance. Our North Sea operations and our Gulf of Mexico shelf operations related to Helix Alliance are usually subject to seasonal changes in demand, which generally peaks in the ~~Siem Helix 1~~summer months and declines in ~~mid-April 2017.~~the winter months. Our ~~“life of field”~~ services are segregated into ~~three~~four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment, which was formed in the third quarter 2022 comprising the Helix Alliance business (Note 12), and Production ~~Facilities (Note 11).~~Facilities.

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Our Well Intervention segment ~~includes~~provides services enabling our ~~vessels~~customers to safely access subsea offshore wells for the purpose of performing production enhancement or decommissioning operations, thereby avoiding drilling new wells by extending the useful lives of existing wells and ~~equipment used to perform~~preserving the environment by preventing uncontrolled releases of oil and gas. Our well intervention ~~services primarily in~~vessels include the ~~U.S. Gulf of Mexico, North Sea~~Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and ~~Brazil.~~two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. Our ~~Well Intervention segment also~~well intervention equipment includes intervention systems such as intervention riser systems (“IRSs”), ~~some of which we rent out on a stand-alone basis, and~~ subsea intervention lubricators (“SILs”). and the Riserless Open-water Abandonment Module, some of which we provide on a stand-alone basis.

Our Robotics segment provides trenching, seabed clearance, offshore construction and inspection, repair and maintenance (“IRM”) services to both the oil and gas and the renewable energy markets globally, thereby assisting the delivery of clean and reliable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our robotics services are used in and complement our well intervention ~~vessels include the~~ ~~Q4000, the~~ ~~Q5000, the~~ ~~Seawell, the~~ ~~Well Enhancer~~ ~~and two chartered vessels, the~~ ~~Siem Helix 1~~ ~~which is used and the~~ ~~Siem Helix 2~~ ~~which is to be used in connection with our contracts to provide well intervention services offshore Brazil. We also have a semi-submersible well intervention vessel under construction, the~~ ~~Q7000~~.

services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, the IROV boulder grab and ~~ROVDrills designed to complement offshore construction and well intervention services, and currently operates four chartered ROV~~robotics support vessels under term charters as well as spot vessels as needed. We offer our ROVs, trenchers and the IROV on a stand-alone basis or on an integrated basis with chartered robotics support vessels.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat, P&A systems and coiled tubing systems. During the ~~Grand Canyon III~~ ~~that went into service~~third quarter 2023, we acquired assets primarily consisting of five operable P&A systems for ustotal consideration of $17.6 million including $6.0 million in ~~May 2017.~~

cash in addition to credits towards future services offered by us.

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~~combines the HP I, the Q4000 and the Q5000 with certain ~~operators access~~well control equipment that can be deployed to ~~our~~ ~~Q4000~~ ~~and~~ ~~HP I~~ ~~vessels in the event of~~respond to a well control incident, and our ownership of mature oil and gas properties (Note 13). All of our current Production Facilities activities are located in the Gulf of Mexico.

Note 3 — Alliance Acquisition

On July 1, 2022, we completed our acquisition of Alliance. The ~~HP I~~ ~~has been under contract since February 2013 to process production from~~Alliance acquisition extended our energy transition strategy by adding shallow water capabilities into the ~~Phoenix field for~~growing offshore decommissioning market.

The aggregate purchase price of the ~~field operator. We currently operate under a fixed fee agreement for~~Alliance acquisition was $145.7 million, consisting of $119.0 million of cash on hand and the ~~HP I~~ ~~for service~~acquisition-date estimated fair value of $26.7 million of contingent consideration related to the ~~Phoenix field until at least June 1, 2023. We are party to an agreement providing various operators with access~~post-closing earn-out consideration. The earn-out is payable in 2024 to the ~~HFRS for well control purposes, which agreement was amended effective February 1, 2017~~seller in the Alliance transaction in either cash or shares of our common stock pursuant to ~~reduce~~ the ~~retainer fee~~terms of an Equity Purchase Agreement (the “Equity Purchase Agreement”) dated May 16, 2022. The earn-out is not capped and ~~to extend the term~~is calculated based on certain financial metrics of the ~~agreement by one year~~Helix Alliance business for 2022 and 2023 relative to ~~March 31, 2019.~~amounts as set forth in the Equity Purchase Agreement. As of September 30, 2023, the estimated fair value of contingent earn-out consideration increased to $74.1 million and is reported in “Accrued liabilities” in the accompanying condensed consolidated balance sheet (Note 4). This increase reflects the improvements in Helix Alliance’s financial results to date as compared to the projections made at the time of the Alliance acquisition. The ~~Production Facilities segment also includes our ownership interest~~earn-out is to be paid in ~~Independence Hub, LLC (“Independence Hub”)~~the first half of 2024 and ~~previously included our former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) that we sold in February 2016 (Note 5).~~the final amount could change based on the ultimate financial performance of Helix Alliance.

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The following table summarizes the final purchase consideration and the final purchase price allocation to estimated fair values of the identifiable assets acquired and liabilities assumed as of the acquisition date (in thousands):


	July 1, 2022
Cash consideration	$	118,961
Contingent consideration		26,700
Total fair value of consideration transferred	$	145,661

Assets acquired:
Cash and cash equivalents	$	6,336
Accounts receivable		43,378
Other current assets		6,077
Property and equipment		117,321
Operating lease right-of-use assets		1,205
Intangible assets		1,500
Other assets		2,133
Total assets acquired		177,950
Liabilities assumed:
Accounts payable		20,480
Accrued liabilities		3,073
Operating lease liabilities		1,205
Deferred tax liabilities		7,531
Total liabilities assumed		32,289
Net assets acquired	$	145,661

The pro forma summary below presents the results of operations as if the Alliance acquisition had occurred on January 1, 2022 and includes transaction accounting adjustments such as incremental depreciation and amortization expense from acquired tangible and intangible assets, elimination of interest expense on Alliance’s long-term debt that was paid off in conjunction with the acquisition, and tax-related effects. The pro forma summary uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any cost savings, operating synergies or revenue enhancements that might have been achieved from combining the operations. The unaudited pro forma summary is provided for illustrative purposes only and does not purport to represent Helix’s actual consolidated results of operations had the acquisition been completed as of the date presented, nor should it be considered indicative of Helix’s future consolidated results of operations.

The following table summarizes the pro forma results of Helix and Alliance (in thousands):


	Nine Months Ended
	September 30,
	2022
Revenues	$	665,021
Net loss		(82,282)

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Note 34 — Details of Certain Accounts

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

September 30,
2017 December 31,
2016

Note receivable ⁽¹⁾
$ —
$ 10,000
Prepaid 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.~~


	September 30,		December 31,
	2023		2022
Prepaids	$	32,897	$	26,609
Contract assets (Note 9)		4,901		6,295
Deferred costs (Note 9)		29,600		13,969
Other		11,186		11,826
Total other current assets	$	78,584	$	58,699

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


	September 30,		December 31,
	2023		2022
Prepaid charter ⁽¹⁾	$	12,544	$	12,544
Deferred costs (Note 9)		1,672		6,432
Other receivable ⁽²⁾		26,653		24,827
Intangible assets with finite lives, net		4,533		4,465
Other		2,075		2,239
Total other assets, net	$	47,477	$	50,507

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 with one~~Represents prepayments to the owner of ~~our customers~~the Siem Helix1 and 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~~the vessels at the end 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 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.their respective charter term.


(2)	~~Primarily reflects deferred mobilization costs~~Represents agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be ~~amortized after 12 months~~performed by us on Droshky oil and gas properties we acquired 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. Marathon Oil in 2019.

Accrued liabilities consist of the following (in thousands):


	September 30,		December 31,
	2023		2022
Accrued payroll and related benefits	$	59,273	$	41,339
Accrued interest		2,001		6,306
Income tax payable		386		479
Deferred revenue (Note 9)		18,635		9,961
Contingent consideration (Note 17)		74,073		—
Other ⁽¹⁾		23,750		15,489
Total accrued liabilities	$	178,118	$	73,574

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

(1)	Amount as of September 30, 2023 includes $9.0 million in credits toward future services offered by us in exchange for the purchase of P&A equipment in the third quarter 2023 (Note 2).

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


	September 30,		December 31,
	2023		2022
Asset retirement obligations (Note 13)	$	55,542	$	51,956
Contingent consideration (Note 17)		—		42,754
Other ⁽¹⁾		4,631		520
Total other non-current liabilities	$	60,173	$	95,230

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~~Amount as of September 30, 2023 includes $2.6 million in credits toward future services offered by us in exchange for the ~~sale and lease-back~~purchase of P&A equipment in ~~January 2016 of our office and warehouse property located in Aberdeen, Scotland. The deferred gain is amortized over a 15-year minimum lease term.~~the third quarter 2023 (Note 2).

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Note 45 — ~~Statement~~Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. Our operating lease additions during the nine-month period ended September 30, 2023 are primarily related to the vessel charters for the Glomar Wave and the Horizon Enabler (Note 14). Our operating lease additions during the nine-month period ended September 30, 2022 are primarily related to the charter extensions for the Siem Helix1, the Siem Helix2, the Grand Canyon II, the Grand Canyon III and the Shelia Bordelon. We also sublease some of ~~Cash Flow Information~~

~~We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less.~~ our facilities under non-cancelable sublease agreements.

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

Nine Months Ended
September 30,
2017 2016

Interest paid, net of interest capitalized $ 9,002
$ 17,970
Income taxes paid $ 3,967
$ 4,674

~~Our non-cash investing activities include property and equipment capital expenditures that are incurred but not yet paid. These non-cash capital expenditures totaled $21.7 million~~


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Operating lease cost	$	18,836	$	16,088	$	53,189	$	44,348
Variable lease cost		6,058		4,488		16,223		14,035
Short-term lease cost		18,751		9,112		43,644		22,121
Sublease income		(374)		(300)		(911)		(930)
Net lease cost	$	43,271	$	29,388	$	112,145	$	79,574

Maturities of our operating lease liabilities as of September 30, ~~2017 and $10.1 million~~2023 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	66,794	$	6,737	$	73,531
One to two years		59,599		4,184		63,783
Two to three years		37,944		1,078		39,022
Three to four years		30,569		968		31,537
Four to five years		7,590		968		8,558
Over five years		—		2,086		2,086
Total lease payments	$	202,496	$	16,021	$	218,517
Less: imputed interest		(25,896)		(1,975)		(27,871)
Total operating lease liabilities	$	176,600	$	14,046	$	190,646

Current operating lease liabilities	$	55,049	$	6,142	$	61,191
Non-current operating lease liabilities		121,551		7,904		129,455
Total operating lease liabilities	$	176,600	$	14,046	$	190,646

Maturities of our operating lease liabilities as of December 31, ~~2016.~~2022 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	58,063	$	6,603	$	64,666
One to two years		55,515		5,697		61,212
Two to three years		43,400		2,797		46,197
Three to four years		35,200		959		36,159
Four to five years		26,244		959		27,203
Over five years		3,041		2,783		5,824
Total lease payments	$	221,463	$	19,798	$	241,261
Less: imputed interest		(32,986)		(2,675)		(35,661)
Total operating lease liabilities	$	188,477	$	17,123	$	205,600

Current operating lease liabilities	$	45,131	$	5,783	$	50,914
Non-current operating lease liabilities		143,346		11,340		154,686
Total operating lease liabilities	$	188,477	$	17,123	$	205,600

~~Note 5 — Equity Investments~~

We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. We previously had a 50% ownership interest in Deepwater Gateway, which we sold in February 2016 to a subsidiary of Genesis Energy, L.P., the other 50% owner, for $25 million with no resulting gain or loss. We also received a cash distribution of $1.2 million from Deepwater Gateway in February 2016. These equity investments are included in our Production Facilities segment.

Independence Hub owns the “Independence Hub” platform located in Mississippi Canyon Block 920 in the U.S. Gulf of Mexico in a water depth of 8,000 feet. Our share of the losses reported by Independence Hub exceeded the carrying amount of our investment by $8.8 million as of September 30, 2017 and $10.2 million at December 31, 2016 reflecting our share of Independence Hub’s obligations (primarily its estimated asset retirement obligations to decommission the platform), net of remaining working capital. This liability is reflected in “Other non-current liabilities” in the accompanying condensed consolidated balance sheets.

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


	September 30,		December 31,
	2023		2022
Weighted average remaining lease term	3.3	years	4.0	years
Weighted average discount rate	8.17	%	7.84	%

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

Note 6 —Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of September 30, ~~2017~~2023 are as follows (in thousands):


	2026		MARAD
	Notes		Debt		Total
Less than one year	$	—	$	8,749	$	8,749
One to two years		—		9,186		9,186
Two to three years		200,000		9,644		209,644
Three to four years		—		5,001		5,001
Gross debt		200,000		32,580		232,580
Unamortized debt issuance costs ⁽¹⁾		(3,616)		(1,707)		(5,323)
Total debt		196,384		30,873		227,257
Less current maturities		—		(8,749)		(8,749)
Long-term debt	$	196,384	$	22,124	$	218,508

Term
Loan ⁽¹⁾

2022
Notes

2032
Notes ⁽²⁾

MARAD
Debt

Nordea
Q5000
Loan
Total

Less than one year $ 6,250
$ —
$ 60,115
$ 6,532
$ 35,714
$ 108,611
One to two years 11,250
—
—
6,858
35,714
53,822
Two to three years 81,250
—
—
7,200
98,215
186,665
Three to four years —
—
—
7,560
—
7,560
Four to five years —
125,000
—
7,937
—
132,937
Over five years —
—
—
40,913
—
40,913
Total debt 98,750
125,000
60,115
77,000
169,643
530,508
Current maturities (6,250 ) —
(60,115 ) (6,532 ) (35,714 ) (108,611 )
Long-term debt, less current 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 )
Long-term debt $ 90,685
$ 108,018
$ (1,144 ) $ 65,833
$ 131,953
$ 395,345


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


~~(2)~~	~~The holders of our remaining Convertible Senior Notes due 2032 may require us to repurchase the notes in March 2018. Accordingly, these notes are classified as current liabilities.~~


~~(3)~~	Our Convertible Senior Notes due 2022 will increase to their face amount through accretion of non-cash interest charges through May 2022. Our Convertible Senior Notes due 2032 will increase to their face amount through accretion of non-cash interest charges through March 2018.


~~(4)~~	Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.

Below is a summary of certain components of our indebtedness:

Credit Agreement

On ~~June~~September 30, ~~2017,~~2021 we entered into an ~~Amended and Restated Credit Agreement (the “Credit Agreement”)~~asset-based credit agreement with ~~a group of lenders led by~~ Bank of America, N.A. (“Bank of America”), Wells Fargo Bank, N.A. and Zions Bancorporation and subsequently we entered into amendments to the credit agreement on July 1, 2022 and June 23, 2023 (collectively, the “Amended ABL Facility”). The ~~amended and restated credit facility is comprised of~~Amended ABL Facility provides for a ~~$100~~$120 million ~~term loan (the “Term Loan”) and a~~asset-based revolving credit facility, ~~(the “Revolving Credit Facility”)~~which matures on September 30, 2026, with a springing maturity 91 days prior to the maturity of any outstanding indebtedness with a principal amount in excess of $50 million. The Amended ABL Facility also permits us to request an increase of the facility by up to ~~$150~~$30 million, ~~(the “Revolving Loans”).~~subject to certain conditions.

Commitments under the Amended ABL Facility are comprised of separate U.S. and U.K. revolving credit facility commitments of $85 million and $35 million, respectively. The ~~Revolving Credit~~Amended ABL Facility ~~permits~~provides funding based on a borrowing base calculation that includes eligible U.S. and U.K. customer accounts receivable and cash, and provides for a $20 million sub-limit for the ~~Company to obtain~~issuance of letters of ~~credit up to a sublimit~~credit. As 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 up to $100 million with respect to an increase in the Revolving Credit Facility, additional term loans, or a combination thereof. The $100 million proceeds from the Term Loan as well as cash on hand were used to repay the approximately $180 million term loan then outstanding under the credit facility prior to its June 2017 amendment and restatement. At September 30, ~~2017,~~2023, we had no borrowings under the ~~Revolving Credit~~Amended ABL Facility, and our available borrowing capacity under that facility, based on the ~~applicable leverage ratio covenant,~~borrowing base, totaled ~~$69.9~~$110.2 million, net of ~~$4.0~~$9.8 million of letters of credit issued under that facility.

We and certain of our U.S. and U.K. subsidiaries are the current borrowers under the Amended ABL Facility, whose obligations under the Amended ABL Facility are guaranteed by those borrowers and certain other U.S. and U.K. subsidiaries, excluding Cal Dive I – Title XI, Inc. (“CDI Title XI”), Helix Offshore Services Limited and certain other enumerated subsidiaries. Other subsidiaries may be added as guarantors of the facility in the future. The Amended ABL Facility is secured by all accounts receivable and designated deposit accounts of the U.S. borrowers and guarantors, and by substantially all of the assets of the U.K. borrowers and guarantors.

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~~The Term Loan and~~

U.S. borrowings under the ~~Revolving Loans (together, the “Loans”), at our election,~~Amended ABL Facility bear ~~interest either in relation to Bank of America’s base rate or to a LIBOR rate. The Term Loan or portions thereof bearing~~ interest at the ~~base~~Term SOFR (also known as CME Term SOFR as administered by CME Group, Inc.) rate will bear interest at a per annum rate equal to the base rate plus 3.25%. The Term Loan or portions thereof bearing interest at a LIBOR rate will bear interest per annum at the LIBOR rate selected by us plus a margin of ~~4.25%. The Revolving Loans~~1.50% to 2.00% or ~~portions thereof bearing interest at the base rate will bear interest~~ at a ~~per annum rate equal to the~~ base rate plus a margin ~~ranging from 1.75%~~of 0.50% to ~~3.25%~~1.00%. ~~The Revolving Loans or portions thereof bearing~~U.K. borrowings under the Amended ABL Facility denominated in U.S. dollars bear interest at ~~a LIBOR~~ the Term SOFRrate ~~will~~ with SOFR adjustment of 0.10% and U.K. borrowings denominated in the British pound bear interest ~~per annum~~ at the ~~LIBOR~~SONIA daily rate, ~~selected by us~~each plus a margin ~~ranging from 2.75%~~of 1.50% to ~~4.25%~~2.00%. A letter of credit fee is payable by us equal to its applicable margin for LIBOR rate Loans times the daily amount available to be drawn under the applicable letter of credit. Margins on the Revolving Loans will vary in relation to the consolidated total leverage ratio provided for in the Credit Agreement. We also pay a ~~fixed~~ commitment fee of 0.375% to 0.50% per annum on the unused portion of ~~our Revolving Credit Facility.~~

the facility.

The ~~Term Loan principal is required to be repaid in quarterly installments of 5% in the first loan year,~~ ~~10%~~ ~~in the second loan year and~~ ~~15%~~ in the third loan year, 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 outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amounts outstanding under the Revolving CreditAmended ABL Facility ~~without premium or penalty, and may reborrow any amounts prepaid up to the amount of the Revolving Credit Facility. The Loans mature on June 30, 2020.~~

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 includeincludes certain ~~restrictions~~limitations on our ~~and our subsidiaries’~~ ability to incur additional indebtedness, grant liens ~~incur indebtedness, make investments, merge or consolidate, sell or transfer~~on assets, pay dividends and make ~~capital expenditures. In addition, the Credit Agreement obligates~~distributions on equity interests, dispose of assets, make investments, repay certain indebtedness, engage in mergers, and other matters, in each case subject to certain exceptions. The Amended ABL Facility contains customary default provisions which, if triggered, could result in acceleration of all amounts then outstanding. The Amended ABL Facility requires us to ~~meet minimum financial ratio requirements of EBITDA to interest charges (“Consolidated Interest Coverage Ratio”)~~satisfy and ~~funded debt to EBITDA (“Consolidated Total Leverage Ratio”), and provided that if there are no Loans outstanding, the funded debt ratio requirement permits us to offset~~maintain 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 thefixed charge coverage ratio of ~~our total secured indebtedness~~not less than 1.0 to ~~EBITDA (“Consolidated Secured Leverage Ratio”) does not exceed~~1.0 if availability is less than the ~~maximum permitted ratio.~~greater of 10% of the borrowing base or $12 million. The ~~Credit Agreement~~Amended ABL Facility also ~~obligates~~requires us to maintain ~~certain cash levels depending on~~a pro forma minimum excess availability of $30 million for the ~~type~~91 days prior to the maturity of ~~indebtedness outstanding. These financial covenant requirements are detailed as follows:~~


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



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

~~September 30, 2017 and~~ each ~~fiscal quarter 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~~

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~~(c)~~	~~The maximum permitted Consolidated Secured Leverage Ratio:~~



~~Four Fiscal Quarters Ending~~	~~Maximum Consolidated~~ ~~Secured Leverage Ratio~~

~~September 30, 2017 through and including June 30, 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 ~~foreign subsidiaries~~outstanding convertible senior notes and for any portion of the Alliance earn-out payment to be made in cash.

The Amended ABL Facility also (i) limits the amount of permitted debt for the deferred purchase price of property not to exceed $50 million, and (ii) provides for potential pricing adjustments based on specific metrics and performance targets determined by us and Bank of America, as ~~subsidiaries which are not generally subject~~agent with respect to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”), provided that we meet certain liquidity requirements. The debt and EBITDA of Unrestricted Subsidiaries are not included in the calculations of our financial covenants, except for the debt and EBITDA of Helix Q5000 Holdings, S.a.r.l., a wholly owned subsidiary incorporated in Luxembourg (“Q5000 Holdings”). Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, a wholly owned Scottish subsidiary, and our obligations under the Credit Agreement and of such guarantors under their guarantee are secured by most of our assets of the parent, our domestic subsidiaries (other than Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, as well as pledges of up to two-thirds of the shares of certain foreign subsidiaries.

~~In June 2017, we recognized a $0.4 million loss to write off the unamortized debt issuance costs~~Amended ABL Facility, related to ~~the lenders exiting from the term loan then outstanding under the credit facility prior to its June 2017 amendment~~environmental, social and ~~restatement, which loss is presented as “Loss on early extinguishment of long-term debt”~~governance (“ESG”) changes implemented by us in ~~the accompanying consolidated statements of operations. In connection with decreases in lenders’ commitments under~~ our revolving credit facility, in June 2017 and February 2016 we recorded interest charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments were reduced.

business.

Convertible Senior Notes Due 2022

~~On November~~ (“2022 Notes”)

We fully paid the $35 million remaining principal amount of the 2022 Notes plus accrued interest by delivering cash upon maturity on May 1, ~~2016, we completed a public offering and sale of our~~ 2022. The effective interest rate for the 2022 Notes was 4.8%. For the nine-month period ended September 30, 2022, total interest expense related to the 2022 Notes was $0.6 million, primarily from coupon interest expense.

Convertible Senior Notes ~~due 2022 (the “2022~~Due 2023 (“2023 Notes”)

The 2023 Notes matured on September 15, 2023. Upon maturity of the 2023 Notes, we paid $29.6 million in cash to settle the conversions of $29.2 million aggregate principal amount of ~~$125 million. The net proceeds from~~ the ~~issuance~~notes, plus accrued and unpaid interest. We recorded the conversion value in excess of such principal amount converted to “Common stock” in the accompanying condensed consolidated balance sheet. Notes representing the remaining $0.8 million aggregate principal amount of the ~~2022~~2023 Notes were ~~$121.7~~redeemed at par, plus accrued and unpaid interest.

The 2023 Notes had a coupon interest rate of 4.125% per annum and an effective interest rate of 4.8%. For the three- and nine-month periods ended September 30, 2023, total interest expense related to the 2023 Notes was $0.3 million ~~after deducting~~and $1.0 million, respectively, primarily from coupon interest expense. For the ~~underwriter’s discounts~~three- and ~~commissions~~nine-month periods ended September 30, 2022, total interest expense related to the 2023 Notes was $0.4 million and ~~offering expenses. We used net proceeds~~$1.1 million, respectively, primarily 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~~coupon interest expense.

Convertible Senior Notes Due ~~2032” below) in separate, privately negotiated transactions.~~

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2026 (“2026 Notes”)

The ~~2022~~2026 Notes bear interest at a coupon interest rate of ~~4.25%~~6.75% per annum ~~and are~~ payable semi-annually in arrears on ~~November 1~~February 15 and ~~May 1~~August 15 of each year, beginning ~~on May 1, 2017.~~February 15, 2021 until maturity. The ~~2022~~2026 Notes mature on ~~May 1, 2022~~February 15, 2026 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~~repurchased by us. The 2026 Notes are convertible by ~~the~~their holders ~~into shares of our common stock~~at any time beginning November 17, 2025 at an initial conversion rate of ~~71.9748~~143.3795 shares of our common stock per $1,000 principal amount, ~~(which~~which currently represents 28,675,900 potentially convertible shares at an initial conversion price of approximately ~~$13.89~~$6.97 per share of common ~~stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2022 Notes. We~~stock. Upon conversion, we have the right ~~and the intention~~ to ~~settle~~satisfy our conversion obligation by delivering cash, shares of our common stock or any ~~such future conversions in cash.~~combination thereof.

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Prior to November ~~1, 2019,~~17, 2025, holders of the ~~2022~~2026 Notes may convert their notes if the closing price of our common stock exceeds 130% of the conversion price for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter (share price condition) or if the trading price of the 2026 Notes is equal to or less than 97% of the conversion value of the notes during the five consecutive business days immediately after any ten consecutive trading day period (trading price condition). Holders of the 2026 Notes may also convert their notes if we make certain distributions on shares of our common stock or engage in certain corporate transactions, in which case the holders may be entitled to an increase in the conversion rate, depending on the price of our common shares and the time remaining to maturity, of up to 64.5207 shares of our common stock per $1,000 principal amount.

On September 29, 2023, we announced that the 2026 Notes are convertible at the option of the holders from October 1, 2023 through December 31, 2023 as a result of the closing price of our common stock exceeding 130% of the conversion price for at least 20 days of the last 30 consecutive trading days in the quarter ended September 30, 2023. Should the closing share price conditions continue to be met in a future quarter for the 2026 Notes, the 2026 Notes will be convertible at their holders’ option during the immediately following quarter.

Prior to August 15, 2023, the 2026 Notes were not redeemable. ~~On or after November 1, 2019,~~Beginning August 15, 2023, we may, at our option, redeem all or any portion of the ~~2022~~2026 Notes if the price of our common stock has been at ~~our option, subject to certain conditions,~~least 130% of the conversion price for at least 20 trading days during the 30 consecutive trading day period preceding the date we provide a notice of redemption and the trading day immediately preceding such date (redemption price condition). Any redemption would be payable in cash equal to 100% of the principal amount ~~to be redeemed,~~ plus accrued and unpaid interest and a “make-whole premium” ~~with a value equal to~~calculated as the present value of ~~the~~all remaining scheduled interest ~~payments~~payments. As of September 29, 2023, the ~~2022~~2026 Notes were redeemable based on the redemption price condition being met. Our ability to redeem the 2026 Notes in the future will be ~~redeemed through May 1, 2022.~~subject to meeting the redemption price condition. Holders of the ~~2022~~2026 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2026 Notes may also require us to repurchase the notes following a “fundamental change,” aswhich includes a change of control or a termination of trading of our common stock (as defined in the ~~2022 Notes documentation.~~

~~The Indenture~~indenture governing the ~~2022~~2026 Notes).

The indenture governing the 2026 Notes contains customary terms and covenants, including that upon certain events of default, ~~occurring and continuing, either the trustee under the Indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2022 Notes may declare~~ the entire principal amount of ~~all~~and any accrued interest on the notes ~~and the interest accrued on such notes, if any, to~~may be declared 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~~2026 Notes together with any accrued ~~and unpaid~~ interest ~~thereon~~ will ~~automatically be and~~ become immediately due and payable.

In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million as required under existing accounting rules. To arrive at this discount amount, we estimated the fair value of the liability component of the 2022 Notes as of October 26, 2016 using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of pricing and an expected life of 5.5 years.

The effective interest rate for the ~~2022~~2026 Notes is ~~7.3% after considering the effect~~7.6%. For each 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 of tax, related to the carrying amount of the equity component of the 2022 Notes. The remaining unamortized amount of the debt discount of the 2022 Notes was $14.6 million at September 30, 2017 and $16.5 million at December 31, 2016.

~~Convertible Senior Notes Due 2032~~

In March 2012, we completed a public offering and sale of our Convertible Senior Notes due 2032 (the “2032 Notes”) in the aggregate principal amount of $200 million, $60 million of which are currently outstanding. The 2032 Notes bear interest at a rate of 3.25% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012. The 2032 Notes mature on March 15, 2032 unless earlier converted, redeemed or repurchased. The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes. We have the right and the intention to settle any such future conversions in cash.

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Prior to March 20, 2018, the 2032 Notes are not redeemable. On or after March 20, 2018, we, at our option, may redeem some or all of the 2032 Notes in cash, at any time upon at least 30 days’ notice, at a price equal to 100% of the principal amount plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date. In addition, the holders of the 2032 Notes may require us to purchase in cash some or all of their 2032 Notes at a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a Fundamental Change (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~~2023 and 2022, total interest expense related to the ~~repurchase of the 2032~~2026 Notes ~~of $0.2~~was $3.7 million and ~~$0.5~~$11.1 million, respectively, ~~which are presented as “Gain on early extinguishment~~with coupon interest expense of ~~long-term debt” in~~$3.4 million and $10.1 million, respectively, and the ~~accompanying consolidated statements~~amortization of ~~operations.~~

debt issuance costs of $0.3 million and $1.0 million, respectively.

2026 Capped Calls

In connection with the ~~issuance~~2026 Notes offering, we entered into capped call transactions (the “2026 Capped Calls”) with three separate option counterparties. The 2026 Capped Calls are for an aggregate of 28,675,900 shares of our common stock, which corresponds to the shares into which the 2026 Notes are initially convertible. The capped call shares are subject to certain anti-dilution adjustments. Each capped call option has an initial strike price of approximately $6.97 per share, which corresponds to the initial conversion price of the ~~2032~~2026 Notes, weand an initial cap price of approximately $8.42 per share. The strike and cap prices are subject to certain adjustments. The 2026 Capped Calls are intended to offset some or all of the potential dilution to Helix common shares caused by any conversion of the 2026 Notes up to the cap price. The 2026 Capped Calls can be settled in either net shares or cash at our option in components commencing December 15, 2025 and ending February 12, 2026, which could be extended under certain circumstances.

The 2026 Capped Calls are subject to either adjustment or termination upon the occurrence of specified extraordinary events affecting Helix, including a merger, tender offer, nationalization, insolvency or delisting. In addition, certain events may result in a termination of the 2026 Capped Calls, including changes in law, insolvency filings and hedging disruptions. The 2026 Capped Calls are recorded ~~a debt discount~~at their aggregate cost of ~~$35.4~~$10.6 million as ~~required under existing accounting rules. To arrive at this discount amount we estimated~~a reduction to common stock in the ~~fair value~~shareholders’ equity section of our condensed consolidated balance sheets.

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MARAD Debt

In 2005, Helix’s subsidiary CDI – Title XI issued its U.S. Government Guaranteed Ship Financing Bonds, Q4000 Series, to refinance the construction financing originally granted in 2002 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). The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception. We recorded $22.5 million, net of tax, related to the carrying amount of the equity component of the 2032 Notes. The remaining unamortized amount of the debt discount of the 2032 Notes was $1.1 million at September 30, 2017 and $2.6 million at December 31, 2016.

~~MARAD Debt~~

~~This U.S. government guaranteed financing~~Q4000 vessel (the “MARAD Debt”),. The MARAD Debt is guaranteed by the U.S. government pursuant to Title XI of the Merchant Marine Act of 1936, administered by the Maritime Administration ~~was used~~(“MARAD”). The obligation of CDI Title XI to ~~finance~~reimburse MARAD in the ~~construction of~~event CDI Title XI fails to repay the~~Q4000. The~~ MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. In addition, we have agreed to bareboat charter the Q4000 from CDI Title XI for so long as the MARAD Debt remains outstanding. The MARAD Debt is payable in equal semi-annual installments, ~~beginning in August 2002 and~~ matures in February 2027 and initially bore 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%~~4.93%. 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. Q5000 Holdings may elect to prepay amounts outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Quarterly principal installments are subject to adjustment for any prepayments 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). The total notional amount of the swaps (initially $187.5 million) decreases in proportionagreements relating to the ~~reduction in~~bonds and the ~~principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.~~

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~~The Nordea Credit Agreement and related loan documents include~~ terms and conditions of our obligations to MARAD in respect of the MARAD Debt are typical for U.S. government-guaranteed ship financing transactions, including ~~covenants and prepayment requirements, that we consider~~ customary ~~for this type of transaction. The covenants include~~ restrictions on ~~Q5000 Holdings’s ability~~incurring additional liens on the Q4000 and trading restrictions with respect 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.~~

vessel as well as working capital requirements.

Other

In accordance with ~~our Credit Agreement,~~ the ~~2022~~Amended ABL Facility, the 2026 Notes ~~the 2032 Notes,~~and the MARAD Debt, ~~agreements and the Nordea Credit Agreement,~~ we are required to comply with certain covenants, including ~~certain financial ratios such as~~minimum liquidity and a ~~consolidated interest~~springing fixed charge coverage ratio (applicable under certain conditions that are currently not applicable) with respect to the Amended ABL Facility and ~~various leverage ratios, as well as~~ the maintenance of ~~minimum cash balance,~~ net worth, working capital and debt-to-equity ~~requirements.~~requirements with respect to the MARAD Debt. As of September 30, ~~2017,~~2023, we were in compliance with these covenants.

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Interest expense	$	4,830	$	4,923	$	14,556	$	15,264
Interest income		(678)		(279)		(1,989)		(647)
Net interest expense	$	4,152	$	4,644	$	12,567	$	14,617

Note 7 — Income Taxes

We operate in multiple jurisdictions with complex tax laws subject to interpretation and judgment. We believe that our ~~recorded deferred tax assets and liabilities are reasonable. However, tax~~application of such laws and ~~regulations~~the tax impact thereof are ~~subject to interpretation~~reasonable and fairly presented in our condensed consolidated financial statements.

For the ~~outcomes~~three- and nine-month periods ended September 30, 2023, we recognized income tax expense of $8.3 million and $9.6 million, respectively, resulting in effective tax ~~disputes are inherently uncertain,~~rates of 34.9% and ~~therefore our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.~~

35.5%, respectively. The effective tax rates for these periods were higher than the U.S. statutory rate primarily due to certain non-deductible expenses and non-creditable foreign income taxes. For the three- and nine-month periods ended September 30, 2022, we recognized income tax expense of $6.5 million and $10.1 million, respectively, resulting in effective tax rates of (53.0)% and (12.5)%, respectively. For the three- and nine-month periods ended September 30, 2022, our aggregate tax expense was greater than the aggregate tax benefit of our losses, resulting in negative effective tax rates.

Note 8 — Share Repurchase Programs

During the nine-month period ended September 30, 2023, we repurchased a total of 1,584,045 shares of our common stock for approximately $12.0 million or an average of $7.57 per share pursuant to a share repurchase program (the “2023 Repurchase Program”) authorized by our Board of Directors (our “Board”) in February 2023. Under the 2023 Repurchase Program, we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. Concurrent with the authorization of the 2023 Repurchase Program, our Board revoked the prior authorization to repurchase shares of our common stock in an amount equal to any equity issued to our employees, officers and directors under our share-based compensation plans, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our Employee Stock Purchase Plan (Note 11).

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The 2023 Repurchase Program has no set expiration date. Repurchases under the 2023 Repurchase Program have been made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, but may also be made through privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management based on an evaluation of market conditions, stock price, liquidity and other factors. The 2023 Repurchase Program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. The purchase of shares by us under the 2023 Repurchase Program is at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled.

Note 9 — Revenue from Contracts with Customers

Disaggregation of Revenue

Our revenues are primarily derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of 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. 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. The following table provides information about disaggregated revenue by contract duration (in thousands):


	Well				Shallow Water		Production		Intercompany		Total
	Intervention		Robotics		Abandonment		Facilities		Eliminations		Revenue
Three months ended September 30, 2023
Short-term	$	139,743	$	26,995	$	73,037	$	—	$	—	$	239,775
Long-term		85,624		48,651		14,235		24,469		(17,084)		155,895
Total	$	225,367	$	75,646	$	87,272	$	24,469	$	(17,084)	$	395,670

Three months ended September 30, 2022
Short-term	$	111,378	$	26,695	$	67,401	$	—	$	(135)	$	205,339
Long-term		32,547		29,487		—		18,448		(13,274)		67,208
Total	$	143,925	$	56,182	$	67,401	$	18,448	$	(13,409)	$	272,547

Nine months ended September 30, 2023
Short-term	$	293,131	$	100,269	$	196,534	$	—	$	(26)	$	589,908
Long-term		228,895		94,649		16,425		68,502		(43,808)		364,663
Total	$	522,026	$	194,918	$	212,959	$	68,502	$	(43,834)	$	954,571

Nine months ended September 30, 2022
Short-term	$	288,772	$	73,684	$	67,401	$	—	$	(770)	$	429,087
Long-term		67,811		69,699		—		54,420		(35,733)		156,197
Total	$	356,583	$	143,383	$	67,401	$	54,420	$	(36,503)	$	585,284

Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” in the accompanying condensed consolidated balance sheets (Note 4). Contract assets were $4.9 million as of September 30, 2023 and $6.3 million as of December 31, 2022. We had no credit losses on our contract assets for the three- and nine-month periods ended September 30, ~~2017 were (204.9)%~~2023 and ~~5.2%, respectively. The effective tax rates~~2022.

Table of Contents

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” in the accompanying condensed consolidated balance sheets (Note 4). Contract liabilities totaled $18.6 million as of September 30, 2023 and $10.0 million as of December 31, 2022. Revenue recognized for the three- and nine-month periods ended September 30, ~~2016~~2023 included $15.2 million and $8.4 million, respectively, that were ~~24.1% and 26.7%, respectively. The variance was primarily attributable to~~included in the ~~earnings mix between our higher and lower tax rate jurisdictions and a change in tax position related to our foreign taxes.~~

~~We continued recording income taxes using a year-to-date effective tax rate method~~contract liability balance at the beginning of each period. Revenue recognized for the three- and nine-month periods ended September 30, ~~2017. The use~~2022 included $2.7 million and and $7.0 million, respectively, that were included in the contract liability balance at the beginning of ~~this method~~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, 2023, $790.0 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $241.7 million, $467.1 million and $81.2 million in 2023, 2024 and 2025, respectively. 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 ~~our expectations~~the estimated start date and duration of each contract according to the information known at September 30, ~~2017 that~~2023.

For the three-and nine-month periods ended September 30, 2023 and 2022, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a ~~small change in our estimated ordinary income could result in~~contract with a ~~large change in~~customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the ~~estimated annual effective tax rate. We will re-evaluate our use~~beginning of ~~this method each quarter until such time as~~ a ~~return to~~contract and costs incurred for demobilization at the ~~annualized effective tax rate method is deemed appropriate.~~

~~Table~~end of ~~Contents~~

~~Income taxes~~a contract. Mobilization costs are ~~provided~~deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the ~~U.S. statutory rate~~pattern of ~~35% and~~the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the ~~local statutory rate~~end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying condensed consolidated balance sheets (Note 4). Our deferred contract costs totaled $31.3 million as of September 30, 2023 and $20.4 million as of December 31, 2022. For the three- and nine-month periods ended September 30, 2023, we recorded $13.7 million and $32.8 million, respectively, related to amortization of these deferred contract costs. For the three- and nine-month periods ended September 30, 2022, we recorded $8.5 million and $19.7 million, respectively, related to amortization of these deferred contract costs. There were no associated impairment losses for ~~each foreign jurisdiction adjusted for items that are allowed as deductions for federal~~any period presented.

For additional information regarding revenue recognition, see Notes 2 and ~~foreign income tax reporting purposes, but not for book purposes. The primary differences between the U.S. statutory rate and~~11 to our ~~effective rate are as follows:~~

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.

2022 Form 10-K.

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) (“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 )


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

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~~Note 9~~ — Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. ~~Holders~~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~~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 ~~undistributed earnings~~two-class method, net income for each period ~~are~~is 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~~

Table of ~~basic~~Contents

Basic EPS ~~amounts on the face of the accompanying condensed consolidated statements of operations~~ is computed by dividing net income allocated to common shareholders or net loss by the weighted average shares of our common stock outstanding. ~~The calculation of diluted~~Diluted EPS is computed in a similar manner after considering the potential dilutive effect of share-based awards and convertible senior notes and taking the more dilutive of the two-class method and the treasury stock method or if-converted method, as applicable. The dilutive effect of share-based awards is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to ~~basic EPS, except that~~be hypothetically repurchased with the ~~denominator includes~~assumed proceeds. The dilutive effect of convertible senior notes is computed using the if-converted method, which assumes conversion of the convertible senior notes into shares of our common stock ~~equivalents and~~at the ~~income included in the numerator excludes the effects~~beginning of the ~~impact~~period, giving income recognition for the add-back of ~~dilutive common stock equivalents, if any.~~related interest expense (net of tax). The computations of the numerator ~~(income)~~(earnings or loss) and denominator (shares) to derive the basic and diluted EPS amounts presented on the face of the accompanying condensed consolidated statements of operations ~~for the three-month periods ended September 30, 2017 and 2016~~ are as follows (in thousands):

Three Months Ended
September 30, 2017 Three Months Ended
September 30, 2016
Income Shares Income Shares
Basic:
Net income $ 2,290
$ 11,462

Less: Undistributed earnings allocated to participating securities (27 ) (160 )
Undistributed earnings allocated to common shares $ 2,263
145,958
$ 11,302
113,680

Diluted:
Undistributed earnings allocated to common shares $ 2,263
145,958
$ 11,302
113,680
Effect of dilutive securities:
Share-based awards other than participating securities —
—
—
—
Undistributed earnings reallocated to participating securities —
—
—
—
Net income $ 2,263
145,958
$ 11,302
113,680


	Three Months Ended			Three Months Ended
	September 30, 2023			September 30, 2022
	Income		Shares	Income		Shares
Basic:
Net income (loss)	$	15,560		$	(18,763)
Less: Undistributed earnings allocated to participating securities		(27)			—
Net income (loss) available to common shareholders, basic	$	15,533	150,550	$	(18,763)	151,331

Diluted:
Net income (loss) available to common shareholders, basic	$	15,533	150,550	$	(18,763)	151,331
Effect of dilutive securities:
Share-based awards other than participating securities		—	3,072		—	—
Undistributed earnings reallocated to participating securities		1	—		—	—
Net income (loss) available to common shareholders, diluted	$	15,534	153,622	$	(18,763)	151,331


	Nine Months Ended			Nine Months Ended
	September 30, 2023			September 30, 2022
	Income		Shares	Income		Shares
Basic:
Net income (loss)	$	17,495		$	(90,493)
Less: Undistributed earnings allocated to participating securities		(30)			—
Net income (loss) available to common shareholders, basic	$	17,465	151,031	$	(90,493)	151,226

Diluted:
Net income (loss) available to common shareholders, basic	$	17,465	151,031	$	(90,493)	151,226
Effect of dilutive securities:
Share-based awards other than participating securities		—	2,905		—	—
Undistributed earnings reallocated to participating securities		1	—		—	—
Net income (loss) available to common shareholders, diluted	$	17,466	153,936	$	(90,493)	151,226

We had net losses for the three- and nine-month periods ended September 30, ~~2017 and 2016.~~2022. Accordingly, our diluted EPS calculation for these periods ~~was equivalent to our basic EPS calculation since diluted EPS~~ excluded ~~any assumed exercise or conversion~~the dilutive effect of ~~common stock equivalents. These common stock equivalents were excluded~~share-based awards 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):


	Three Months Ended	Nine Months Ended
	September 30,	September 30,
	2022	2022
Diluted shares (as reported)	151,331	151,226
Share-based awards	1,471	1,332
Total	152,802	152,558

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~~

The following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the ~~2032~~2026 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,
2017 2016 2017 2016

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


	Three Months Ended		Nine Months Ended
	September 30,		September 30,
	2023	2022	2023	2022
2022 Notes	—	—	—	803
2023 Notes	2,652	3,168	2,996	3,168
2026 Notes	28,676	28,676	28,676	28,676

We have outstanding restricted stock units (“RSUs”) (Note 11) as well as post-closing earn-out consideration related to the Alliance acquisition (Note 3) that can each be settled in either cash or shares of our common stock or a combination thereof, which are not included in the computation of diluted EPS as cash settlement is assumed.

Note 1011 — Employee Benefit Plans

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

As of September 30, ~~2017,~~2023, there were ~~2.4~~3.5 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”). During the nine-month period ended September 30, ~~2017,~~2023, the following grants of share-based awards were made under the 2005 Incentive Plan:


			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period
January 1, 2023 ⁽¹⁾	RSU	506,436	$	7.38	33% per year over three years
January 3, 2023 ⁽¹⁾	PSU	489,498	$	9.26	100% on December 31, 2025
January 1, 2023 ⁽²⁾	Restricted stock	9,210	$	7.38	100% on January 1, 2025
April 1, 2023 ⁽²⁾	Restricted stock	7,267	$	7.74	100% on January 1, 2025
July 1, 2023 ⁽²⁾	Restricted stock	7,622	$	7.38	100% on January 1, 2025

Date of Grant Shares
Grant Date
Fair Value
Per Share
Vesting Period

January 3, 2017 ⁽¹⁾
671,771
$ 8.82
33% per year over three years
January 3, 2017 ⁽²⁾
671,771
$ 12.64
100% on January 1, 2020
January 3, 2017 ⁽³⁾
9,956
$ 8.82
100% on January 1, 2019
April 3, 2017 ⁽³⁾
8,004
$ 7.77
100% on January 1, 2019
July 3, 2017 ⁽³⁾
14,018
$ 5.64
100% on January 1, 2019


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

(2)

Reflects grants of performance share units (“PSUs”) to our executive officers and select management employees. 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 and the minimum amount being zero. For the 2017 awards, vested PSUs can only be settled in shares of our common stock.


~~(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.

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~~Forfeitures are recognized as they occur. No restricted stock awards have been granted to ~~account for forfeitures when they occur upon the adoption of the new guidance for employee share-based payment accounting (Note 1).~~our executive officers or other employees since 2020. For the three- and nine-month periods ended September 30, ~~2017, $1.7~~2023, $0.3 million and ~~$5.4~~$1.0 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~~2022, $0.5 million and ~~$4.3~~$1.9 million, respectively, were recognized as share-based compensation related to restricted stock.

Our performance share units (“PSUs”) granted prior to 2021 were settled solely in shares of our common stock and were accounted for as equity awards. Our PSUs granted beginning in January 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee of our Board and have been accounted for as equity awards. Those PSUs consist of two components: (i) 50% based on the performance of our common stock against peer group companies, which component contains a service and a market condition, and (ii) 50% based on cumulative total Free Cash Flow, which component contains a service and a performance condition. Free Cash Flow is calculated as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Our PSUs cliff vest at the end of a three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

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~~The estimated fair value of~~

For PSUs ~~is determined using~~with a ~~Monte Carlo simulation model. Compensation cost for PSUs~~service and a market condition that are accounted for as equity awards, compensation cost is measured based on the ~~estimated~~ grant date estimated fair value determined using a Monte Carlo simulation model and subsequently recognized over the vesting period on a straight-line basis. For PSUs ~~that are accounted for as liability awards are measured based on the estimated fair value at the balance sheet date~~with a service 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~~a performance condition that are accounted for as equity awards, ~~whereas awards made prior~~compensation cost is initially measured based on the grant date fair value. Cumulative compensation cost is subsequently adjusted at the end of each reporting period to ~~2017 are accounted for as liability awards.~~reflect the current estimation of achieving the performance condition. For the three- and nine-month periods ended September 30, ~~2017, $4.0~~2023, $1.2 million and ~~$5.8~~$3.5 million, respectively, were recognized as share-based compensation related to PSUs. For the three- and nine-month periods ended September 30, ~~2016, $2.5~~2022, $1.5 million and ~~$5.3~~$3.6 million, respectively, were recognized as share-based compensation related to PSUs. ~~The~~In January 2023, based on the performance of our common stock price as compared to our performance peer group over a three-year period, 369,938 PSUs granted in 2020 vested at 77%, representing 285,778 shares of our common stock with a total market value of $3.6 million.

Our currently outstanding RSUs may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and have been accounted for as liability awards. Liability RSUs are measured at their estimated fair value based on the closing share price of our common stock as of each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for ~~unvested PSUs was $10.2 million at~~the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting. For the three- and nine-month periods ended September 30, ~~2017~~2023, $3.2 million and ~~$7.1~~$5.5 million, ~~at December 31, 2016.~~ respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2022, $0.7 million and $1.5 million, respectively, were recognized as compensation cost.

In 2023 and 2022, we granted fixed-value cash awards of $6.0 million and $5.5 million, respectively, to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the three- and nine-month periods ended September 30, 2023, $1.1 million and $3.5 million, respectively, were recognized as compensation cost. For the three- and nine-month periods ended September 30, 2022, $1.1 million and $3.2 million, respectively, were recognized as compensation cost.

Defined Contribution Plans

We ~~paid $0.6~~sponsor a defined contribution 401(k) retirement plan (the “401(k) Plan”) in the U.S. as well as various other defined contribution plans globally. During the three- and nine-month periods ended September 30, 2023, we made contributions to our defined contribution plans totaling $1.0 million ~~in cash~~and $3.2 million, respectively. During the three- and nine-month periods ended September 30, 2022, we made contributions to ~~settle the 2014 grant of PSUs when they vested in January 2017.~~

our defined contribution plans totaling $0.7 million and $2.2 million, respectively.

Employee Stock Purchase Plan

We have an employee stock purchase plan (the “ESPP”). ~~The ESPP has 1.5 million shares authorized for issuance,~~As of ~~which 0.6~~September 30, 2023, 1.2 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, the 401(k) Plan and ~~cash plans and our employee stock purchase plan,~~the ESPP, see Note 1213 to our ~~2016~~2022 Form 10-K.

Note 1112 — Business Segment Information

We have ~~three~~four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. Our U.S., U.K. and Brazil ~~well intervention~~Well Intervention operating segments are aggregated into the Well Intervention ~~business~~ segment for financial reporting purposes. ~~Our Well Intervention~~We formed the Shallow Water Abandonment segment ~~includes our vessels and equipment used to perform well intervention services primarily~~ in the ~~U.S. Gulf of Mexico, North Sea and Brazil. Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and SILs. Our well intervention vessels include~~third quarter 2022 following 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 Robotics segment includes ROVs, trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates four chartered ROV support vessels, including the ~~Grand Canyon III~~ ~~that went into service for us in May 2017. Our Production Facilities segment includes the~~ ~~HP I~~, the HFRS and our investment in Independence Hub that is accounted for under the equity method, and previously included our former ownership interest in Deepwater Gateway that we sold in February 2016Alliance acquisition (Note 5)3). All material intercompany transactions between the segments have been eliminated. See Note 2 for more information on our business segments.

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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,
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 )


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Net revenues —
Well Intervention	$	225,367	$	143,925	$	522,026	$	356,583
Robotics		75,646		56,182		194,918		143,383
Shallow Water Abandonment		87,272		67,401		212,959		67,401
Production Facilities		24,469		18,448		68,502		54,420
Intercompany eliminations		(17,084)		(13,409)		(43,834)		(36,503)
Total	$	395,670	$	272,547	$	954,571	$	585,284

Income (loss) from operations —
Well Intervention	$	16,120	$	(1,304)	$	11,357	$	(55,610)
Robotics		20,665		11,708		43,226		22,854
Shallow Water Abandonment		27,624		16,320		54,208		16,320
Production Facilities		8,886		6,068		21,817		17,964
Segment operating income (loss)		73,295		32,792		130,608		1,528
Change in fair value of contingent consideration		(16,499)		—		(31,319)		—
Corporate, eliminations and other		(20,568)		(20,566)		(51,159)		(41,255)
Total	$	36,228	$	12,226	$	48,130	$	(39,727)

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

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

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Well Intervention	$	6,832	$	4,303	$	18,174	$	12,046
Robotics		10,252		8,971		25,634		24,322
Shallow Water Abandonment		—		135		26		135
Total	$	17,084	$	13,409	$	43,834	$	36,503

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,		December 31,
	2023		2022
Well Intervention	$	1,828,452	$	1,796,269
Robotics		190,092		192,694
Shallow Water Abandonment		247,317		206,944
Production Facilities		119,674		136,382
Corporate and other		49,217		57,049
Total	$	2,434,752	$	2,389,338

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

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Note 1213 — Asset Retirement Obligations

Our asset retirement obligations (“AROs”) relate to mature offshore oil and gas properties that we acquired with the intention to perform decommissioning work at the end of their life cycles. AROs are recorded initially at fair value and consist of estimated costs for subsea infrastructure decommissioning and P&A activities associated with our oil and gas properties. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the passage of time as accretion expense, which is a component of our depreciation and amortization expense. An ARO liability may also change based on revisions in estimated costs and/or timing to settle the obligations.

In August 2022, we acqured from MP Gulf of Mexico, LLC (“MP GOM”), a joint venture controlled by Murphy Exploration & Production Company – USA, all of MP GOM’s 62.5% interest in the Thunder Hawk Field, in exchange for the assumption of MP GOM’s abandonment obligations (initially estimated at $23.6 million). Our AROs also include P&A costs associated with our Droshky oil and gas properties (Note 4). The following table describes the changes in our AROs (in thousands):


	2023		2022
AROs at January 1,	$	51,956	$	29,658
Liability incurred during the period		—		23,601
Accretion expense		3,586		1,465
AROs at September 30,	$	55,542	$	54,724

Note 14 — 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 into

Our Well Intervention segment has long-term charter agreements with Siem Offshore AS ~~(“Siem”)~~ for ~~two newbuild monohull vessels,~~ the Siem Helix1 and ~~the~~ Siem Helix2~~. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates~~ vessels expiring in February 2025 and February 2027, respectively, with options to extend. ~~The initial term~~Our Robotics segment has vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon, the Glomar Wave and the Horizon Enabler. Our time charter agreements for the Grand Canyon II and Grand Canyon III vessels expire in December 2027 and May 2028, respectively, with options to renew the Grand Canyon III. Our time charter agreement for the Shelia Bordelon in the Gulf of Mexico expires in June 2024. In January 2023, we entered into a three-year charter agreement for the Glomar Wave in the North Sea with options to extend. In July 2023, we entered into a new agreement to extend the Horizon Enabler charter until December 2025, with further options to extend.

Contingencies and Claims

Our contingent consideration liability resulting from the Alliance acquisition is subject to risk, through the remainder of the ~~agreements with Petrobras~~contingency period, which ends on December 31, 2023, as a result of changes in our probability weighted discounted cash flow model, which is ~~for four years with Petrobras’s options to extend.~~

~~The~~ ~~Siem Helix~~1 ~~vessel was delivered to us~~based on internal forecasts, and ~~the charter term began on June 14, 2016. The vessel was accepted by Petrobras and commenced operations on April 14, 2017, at~~changes in weighted average discount rate, which time we agreed with Petrobras to commence operations at reduced day rates. Our day rates improved in the third quarter as we addressed most of the items identified in the vessel acceptance process. The ~~Siem 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. At September 30, 2017, our total investment in the topside equipment for the two vessels was $304.1 million.

~~Contingencies and Claims~~

derived from market data.

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

Litigation

We are involved in various ~~other~~ legal proceedings, some involving claims ~~for personal injury~~ under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as 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.

Table of Contents

We are currently involved in several lawsuits filed by current and former offshore employees seeking overtime compensation. These suits are brought as collective actions and are in various stages of litigation in federal district courts. We appealed one such lawsuit to the United States Supreme Court, which issued a ruling adverse to us in the first quarter 2023 that has implications for similar lawsuits in which we are involved. In a separate lawsuit, during the third quarter 2022 the United States Court of Appeals for the Fifth Circuit issued an adverse ruling that is likely to have implications for other similar lawsuits in which we are involved. We continue to vigorously defend these lawsuits, and notwithstanding that we believe we retain valid defenses, we have established a liability in each of these matters. The final outcome of these matters remains uncertain, and the ultimate liability to us could be more or less than the liability established.

Note 1315 — Statement of Cash Flow Information

We define cash and cash equivalents as cash and all highly liquid financial instruments with original maturities of three months or less. We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. The following table provides supplemental cash flow information (in thousands):

(1)	Exclusive of any income tax refunds.

Our capital additions include the acquisition of property and equipment for which payment has not been made. These non-cash capital additions were $0.8 million at September 30, 2023 and $0.3 million at December 31, 2022.

Non-cash investing and financing activities for the nine-month period ended September 30, 2023 included a portion of P&A equipment purchase financed by the seller in the form of credits towards future services offered by us which had an estimated fair value of $11.6 million at the time of purchase in the third quarter 2023 (Note 2). Non-cash investing activities for the nine-month period ended September 30, 2022 included $26.7 million in estimated fair value of contingent earn-out consideration as of July 1, 2022, the date of the Alliance acquisition (Note 3).

Note 16 — Allowance for Credit Losses

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

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


	2023		2022
Balance at January 1,	$	2,277	$	1,477
Additions ⁽¹⁾		1,020		710
Balance at September 30,	$	3,297	$	2,187

(1)	Additions in allowance for credit losses reflect credit loss reserves during the respective periods.

Note 17 — Fair Value Measurements

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

~~Level 1. Observable inputs such as quoted prices in active markets;~~

~~Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and~~

~~Table of Contents~~

~~Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.~~

~~Assets and liabilities measured at fair value are based on one or more of three valuation approaches as follows:~~


~~(a)~~	~~Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.~~


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


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

Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term ~~debt and various derivative instruments.~~debt. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments. ~~The net carrying amount~~

Table of ~~our long-term note receivable also approximates its fair value.~~ Contents

The following ~~tables provide additional information relating to other financial instruments~~table sets forth our assets and liabilities that are measured at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

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

Liabilities:
Foreign exchange contracts —
19,508
—
19,508
(c)
Interest rate swaps —
82
—
82
(c)
Total liability $ —
$ 19,216
$ —
$ 19,216

Fair Value Measurements at
December 31, 2016 Using
Level 1
Level 2 ⁽¹⁾
Level 3 Total
Valuation
Approach
Assets:
Interest rate swaps $ —
$ 451
$ —
$ 451
(c)

Liabilities:
Foreign exchange contracts —
38,170
—
38,170
(c)
Interest rate swaps —
751
—
751
(c)
Total net liability $ —
$ 38,470
$ —
$ 38,470

~~(1)~~

Unless otherwise indicated, the fair value of our Level 2 derivative instruments reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. See Note 14 for further discussion on fair value of our derivative instruments.

~~Table~~

Fair Value at September 30, 2023

Level 1

Level 2

Level 3

Total

Liabilities:

Contingent consideration

—

74,073

Contingent consideration liability related to the Alliance acquisition (Note 3) is measured at fair value using Level 3 unobservable inputs at the end of ~~Contents~~

each reporting period. The ~~carrying values~~fair value of the estimated contingent consideration is determined based on our evaluation of the probability and amount of earn-out that may be achieved based on expected future performance of Helix Alliance. The Monte Carlo simulation model is used to calculate the estimated earn-out payment, which is then discounted to present value based on the expected payment date of the contingent consideration. The changes in the fair value of contingent consideration are as follows (in thousands):


	2023
Balance at January 1,	$	42,754
Change in fair value		31,319
Balance at September 30,	$	74,073

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


	September 30, 2023				December 31, 2022
	Principal		Fair		Principal		Fair
	Amount ⁽¹⁾		Value ⁽²⁾		Amount ⁽¹⁾		Value ⁽²⁾
2023 Notes (matured September 2023)	$	—	$	—	$	30,000	$	31,149
2026 Notes (mature February 2026)		200,000		340,000		200,000		277,014
MARAD Debt (matures February 2027)		32,580		32,151		40,913		40,940
Total debt	$	232,580	$	372,151	$	270,913	$	349,103

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~~any 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~~2023 Notes, the 2026 Notes and the ~~2032 Notes~~MARAD Debt was determined using Level 1 inputs under the market approach. The fair value of the Nordea Q5000 Loan, 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.

~~Note 14 — Derivative Instruments and Hedging Activities~~

Our business is exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to hedge the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative instruments are reflected in the accompanying condensed consolidated balance sheets at fair value.

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

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

~~Interest Rate Risk~~

From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. In June 2015 we entered into various interest rate swap contracts to fix the interest rate on $187.5 million of our Nordea Q5000 Loan (Note 6). These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. Our interest rate swap contracts qualify for cash flow hedge accounting treatment. Changes in the fair value of interest rate swaps are deferred to the extent the swaps are effective. These changes are recorded as a component of Accumulated OCI until the anticipated interest is recognized as interest expense. The ineffective portion of the interest rate swaps, if any, is recognized immediately in earnings within the line titled “Net interest expense.” The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.

~~Table of Contents~~

~~Foreign Currency Exchange Rate Risk~~

Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. We enter into foreign currency exchange contracts from time to time to stabilize expected cash outflows related to our vessel charters that are denominated in foreign currencies.

~~In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 our foreign currency exposure associated with the~~ ~~Grand Canyon~~ charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). In February 2013, we entered into similar foreign currency exchange contracts to hedge our foreign currency exposure associated with the ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. In December 2015, we de-designated the foreign currency exchange contracts associated with the charter payment obligations for the ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ ~~vessels that no longer qualified for cash flow hedge accounting treatment and we re-designated the hedging relationship between a portion of these contracts and our forecasted~~ ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring. Unrealized losses associated with the effective portion of our foreign currency exchange contracts that qualify for hedge accounting treatment are included in our Accumulated OCI (net of tax). Reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations are changes in unrealized losses associated with the foreign currency exchange contracts that are no longer designated as cash flow hedges. Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying condensed consolidated statements of operations. There were no gains or losses associated with hedge ineffectiveness for the three- and nine-month periods ended September 30, 2017 and the three-month period ended September 30, 2016. For the nine-month period ended September 30, 2016, we recorded unrealized gains of $0.1 million related to our hedge ineffectiveness.

~~Quantitative Disclosures Relating to Derivative Instruments~~

~~The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands):~~

September 30, 2017 December 31, 2016

Balance Sheet
Location

Fair
Value

Balance Sheet
Location

Fair
Value
Asset Derivative Instruments:
Interest rate 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

~~Table of Contents~~

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

September 30, 2017 December 31, 2016

Balance Sheet
Location

Fair
Value

Balance Sheet
Location

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

Gain (Loss) Recognized in OCI on
Derivative Instruments, Net of Tax
(Effective Portion)
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

Foreign exchange contracts $ 3,620
$ 4,249
$ 9,341
$ 10,745
Interest rate swaps 68
643
366
(880 )
$ 3,688
$ 4,892
$ 9,707
$ 9,865

Location of Loss Reclassified from
Accumulated OCI into Earnings

Loss Reclassified from
Accumulated OCI into Earnings
(Effective Portion)
Three Months Ended
September 30, Nine Months Ended
September 30,
2017 2016 2017 2016

Foreign exchange 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 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

~~Table of Contents~~

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

FORWARD-LOOKING STATEMENTS AND ASSUMPTIONS

This Quarterly Report on Form 10-Q contains or incorporates by reference various statements that contain forward-looking information regarding Helix ~~Energy Solutions Group, Inc.~~ and represent our current expectations ~~and beliefs concerning~~or forecasts of future events. This forward-looking information is intended to be covered by the safe harbor for “forward-looking statements” provided by the Private Securities Litigation Reform Act of 1995 as set forth in Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange ~~Act.~~Act of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated ~~herein~~ by reference herein that are predictive in nature, that depend upon or refer to future events or conditions, or that use terms and phrases such as “achieve,” “anticipate,” “believe,” “estimate,” “budget,” “expect,” “forecast,” “plan,” “project,” “propose,” “strategy,” “predict,” “envision,” “hope,” “intend,” “will,” “continue,” “may,” “potential,” “should,” “could” and similar terms and phrases are forward-looking ~~statements.~~statements although not all forward-looking statements contain such identifying words. Included in forward-looking statements are, among other things:

~~statements regarding our business strategy or~~

●

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

●

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

●

statements regarding our backlog and commercial contracts and rates thereunder;

~~statements regarding the construction, upgrades or acquisition~~

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

Contents

●

statements regarding our ability to enter into, renew and/or perform commercial contracts, including the scope, timing and outcome of those contracts;

●

statements regarding the spot market, the continuation of our current backlog, visibility and future utilization, our spending and cost management efforts and our ability to manage changes, oil price volatility and its effects and results on the foregoing as well as our protocols and plans;

●

statements regarding energy transition and energy security;

●

statements regarding our ability to identify, effect and integrate acquisitions, joint ventures or other transactions;

●

statements regarding the acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto;

●

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

●

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

●

statements regarding our trade receivables and their collectability;

●

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

●

statements regarding our ESG initiatives and the successes thereon or regarding our environmental efforts, including greenhouse gas emissions targets;

●

statements regarding global, market or investor sentiment with respect to fossil fuels;

●

statements regarding our existing activities in, and future expansion into, the offshore renewable energy market;

●

statements regarding general economic or political conditions, whether international, national or in the regional or local markets in which we do business;

●

statements regarding our human capital resources, including our ability to retain our senior management and other key employees;

●

statements regarding our share repurchase authorization or program;

●

statements regarding the underlying assumptions related to any projection or forward-looking statement; and

●

any other statements that relate to non-historical or future information.

~~statements regarding the commencement of commercial operations of the~~ ~~Siem 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, expenses, earnings or losses, working capital, debt and liquidity, or other financial items;~~

~~statements regarding our backlog and long-term contracts and rates thereunder;~~

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

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

~~statements regarding our trade receivables and their collectability;~~

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

~~statements regarding general economic or political conditions, whether international, national or in the regional and local market areas in which we do business;~~

~~statements regarding our ability to retain key members of our senior management and other key employees;~~

~~statements regarding the underlying assumptions related to any projection or forward-looking statement; and~~

~~any other statements that relate to non-historical or future information.~~

Although we believe that the expectations reflected in our forward-looking statements are reasonable and are based on reasonable assumptions, they do involve risks, uncertainties and other factors that could cause actual results to bediffer materially ~~different~~ from those in the forward-looking statements. These factors include:

~~the impact of domestic and global economic conditions and the future impact of such conditions on the oil and gas industry and the demand for our services;~~

~~the impact of oil and gas price fluctuations and the cyclical nature of the oil and gas industry;~~

●

the impact of domestic and global economic and market conditions and the future impact of such conditions on the offshore energy industry and the demand for our services;

●

the general impact of oil and gas price volatility and the cyclical nature of the oil and gas market;

●

the potential effects of regional tensions that have escalated or may escalate, including into conflicts or wars, and their impact on the global economy, oil and gas market, our operations, international trade, or our ability to do business with certain parties or in certain regions, and any governmental sanctions resulting therefrom;

●

the results of corporate initiatives such as alliances, partnerships, joint ventures, mergers, acquisitions, divestitures and restructurings, and any earn-outs payable in connection therewith, or the determination not to pursue or effect such initiatives;

●

the results of acquired properties and/or equipment;

●

the impact of inflation and our ability to recoup rising costs in the rates we charge to our customers;

●

the impact of our ability to secure and realize backlog, including any potential cancellation, deferral or modification of our work or contracts by our customers;

●

the ability to effectively bid, renew and perform our contracts, including the impact of equipment problems or failure;

●

the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets;

●

the performance of contracts by suppliers, customers and partners;

●

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

●

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

●

the effectiveness and timing of our vessel and/or system upgrades, regulatory certification and inspection as well as major maintenance items;

●

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

●

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

~~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 the items identified in the~~ ~~Siem Helix~~1 ~~acceptance process and the timing thereof;~~

~~the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets, including the~~ ~~Q4000, the~~ ~~Q5000~~ ~~and the~~ ~~Siem Helix~~1;

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

~~the effectiveness and timing of completion of our vessel upgrades and major maintenance items;~~

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

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

~~the success of our risk management activities;~~

~~the effects of competition;~~

Table of Contents

●

the impact of foreign currency exchange controls, potential illiquidity of those currencies and exchange rate fluctuations;

●

the effects of our indebtedness, our ability to comply with debt covenants and our ability to reduce capital commitments;

●

the success of our risk management activities, including with respect to our cybersecurity initiatives;

●

the effects of competition;

●

the availability of capital (including any financing) to fund our business strategy and/or operations;

●

the effectiveness of our ESG initiatives and disclosures;

●

the impact of current and future laws and governmental regulations and how they will be interpreted or enforced, including related to fossil fuel production, decommissioning, and litigation and similar claims in which we may be involved;

●

the future impact of international activity and trade agreements on our business, operations and financial condition;

●

the effectiveness of any future hedging activities;

●

the potential impact of a negative event related to our human capital resources, including a loss of one or more key employees;

●

the impact of general, market, industry or business conditions; and

●

the factors generally described in Item 1A. Risk Factors in our 2022 Form 10-K.

~~the availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations;~~

~~the impact of current and future laws and governmental regulations, including tax and accounting developments;~~

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

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

~~the impact of foreign currency fluctuations;~~

~~the effectiveness of our current and future hedging activities;~~

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

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

Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in Item ~~1A. “Risk Factors”~~7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our ~~2016~~2022 Form 10-K. ~~All~~Should one or more of the risks or uncertainties described in this Quarterly Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking ~~statements attributable~~statements.

We caution you not to ~~us or persons acting~~place undue reliance on ~~our behalf are expressly qualified in their entirety by these risk factors.~~forward-looking statements. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise ~~these~~ forward-looking statements, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ.

All forward-looking statements, express or implied, included in this Quarterly Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. We urge you to carefully review and consider the disclosures made in this Quarterly Report and our reports filed with the SEC and incorporated by reference in our 2022 Form 10-K that attempt to advise interested parties of the risks and factors that may affect our business.

EXECUTIVE SUMMARY

Our Business ~~Strategy~~

We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention, robotics and ~~robotics~~full-field decommissioning operations. ~~We believe that focusing~~Our services are centered on ~~these services will deliver favorable long-term financial returns. From time to time, we make strategic investments that expand our service capabilities or add capacity to~~a three-legged business model well positioned for a global energy transition by maximizing production of existing ~~services in our key operating regions.~~oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments. Our well intervention fleet ~~expanded following~~includes seven purpose-built well intervention vessels and 12 subsea intervention systems. Our robotics equipment includes 39 work-class ROVs, seven trenchers and the ~~delivery~~IROV boulder grab. We charter robotics support vessels on long-term, short-term, flexible and spot bases to facilitate our ROV and trenching operations. Our Shallow Water Abandonment segment includes nine liftboats, six OSVs, three DSVs, one heavy lift derrick barge, one crew boat, 20 P&A systems and six coiled tubing systems. Our Production Facilities segment includes the HP I, the HFRS and our ownership of ~~the~~ ~~Siem Helix~~ ~~2 chartered vessel in February 2017~~mature oil and ~~is expected to further expand following the completion and delivery~~gas properties.

Table of ~~the~~ ~~Q7000, a newbuild semi-submersible vessel, in 2018. Chartering newer vessels with additional capabilities, including the~~ ~~Grand Canyon III~~ chartered vessel that went into service for us in May 2017, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also benefit by our fixed fee agreement for the ~~HP I~~ ~~servicing the Phoenix field for the field operator until at least June 1, 2023.~~Contents

In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the parties’ strategic alliance to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to customers, combining marine support with well access and control technologies. In April 2015, we and OneSubsea agreed to jointly develop and ordered a 15,000 working p.s.i. IRS, which is expected to be completed mid-fourth quarter of 2017 for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At September 30, 2017, our total investment in the IRS was $11.6 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest). At September 30, 2017, our total investment in the ROAM was $1.9 million. The ROAM is expected to be available to customers in the first quarter of 2018.

Economic Outlook and Industry Influences

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

~~worldwide economic activity, including available access to global capital and capital markets;~~

~~supply and~~factors.

Oil prices have been volatile but remained robust during 2023. Global demand for oil ~~and natural gas, especially in the United States, Europe, China and India;~~

continues to experience growth whereas supply has been negatively impacted by regional conflicts and ~~economic and political conditions in the Middle East and other oil-producing regions;~~

~~actions taken~~production cuts by members of the Organization of Petroleum Exporting ~~Countries;~~

~~Table~~Countries (“OPEC) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”). We expect the current market conditions will maintain continued customer spending for the industry. Despite the current commodity price environment, there remain headwinds to commodity price stability, including those regional conflicts, further OPEC+ decisions, high inflation and in particular governments’ and central banks’ efforts to control inflation such as raising interest rates, which may taper economic growth, and various governmental and customer ESG initiatives and continued shifting of ~~Contents~~

resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility with the ~~availability and discovery rate of new oil and natural gas reserves in offshore areas;~~

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

~~the cost of offshore exploration~~potential to temper customer spending for ~~and production and transportation of oil and natural gas;~~

~~the level of excess production capacity;~~

~~the ability of~~ oil and gas ~~companies~~projects.

We are subject to ~~generate funds or otherwise obtain external capital for capital projects~~the effects of changing prices. Inflation rates have been relatively low and stable over the previous three decades; however, inflation rates have risen significantly since 2021. Although we may be able to mitigate our exposure to price increases through the rates we charge, we bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification and dry dock costs. While the cost outlook is not certain, we believe that we can manage these inflationary pressures by through the rates we charge and by actively pursuing internal cost management efforts. However, competitive market pressures may affect our ability to recoup these price increases through our rates, which may result in reductions in our operating margins and cash flows. The recent high inflation rates seen in various major economies have resulted in central banks’ tightening of monetary policies. These concerns have contributed to stock market volatility as well as higher interest rates, which could provide a strained macroeconomic outlook and in turn affect energy markets.

We maximize production ~~operations;~~

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

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

~~potential acceleration of the development of alternative fuels;~~

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

~~weather conditions and natural disasters;~~

~~environmental and other governmental regulations; and~~

~~domestic and international tax laws, regulations and policies.~~

~~The significant decline in oil prices since mid-year 2014 and the resulting difficult industry environment has had a significant adverse impact on investments in~~existing oil and gas ~~exploration and production. Many oil and gas companies have terminated or not renewed contracts~~reserves for ~~many of their contracted rigs and have drastically cut investments~~our customers primarily in exploration and production as well as other operational activities. We expect these challenging industry conditions to continue through the end of 2017 and beyond if oil and gas prices fail to increase to a level conducive to increased activity levels. Increased competition for limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects us, asour Well Intervention segment. Historically, drilling rigs ~~historically~~ have been the asset class used for offshore well intervention ~~work. This~~work, and rig ~~overhang combined with lower~~day rates are a pricing indicator for our services. Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities. Current volumes of work, ~~may~~rig utilization rates, the day rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our ~~assets. In addition, despite~~assets and services.

Over the upward trend in global economic growth especially in emerging markets, the current volatile and uncertain macroeconomic conditions in some countries around the world, such as Brazil 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 theynear-term, we 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~~seeing oil and gas companies ~~are increasingly focusing~~investing in new long-cycle exploration projects in addition to maintaining and/or increasing production from their existing reserves. As historically production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we expect oil and gas companies to continue to focus 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 oil and gas companies begin to increase overall spending levels, itexpect the fundamentals for our business will likely be for 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 services at the end of the life of a field as required by governmental regulations. Thusremain favorable over the longer term ~~we believe that fundamentals for our business remain favorable~~ as the need ~~for prolongation of~~to prolong well life in oil and gas production is the primary driver of demand for our production enhancement services.

~~Our current strategy is to be positioned for future recovery while coping with a sustained period of weak activity.~~ This ~~strategy~~expectation is based on multiple factors, including (1) maintaining the ~~following factors: (1)~~optimal production of a well through enhancement is fundamental to maximizing the ~~need to extend the life~~overall economics of ~~subsea wells is significant to the commercial viability of the wells as plug and abandonment costs are considered;~~well production; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new ~~drilling~~drilling; and (3) extending the production of offshore wells not only maximizes a well’s production economics but also enables the financial benefit of delaying P&A costs, which can be substantial.

We support the energy transition to renewables through our services in offshore wind farm developments, primarily including subsea cable trenching and burial as well as ~~extending~~seabed clearance 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 the HFRS in 2011 as a culmination of~~preparation services. Demand for our ~~experience as a responder~~services in the ~~2010 Macondo well control and containment efforts. The HFRS centers on two~~renewable energy market is affected by various factors, including the pace of ~~our vessels,~~consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase 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 in the Gulf of Mexico. The HFRS provides industry participants with a response resource to be named in permit applications to federal and state agencies in exchange for a retainer fee. The HFRS agreements specify the day rates to be charged should the HFRS be deployed in connection with a well control incident. The agreement providing access to the HFRS was amended effective February 1, 2017 togeneration and/or reduce the ~~retainer fee~~cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects. We expect growth in our renewables services as the energy market transitions to ~~extend the term of the agreement by one year to March 31, 2019.~~continued renewable energy developments.

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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 primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and have expanded our operations into Brazil with the commencement of operations of the ~~Siem Helix 1~~ ~~in mid-April 2017. In addition to servicing the~~

Once end-of-life oil and gas ~~market,~~wells have depleted their production, we decommission wells and infrastructure in our ~~Robotics operations are contracted for~~Well Intervention and Shallow Water Abandonment segments. As the ~~development of~~subsea tree base expands and ages and customers shift resources to renewable energy, ~~projects (wind farms).~~the demand for P&A services should persist. Our operations service the life cycle of an oil and gas field and provide P&A and decommissioning services at the end of the life of a field as required by governmental regulations, and we believe that we have a competitive advantage in performing these services efficiently.

Backlog

We define backlog as firm commitments represented by signed contracts. As of September 30, ~~2017,~~2023, our consolidated backlog ~~that is supported by written agreements or contracts~~ totaled ~~$1.7 billion,~~approximately $790 million, of which ~~$135.3~~$242 million is expected to be performed over the remainder of ~~2017. The substantial majority of~~2023. Our various contracts with Shell globally, our ~~backlog is associated~~contracts with Trident and Petrobras in Brazil, our ~~Well Intervention business segment. As of September 30, 2017, our well intervention backlog was $1.3 billion, including $94.9 million expected to be performed over the remainder of 2017. Our contract~~contracts with ~~BP to provide well intervention services with our~~ ~~Q5000~~ ~~semi-submersible vessel, our agreements with Petrobras to provide well intervention services offshore Brazil with the~~ ~~Siem Helix 1~~ ~~and~~ ~~Siem Helix 2~~ ~~chartered vessels,~~Repsol globally, and our ~~fixed fee~~ agreement for the HP I ~~represent~~ in the Gulf of Mexico represented approximately ~~87%~~57% of our total backlog as of September 30, ~~2017.~~2023. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be 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 andamounts reflected in ~~many cases modified while in progress, and reduced rates, fines and penalties may be imposed by our customers.~~

backlog.

RESULTS OF OPERATIONS

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~~evaluate our operating performance and financial condition based on EBITDA, aAdjusted EBITDA, Free Cash Flow and Net Debt. EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt 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, Adjusted EBITDA, Free Cash Flow and Net Debt 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~~Adjusted EBITDA, Free Cash Flow and Net Debt provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand ~~our operating performance~~ and compare our results to other companies that have different financing, capital and tax structures.

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

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Other companies may calculate their measures of EBITDA, ~~and~~ Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. ~~Because~~ EBITDA, ~~and~~ Adjusted EBITDA, ~~are not financial measures calculated in accordance with U.S. GAAP, they~~Free Cash Flow and Net Debt 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~~ data prepared in accordance with ~~U.S.~~ GAAP.

We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets, acquisition and integration costs, the change in fair value of contingent consideration and the general provision (release) for current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents and restricted cash. In the following reconciliations, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2023		2022		2023		2022
Net income (loss)	$	15,560	$	(18,763)	$	17,495	$	(90,493)
Adjustments:
Income tax provision		8,337		6,500		9,631		10,074
Net interest expense		4,152		4,644		12,567		14,617
Other expense, net		8,257		20,271		10,553		37,623
Depreciation and amortization		43,249		35,944		120,013		102,590
Gain on equity investment		—		(78)		—		(8,262)
EBITDA		79,555		48,518		170,259		66,149
Adjustments:
Gain on disposition of assets, net		—		—		(367)		—
Acquisition and integration costs		—		762		540		2,349
Change in fair value of contingent consideration		16,499		2,664		31,319		2,664
General provision for current expected credit losses		331		624		1,020		691
Adjusted EBITDA	$	96,385	$	52,568	$	202,771	$	71,853

The reconciliation of our cash flows from operating activities to Free Cash Flow is as follows (in thousands):


	Nine Months Ended
	September 30,
	2023		2022
Cash flows from operating activities	$	57,720	$	1,396
Less: Capital expenditures, net of proceeds from sale of assets		(15,800)		(4,990)
Free Cash Flow	$	41,920	$	(3,594)

The reconciliation of our long-term debt to Net Debt is as follows (in thousands):


	September 30,		December 31,
	2023		2022
Long-term debt including current maturities	$	227,257	$	264,075
Less: Cash and cash equivalents and restricted cash		(168,370)		(189,111)
Net Debt	$	58,887	$	74,964

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

Net income (loss) $ 2,290
$ 11,462
$ (20,528 ) $ (27,032 )
Adjustments:
Income tax provision (benefit) (1,539 ) 3,649
(1,117 ) (9,858 )
Net interest expense 3,615
6,843
15,480
25,007
(Gain) loss on early extinguishment of long-term debt —
(244 ) 397
(546 )
Other (income) expense, net 551
(830 ) 619
(4,018 )
Depreciation and amortization 26,293
27,607
82,670
84,846
EBITDA 31,210
48,487
77,521
68,399
Adjustments:
Loss on disposition of assets, net —
—
39
—
Realized losses from cash settlements of ineffective foreign currency exchange contracts (758 ) (1,786 ) (2,759 ) (5,744 )
Adjusted EBITDA $ 30,452
$ 46,701
$ 74,801
$ 62,655

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Comparison of Three Months Ended September 30, ~~2017~~2023 and ~~2016~~

2022

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. All material intercompany transactions between the segments have been eliminated in our condensed consolidated financial statements, including our condensed consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):


	Three Months Ended						Increase/
	September 30,						(Decrease)
	2023			2022			Amount		Percent
Net revenues —
Well Intervention	$	225,367		$	143,925		$	81,442	57	%
Robotics		75,646			56,182			19,464	35	%
Shallow Water Abandonment		87,272			67,401			19,871	29	%
Production Facilities		24,469			18,448			6,021	33	%
Intercompany eliminations		(17,084)			(13,409)			(3,675)
	$	395,670		$	272,547		$	123,123	45	%

Gross profit (loss) —
Well Intervention	$	19,704		$	1,839		$	17,865	971	%
Robotics		22,707			13,514			9,193	68	%
Shallow Water Abandonment		29,235			17,381			11,854	68	%
Production Facilities		9,385			6,854			2,531	37	%
Corporate, eliminations and other		(486)			(373)			(113)
	$	80,545		$	39,215		$	41,330	105	%

Gross margin —
Well Intervention		9	%		1	%
Robotics		30	%		24	%
Shallow Water Abandonment		33	%		26	%
Production Facilities		38	%		37	%
Total company		20	%		14	%

Number of vessels, Robotics assets or Shallow Water Abandonment systems ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels		7 / 92	%		7 / 87	%
Robotics assets ⁽³⁾		46 / 67	%		46 / 66	%
Chartered Robotics vessels		6 / 97	%		5 / 98	%
Shallow Water Abandonment vessels ⁽⁴⁾		20 / 89	%		21 / 80	%
Shallow Water Abandonment systems ⁽⁵⁾		26 / 74	%		20 / 59	%

Three Months Ended
September 30,
Increase/
(Decrease)
2017 2016
Net revenues —
Well Intervention $ 111,522
$ 108,287
$ 3,235
Robotics 47,049
48,897
(1,848 )
Production Facilities 16,380
17,128
(748 )
Intercompany elimination (11,691 ) (13,067 ) 1,376
$ 163,260
$ 161,245
$ 2,015

Gross profit (loss) —
Well Intervention $ 20,642
$ 28,174
$ (7,532 )
Robotics (6,991 ) 4,953
(11,944 )
Production Facilities 7,780
8,413
(633 )
Corporate and other (489 ) (483 ) (6 )
Intercompany elimination 199
(873 ) 1,072
$ 21,141
$ 40,184
$ (19,043 )

Gross margin —
Well Intervention 19%
26%

Robotics (15)%
10%

Production Facilities 47%
49%

Total company 13%
25%

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

Well Intervention vessels 5/88%
5/76%

Robotics assets 60/46%
60/57%

Chartered robotics vessels 5/80%
3/81%

(1)

Represents the number of vessels, Robotics assets or ~~robotics assets~~Shallow Water Abandonment systems as of the end of the period, including spot vessels and those under term charters, and excluding acquired vessels prior to their in-service dates, vessels managed on behalf of third parties and vessels or assets disposed of and/or taken out of ~~service prior to their disposition and vessels jointly owned with a third party.~~service.

(2)

Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or ~~robotics assets~~Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period. Utilization rates of chartered Robotics vessels during the three-month periods ended September 30, 2023 and 2022 included 92 and 100 spot vessel days, respectively, at near full utilization.

(3)	Consists of ROVs, trenchers and the IROV boulder grab.

(4)	Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.

(5)	Consists of P&A systems and coiled tubing systems.

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

Well Intervention $ 3,765
$ 2,898
$ 867
Robotics 7,926
10,169
(2,243 )
$ 11,691
$ 13,067
$ (1,376 )

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	Three Months Ended
	September 30,				Increase/
	2023		2022		(Decrease)
Well Intervention	$	6,832	$	4,303	$	2,529
Robotics		10,252		8,971		1,281
Shallow Water Abandonment		—		135		(135)
	$	17,084	$	13,409	$	3,675

Net Revenues.Our ~~total~~consolidated net revenues ~~increased by 1%~~ for the three-month period ended September 30, ~~2017~~2023 increased by 45% as compared to the same period in ~~2016. Increased revenues for the three-month period in 2017 reflected~~2022, reflecting higher revenues inacross our ~~Well Intervention segment, offset in part by revenue decreases in our Robotics and Production Facilities~~business segments.

Our Well Intervention revenues increased by 3%57% for the three-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016~~2022, primarily reflecting higher revenues ~~generated from our well intervention operations in Brazil, offset in part by operational downtime experienced by~~on the ~~Well Enhancer~~Q7000 and higher rates in the North Sea and ~~$15.6 million we recognized in~~Brazil. During the third quarter ~~of 2016 associated with a work scope cancellation under a “take or pay” contract originally scheduled~~2023, the Q7000 operated throughout the quarter, achieving 88% utilization at higher rates as compared to ~~be performed by the~~ ~~Q4000~~ ~~in late 2016. In Brazil, the~~ ~~Siem Helix~~1 ~~was 96%~~being 59% utilized during the third quarter ~~of 2017. Our~~2022 following scheduled regulatory maintenance. Revenues in the North Sea improved with higher day rates ~~improved in~~and a stronger British pound as compared to the third quarter ~~as we addressed most of the items identified~~2022. Revenues in ~~the vessel acceptance process. In the North Sea, the~~ ~~Well Enhancer~~ ~~was 84% utilized during the third quarter of 2017 while the vessel was 91% utilized during the same period in 2016. The~~ ~~Seawell~~ ~~was 97% utilized during the third quarter of 2017 as compared to being 98% utilized during the same period in 2016. In the Gulf of Mexico, the~~ ~~Q5000~~ ~~was 75% utilized during the third quarter of 2017~~Brazil increased primarily due to ~~18 idle days during~~higher rates as both the ~~off-hire period~~Siem Helix 1 and the Siem Helix 2 commenced long-term contracts with improved rates at the end of ~~the BP contract. The vessel was 84% utilized during the same period in 2016. The~~ ~~Q4000~~ ~~was 86% utilized during the third quarter of 2017 as compared to being 93% utilized during the same period in 2016.~~

2022.

Our Robotics revenues ~~decreased~~increased by 4%35% for the three-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. The decrease~~2022, primarily ~~reflected lower~~reflecting higher chartered vessel and ROV activities and rates. Although chartered vessel utilization ~~of our robotics assets~~declined slightly, vessel days increased to 506 days during the third quarter 2023 as compared to 376 days during the third quarter 2022. ROV and ~~accepting work at reduced rates, offset~~trencher utilization increased to 67% in ~~part by~~ the ~~addition of~~third quarter 2023 from 66% during the ~~Grand Canyon III~~ ~~to our robotics fleet~~third quarter 2022 and ~~30 additional~~included 276 days of ~~spot~~integrated vessel ~~utilization~~trenching in the ~~comparable quarter-over-quarter periods. Some of our ROV units have been affected~~third quarter 2023 as compared to 176 days in the third quarter 2022.

Our Shallow Water Abandonment revenues increased by ~~other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn.~~

~~Our Production Facilities revenues decreased by 4%~~29% for the three-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016, which reflected reduced retainer fees from~~2022, primarily reflecting higher vessel and system utilization and rates in the ~~amended HFRS agreement that became effective February 1, 2017.~~

~~Gross Profit (Loss).~~third quarter 2023. Overall vessel utilization was 89% during the third quarter 2023 as compared to 80% during the third quarter 2022. P&A systems and coiled tubing systems achieved 1,531 days of utilization, or 74%, during the third quarter 2023 as compared to 1,077 days of utilization, or 59%, during the third quarter 2022.

Our ~~total gross profit decreased~~Production Facilities revenues increased by ~~47%~~33% for the three-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. The gross profit related to our Well Intervention segment decreased~~2022, primarily reflecting higher oil and gas production, offset in part by ~~27% for~~lower oil and gas prices during the ~~three-month period ended September 30, 2017~~third quarter 2023 as compared to the ~~same period in 2016 primarily reflecting the $15.6 million in~~ third quarter ~~2016 revenues associated with a take-or-pay contract.~~

~~The~~2022.

Gross Profit (Loss). Our consolidated gross profit ~~associated with our Robotics segment decreased~~increased by 241% for the three-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting decreased utilization for our robotics assets, accepting work with lower profit margins and increased vessel costs associated with the addition of the ~~Grand Canyon III~~ ~~in May 2017.~~

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

~~Selling, General and Administrative Expenses.~~ ~~Our selling, general and administrative expenses decreased by $2.3~~$41.3 million for the three-month period ended September 30, ~~2017 primarily attributable~~2023 as compared to ~~a $2.7 million charge in~~ the same period in ~~2016 that was associated with~~2022, primarily reflecting increased segment profitability as well as the ~~provision for uncertain collection~~addition of ~~a portion of our note receivable related to our Robotics~~Shallow Water Abandonment segment.

~~Net Interest Expense.~~

Our ~~net interest expense decreased~~Well Intervention gross profit increased by ~~$3.2~~$17.9 million for the three-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016~~2022, primarily reflecting a decrease in interest expense and an increase in capitalized interest. The decrease in interest expense was primarily attributable to a significant reduction in our debt levels including the $80 million principal reduction of our term loan in June 2017 (Note 6). Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $3.9higher segment revenues.

Our Robotics gross profit increased by $9.2 million for the three-month period ended September 30, ~~2017~~2023 as compared to ~~$3.1 million for~~ the same period in ~~2016.~~

~~Table of Contents~~

~~Other Income (Expense), Net.~~ ~~We reported other expense, net, of $0.6~~2022, primarily reflecting higher revenues due to increased activities.

Our Shallow Water Abandonment gross profit increased by $11.9 million for the three-month period ended September 30, ~~2017~~2023 as compared to ~~other income, net, of $0.8 million for~~ the same period in 2016. Net other income (expense) for the three-month periods ended September 30, 2017 and 2016 included foreign currency transaction losses totaling $1.6 million and $0.5 million, respectively. Also included in the comparable quarter-over-quarter periods were net gains of $1.1 million and $1.3 million, respectively, associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 14).

~~Income Tax Provision (Benefit).~~ ~~Income tax benefit was $1.5~~2022, primarily reflecting better operating results from Helix Alliance.

Our Production Facilities gross profit increased by $2.5 million for the three-month period ended September 30, ~~2017~~2023 as compared to ~~income tax provision of $3.6 million for~~ the same period in ~~2016.~~ 2022, primarily reflecting higher revenues.

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Change in Fair Value of Contingent Consideration. The ~~variance primarily~~change in fair value of contingent consideration reflected ~~decreased profitability~~increases in the ~~current year period. The effective tax rate was (204.9)%~~estimated Alliance acquisition earn-out consideration primarily due to an improvement in Helix Alliance’s results (Notes 3 and 17).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $27.8 million for the three-month period ended September 30, ~~2017~~2023 as compared to ~~24.1%~~$23.6 million for the same period in ~~2016.~~2022, primarily reflecting higher employee compensation costs.

Net Interest Expense. Our net interest expense totaled $4.2 million for the three-month period ended September 30, 2023 as compared to $4.6 million for the same period in 2022, primarily reflecting the increase in interest income and the repayment of certain indebtedness (Note 6).

Other Expense, Net. Net other expense was $8.3 million for the three-month period ended September 30, 2023 as compared to $20.3 million for the same period in 2022, primarily reflecting a reduction in foreign currency losses related to the depreciation of the British pound primarily on U.S. dollar denominated intercompany debt in our U.K. entities.

Income Tax Provision. Income tax provision was $8.3 million for the three-month period ended September 30, 2023 as compared to $6.5 million for the same period in 2022. The ~~variance was~~effective tax rates for the three-month periods ended September 30, 2023 and 2022 were 34.9% and (53.0)%, respectively. These variances were primarily attributable to ~~the earnings mix between our higher~~non-deductible expenses, non-creditable foreign income taxes and ~~lower tax rate jurisdictions.~~losses for which no financial statement benefits have been recognized (Note 7).

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Comparison of Nine Months Ended September 30, ~~2017~~2023 and ~~2016~~

2022


	Nine Months Ended						Increase/
	September 30,						(Decrease)
	2023			2022			Amount		Percent
Net revenues —
Well Intervention	$	522,026		$	356,583		$	165,443	46	%
Robotics		194,918			143,383			51,535	36	%
Shallow Water Abandonment		212,959			67,401			145,558	216	%
Production Facilities		68,502			54,420			14,082	26	%
Intercompany eliminations		(43,834)			(36,503)			(7,331)
	$	954,571		$	585,284		$	369,287	63	%

Gross profit (loss) —
Well Intervention	$	22,316		$	(45,943)		$	68,259	149	%
Robotics		49,238			28,631			20,607	72	%
Shallow Water Abandonment		57,725			17,381			40,344	232	%
Production Facilities		23,822			20,150			3,672	18	%
Corporate, eliminations and other		(2,023)			(967)			(1,056)
	$	151,078		$	19,252		$	131,826	685	%

Gross margin —
Well Intervention		4	%		(13)	%
Robotics		25	%		20	%
Shallow Water Abandonment		27	%		26	%
Production Facilities		35	%		37	%
Total company		16	%		3	%

Number of vessels, Robotics assets or Shallow Water Abandonment systems ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels		7 / 85	%		7 / 74	%
Robotics assets ⁽³⁾		46 / 60	%		46 / 52	%
Chartered Robotics vessels		6 / 95	%		6 / 94	%
Shallow Water Abandonment vessels ⁽⁴⁾		20 / 75	%		21 / 80	%
Shallow Water Abandonment systems ⁽⁵⁾		26 / 74	%		20 / 59	%

Nine Months Ended
September 30,
Increase/
(Decrease)
2017 2016
Net revenues —
Well Intervention $ 299,219
$ 214,262
$ 84,957
Robotics 102,078
119,805
(17,727 )
Production Facilities 47,965
54,567
(6,602 )
Intercompany elimination (31,145 ) (29,083 ) (2,062 )
$ 418,117
$ 359,551
$ 58,566

Gross profit (loss) —
Well Intervention $ 47,757
$ 17,195
$ 30,562
Robotics (29,376 ) (12,008 ) (17,368 )
Production Facilities 21,031
25,634
(4,603 )
Corporate and other (1,370 ) (1,367 ) (3 )
Intercompany elimination 641
(542 ) 1,183
$ 38,683
$ 28,912
$ 9,771

Gross margin —
Well Intervention 16%
8%

Robotics (29)%
(10)%

Production Facilities 44%
47%

Total company 9%
8%

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

Well Intervention vessels 5/79%
5/52%

Robotics assets 60/42%
60/48%

Chartered robotics vessels 5/61%
3/63%

(1)

(2)

Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or ~~robotics assets~~Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period. Utilization rates of chartered Robotics vessels during the nine-month periods ended September 30, 2023 and 2022 included 218 and 352 spot vessel days, respectively, at near full utilization.

(3)	Consists of ROVs, trenchers and the IROV boulder grab.

(4)	Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.

(5)	Consists of P&A systems and coiled tubing systems.

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

Well Intervention $ 8,033
$ 5,740
$ 2,293
Robotics 23,112
23,343
(231 )
$ 31,145
$ 29,083
$ 2,062


	Nine Months Ended
	September 30,				Increase/
	2023		2022		(Decrease)
Well Intervention	$	18,174	$	12,046	$	6,128
Robotics		25,634		24,322		1,312
Shallow Water Abandonment		26		135		(109)
	$	43,834	$	36,503	$	7,331

Net Revenues.Our ~~total~~consolidated net revenues ~~increased by 16%~~ for the nine-month period ended September 30, ~~2017~~2023 increased by 63% as compared to the same period in ~~2016. Increased revenues for the nine-month period in 2017 reflected~~2022, reflecting higher revenues inacross our ~~Well Intervention segment, offset in part by revenue decreases in our Robotics and Production Facilities~~business segments.

Our Well Intervention revenues increased by ~~40%~~46% for the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016~~2022, primarily reflecting 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 utilization of 96%. In~~ the North Sea and Brazil and on the ~~Well Enhancer~~ ~~was 81% utilized~~Q7000, offset in part by lower revenues in the Gulf of Mexico. Revenues in the North Sea improved with stronger utilization and rates as compared to the nine-month period ended September 30, 2022. Revenues in Brazil increased primarily due to higher rates as both the Siem Helix 1 and the Siem Helix 2 commenced long-term contracts with improved rates at the end of 2022. Higher revenues on the Q7000 were primarily attributable to the vessel achieving higher utilization and rates during the ~~first nine months of 2017 while the vessel was 60% utilized during~~third quarter 2023 as compared to the same period in ~~2016. The~~ ~~Seawell~~ ~~was 84% utilized during the first nine months of 2017 whereas it was 41% utilized during the same period~~2022. Revenues in ~~2016. In~~ the Gulf of Mexico decreased primarily due to lower utilization on the Q4000 and the Q5000 as both vessels had their scheduled regulatory dry dock in 2023. This revenue decrease was ~~88% utilized during~~partially offset by improved day rates on 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.~~

Our Robotics revenues ~~decreased~~increased by ~~15%~~36% for the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. The decrease~~2022, primarily ~~reflected lower~~reflecting higher utilization and rates on vessels, ROVs and trenchers. Chartered vessel days and utilization increased to 1,236 days and 95%, respectively, during the nine-month period ended September 30, 2023 as compared to 1,069 days and 94%, respectively, during the nine-month period ended September 30, 2022. ROV and trencher utilization increased to 60% in the nine-month period ended September 30, 2023 from 52% during the nine-month period ended September 30, 2022 and included 536 days of ~~our robotics assets~~integrated vessel trenching in 2023 as compared to 323 days in 2022. Also included in the nine-month period ended September 30, 2023 were 148 days of stand-alone trencher activities on the i-Plough trencher and ~~accepting work at reduced rates. Some~~83 days of ~~our ROV units have been affected by other industry participants laying up vessels or canceling work as a result~~utilization on the IROV boulder grab, both of which were acquired in the ~~oil and gas industry downturn.~~

second half of 2022.

Our ~~Production Facilities~~Shallow Water Abandonment revenues ~~decreased by 12%~~ for the nine-month period ended September 30, ~~2017~~2023 reflected nine months of revenue generated by Helix Alliance with 75% utilization across 20 vessels and 4,362 days of utilization across 26 P&A systems and coiled tubing systems. Our Shallow Water Abandonment revenues for the nine-month period ended September 30, 2022 reflected three months of revenue generated by Helix Alliance since July 1, 2022 (Note 3) with 80% utilization across 21 vessels and 1,077 days of utilization across P&A systems and coiled tubing systems.

Our Production Facilities revenues for the nine-month period ended September 30, 2023 increased by 26% as compared to the same period in ~~2016, which reflected reduced retainer fees from the amended HFRS agreement that became effective February 1, 2017~~2022, primarily reflecting higher oil and ~~lower revenues from the fixed fee agreement~~gas production with the ~~Phoenix field operator for~~contribution from our interest in the ~~HP I~~ ~~that commenced June 1, 2016.~~

~~Gross Profit (Loss).~~ ~~Our total gross profit increased~~Thunder Hawk Field acquired during the third quarter 2022, offset in part by ~~34% for~~lower oil and gas prices during the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. The~~2022.

Gross Profit (Loss). Our consolidated gross profit ~~related to our Well Intervention segment~~ increased by ~~178% for the nine-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting higher revenues in our North Sea region.~~

The gross profit associated with our Robotics segment decreased by 145% for the nine-month period ended September 30, 2017 as compared to the same period in 2016 primarily reflecting decreased utilization for our robotics assets and accepting work with lower profit margins.

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

~~Table of Contents~~

~~Selling, General and Administrative Expenses.~~ ~~Our selling, general and administrative expenses decreased by $1.0~~$131.8 million for the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. The~~2022, primarily reflecting increased segment profitability as well as the addition of Shallow Water Abandonment segment since July 1, 2022.

Our Well Intervention gross profit for the nine-month ~~periods~~period ended September 30, ~~2017 and 2016 included charges~~2023 was $22.3 million as compared to a gross loss of ~~$1.2~~$45.9 million ~~and $2.7 million, respectively, that were associated with~~for the ~~provision for uncertain collection of a portion of our receivables related to our~~same period in 2022, primarily reflecting higher segment revenues.

Our Robotics ~~segment.~~

~~Net Interest Expense.~~ ~~Our net interest expense decreased~~gross profit increased by ~~$9.5~~ $20.6million for the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016~~2022, primarily reflecting ~~increases in interest income and capitalized interest and a decrease in interest expense. Interest income totaled $2.1~~higher revenues due to increased activities.

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Our Shallow Water Abandonment gross profit increased by $40.3 million for the nine-month period ended September 30, ~~2017~~2023 as compared to ~~$1.7~~the same period in 2022, primarily reflecting nine months of operating results from Helix Alliance in 2023 as compared to three months of operating results in 2022.

Our Production Facilities gross profit increased by $3.7 million for the nine-month period ended September 30, 2023 as compared to the same period in 2022, primarily reflecting higher revenues.

Acquisition and Integration Costs. Our acquisition and integration costs decreased by $1.8 million for the nine-month period ended September 30, 2023 as compared to the same period in 2022, reflecting lower spend towards the late stage of the Alliance integration process.

Change in Fair Value of Contingent Consideration. The change in fair value of contingent consideration reflected increases in the estimated Alliance acquisition earn-out consideration primarily due to an improvement in Helix Alliance’s results (Notes 3 and 17).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $71.5 million for the nine-month period ended September 30, 2023 as compared to $54.0 million for the same period in ~~2016.~~2022, primarily reflecting higher employee compensation costs and the addition of Helix Alliance.

Equity in Earnings of Investment. Equity in earnings of investment was $8.3 million for the nine-month period ended September 30, 2022 primarily reflecting gains recognized as a result of the sale of the “Independence Hub” platform.

Net Interest ~~on debt used to finance capital projects is capitalized and thus reduces overall~~Expense. Our net interest ~~expense. Capitalized interest~~expense totaled $12.6 million for the nine-month period ended September 30, ~~2017~~2023 as compared to ~~$7.5~~$14.6 million for the same period in ~~2016. The decrease~~2022, primarily reflecting the increase in interest income and the repayment of certain indebtedness (Note 6).

Other Expense, Net. Net other 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).

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

~~Other Income (Expense), Net.~~ ~~We reported other expense, net, of $0.6~~$10.6 million for the nine-month period ended September 30, ~~2017 as compared to other income, net, of $4.0 million for the same period in 2016. Net other income (expense) for the nine-month periods ended September 30, 2017 and 2016 included~~2023, primarily reflecting foreign currency ~~transaction gains (losses)~~losses related to the devaluation of ~~$(2.2) million and $0.5 million, respectively. Also included~~the Nigerian naira on our naira cash holdings, offset in ~~the comparable year-over-year periods were net gains of $1.5 million and $3.5 million, respectively, associated with our~~part by foreign currency ~~exchange contracts primarily reflecting~~ gains related to ~~the contracts that were not designated as cash flow hedges (Note 14).~~

~~Income Tax Benefit.~~ ~~Income tax benefit~~U.S. dollar denominated intercompany debt in our U.K. entities. Net other expense was ~~$1.1~~$37.6 million for the nine-month period ended September 30, ~~2017 as compared to $9.9 million for the same period in 2016. The variance~~2022, 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~~reflecting foreign currency losses related to U.S. dollar denominated intercompany debt in our ~~foreign taxes. The effective~~U.K. entities.

Income Tax Provision. Income tax ~~rate~~provision was ~~5.2%~~$9.6 million for the nine-month period ended September 30, ~~2017~~2023 as compared to ~~26.7%~~$10.1 million for the same period in ~~2016.~~2022. The ~~variance was~~effective tax rates for the nine-month periods ended September 30, 2023 and 2022 were 35.5% and (12.5)%, respectively. These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions ~~and the change in tax position related to our foreign taxes~~as well as losses for which no financial statement benefits have been recognized (Note 7).

~~Table of Contents~~

LIQUIDITY AND CAPITAL RESOURCES

~~Overview~~

Financial Condition and Liquidity

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


	September 30,		December 31,
	2023		2022
Net working capital	$	164,702	$	162,634
Long-term debt		218,508		225,875
Liquidity		278,608		284,729

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September 30,
2017 December 31,
2016

Net working capital $ 268,817
$ 336,387
Long-term debt ⁽¹⁾
$ 395,345
$ 558,396
Liquidity ⁽²⁾
$ 426,741
$ 375,504


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

~~(2)~~

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

~~The carrying amount of our long-term debt, including~~

Net Working Capital

Net working capital is equal to current assets minus current liabilities and includes current maturities of long-term debt. Net working capital measures short-term liquidity and is important for predicting cash flow and debt requirements.

Long-Term Debt

Long-term debt in the table above is net of unamortized debt ~~discount and debt~~ issuance costs and excludes current maturities of $8.7 million at September 30, 2023 and $38.2 million at December 31, 2022. See Note 6 for information relating to our long-term debt.

Liquidity

We define liquidity as cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility. Our liquidity at September 30, 2023 included $168.4 million of cash and cash equivalents and $110.2 million of available borrowing capacity under the Amended ABL Facility (Note 6). Our liquidity at December 31, 2022 included $186.6 million of cash and cash equivalents and $98.1 million of available borrowing capacity under the Amended ABL Facility and excluded $2.5 million of restricted cash. As of September 30, 2023, we had approximately $15.9 million in Nigerian naira, which has been subject to currency exchange controls established by the Central Bank of Nigeria. Those exchange controls have to date limited our ability to convert our Nigerian naira into U.S. dollars.

Beginning 2022 and continuing through 2023, we have seen an improvement in the markets we serve, following the slowdown triggered by the COVID-19 pandemic, as evidenced by increases in our revenues and gross profit. We expect continued improvements in our operating performance, increases in our cash position and high availability on the Amended ABL Facility. We believe that our cash on hand, internally generated cash flows and availability under the Amended ABL Facility will be sufficient to fund our operations and service our debt over at least the next 12 months.

A period of weak industry activity may make it difficult to comply with the covenants and other restrictions in our debt agreements. Our failure to comply with the covenants and other restrictions could lead to an event of default. Decreases in our borrowing base may limit our ability to fully access the Amended ABL Facility. We currently do not anticipate borrowing under the Amended ABL Facility other than for the issuance of letters of credit.

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. The 2023 Repurchase Program has no set expiration date. Repurchases under the 2023 Repurchase Program are expected to be made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management based on an evaluation of market conditions, stock price, liquidity and other factors. The 2023 Repurchase Program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. The purchase of shares by us under the 2023 Repurchase Program is ~~as follows (in thousands):~~ at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled. During the nine-month period ended September 30, 2023, we repurchased a total of 1,584,045 shares of our common stock for approximately $12.0 million pursuant to the 2023 Repurchase Program.

Table of Contents

September 30,
2017 December 31,
2016

Term Loan (previously scheduled to mature June 2018) $ —
$ 190,867
Nordea Q5000 Loan (matures April 2020) 167,667
193,879
Term Loan (matures June 2020) 96,935
—
MARAD Debt (matures February 2027) 72,365
78,221
2022 Notes (mature May 2022) ⁽¹⁾
108,018
105,697
2032 Notes (mature March 2032) ⁽²⁾
58,971
57,303
Total debt $ 503,956
$ 625,967


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


~~(2)~~	The 2032 Notes will increase to their face amount through accretion of non-cash interest charges through March 15, 2018, which is the first date on which the holders may require us to repurchase the notes.

Cash Flows

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

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

~~Table of Contents~~

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 a further response to the industry-wide spending reductions, we 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 under our Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.

In accordance with our Credit Agreement, the 2022 Notes, the 2032 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. Our Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by us.


	Nine Months Ended
	September 30,
	2023		2022
Cash provided by (used in):
Operating activities	$	57,720	$	1,396
Investing activities		(15,800)		(109,775)
Financing activities		(51,375)		(44,437)

Operating Activities

The Credit Agreement does permit us to incur certain unsecured indebtedness, and also provides for our subsidiaries to incur project financing indebtedness (such as our MARAD Debt and our Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. Our Credit Agreement also permits our Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as definedincrease in our ~~Credit Agreement). As of September 30, 2017 and December 31, 2016, we were in compliance with all of the covenants in our long-term debt agreements.~~

A prolonged period of weak industry activity may make it difficult to comply with our covenants and other restrictions in agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to fully access our Revolving Credit Facility may be impacted. At September 30, 2017, our available borrowing capacity under our Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $69.9 million, net of $4.0 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrow under our Revolving Credit Facility other than for issuances of letters of credit. Our ability to comply with loan agreement covenants and other restrictions is affected by economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, that failure could lead to an event of default, the possible acceleration of our outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral.

Subject to the terms and restrictions of the Credit Agreement, we may borrow and/or obtain letters of credit up to $25 million under our Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding our Credit Agreement, including covenants and collateral.

The 2022 Notes and the 2032 Notes can be converted into our common stock prior to their stated maturity upon certain triggering events specified in the applicable Indenture governing the notes. The holders of the remaining 2032 Notes may require us to repurchase these notes in March 2018. Accordingly, the 2032 Notes are classified as current liabilities on our consolidated balance sheet at September 30, 2017. No conversion triggers were met during the nine-month periods ended September 30, 2017 and 2016.

~~Operating Cash Flows~~

~~Total~~operating cash flows ~~from operating activities increased by $15.9 million~~ for the nine-month period ended September 30, ~~2017~~2023 as compared to the same period in ~~2016. This increase was~~2022 primarily ~~attributable~~reflects higher earnings, offset in part by higher regulatory recertification costs for our vessels and systems and higher working capital outflows. Regulatory recertification spend on our vessels and systems amounted to ~~improvements in our operating results.~~

$59.2 million and $25.6 million, respectively, during the comparable year over year periods.

Investing Activities

Capital expenditures consist principally of the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Significant sources (uses) of cash associated with

Cash flows used in investing activities ~~are as follows (in thousands):~~

~~Table of Contents~~

Nine Months Ended
September 30,
2017 2016
Capital expenditures:
Well Intervention $ (130,649 ) $ (79,147 )
Robotics (691 ) (504 )
Production Facilities —
(74 )
Other (88 ) 372
Distribution from equity investment —
1,200
Proceeds from sale of equity investment ⁽¹⁾
—
25,000
Proceeds from sale of assets ⁽²⁾
10,000
10,887
Net cash used in investing activities $ (121,428 ) $ (42,266 )


~~(1)~~	~~Amount in 2016 reflected cash received from the sale of our former ownership interest in Deepwater Gateway (Note 5).~~


~~(2)~~	Amount in 2017 reflected cash received from the sale of our Ingleside spoolbase (Note 3). Amount in 2016 reflected cash received from the sale of our office and warehouse property located in Aberdeen, Scotland.

~~Capital expenditures associated with our business primarily have included payments associated with the construction of our~~ ~~Q7000~~ ~~vessel (see below) and the investment in the topside well intervention equipment~~ for the ~~Siem Helix 1~~nine-month periods ended September 30, 2023 and ~~Siem Helix 2~~ ~~vessels chartered to perform our agreements with Petrobras (see below).~~

~~In September 2013, we executed~~2022 reflect higher capital expenditures as a ~~contract with the same shipyard in Singapore that constructed the~~ ~~Q5000~~result of increased activity levels as well as $6.0 million cash payment for the ~~construction~~purchase of ~~a newbuild semi-submersible well intervention vessel,~~P&A equipment (Note 2). Cash flows used in investing activities for the ~~Q7000, which is being 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 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. At~~nine-month periods ended September 30, ~~2017, our total investment in the~~ ~~Q7000~~ ~~was $213.6 million, including $138.4 million of installment payments to the shipyard. We plan to incur approximately $77 million of costs related to the construction of the~~ ~~Q7000~~ ~~over the remainder of 2017.~~

In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem for two newbuild monohull vessels, the ~~Siem Helix 1~~ ~~and the~~ ~~Siem Helix 2.~~ ~~The~~ ~~Siem Helix 1~~ ~~commenced its operations for Petrobras in mid-April 2017. We currently expect the~~ ~~Siem Helix 2~~ ~~to be in service for Petrobras late in the fourth quarter of 2017. We have invested $304.1 million as of September 30, 2017 and plan to invest approximately $9~~2022 also included $112.6 million in ~~the topside equipment over the remainder of 2017.~~

net cash paid to acquire Alliance (Note 3).

Financing Activities

~~Cash flows~~

Net cash outflows from financing activities ~~consist primarily of proceeds from debt and equity financing activities and repayments of our long-term debt. Total cash flows from financing activities increased by $71.2 million~~ for the nine-month period ended September 30, ~~2017 as compared~~2023 primarily reflect the $12.0 million repurchase of our common stock under the 2023 Repurchase Program, the principal repayment of $8.3 million related to the ~~same period in 2016 primarily reflecting net proceeds of approximately $220~~MARAD Debt and $30.4 million ~~we received~~related to the 2023 Notes (Note 6). Net cash outflows from our underwritten public equity offering in January 2017 (Note 8) and the $100 million proceeds from our Term Loan borrowings in June 2017, offset in part by early repayment of the approximately $180 million term loan then outstanding under the credit agreement prior to its June 2017 amendment and restatement (Note 6) and net proceeds of approximately $95 million we received infinancing activities for the nine-month period ended September 30, ~~2016~~2022 primarily reflect the principal repayment of $7.9 million related to the MARAD Debt and $35 million related to the 2022 Notes.

Material Cash Requirements

Our material cash requirements include our obligations to repay our long-term debt, satisfy other contractual cash commitments and fund other obligations, including the payment of the Alliance earn-out consideration to the seller in the Alliance transaction.

Long-term debt and other contractual commitments

The following table summarizes the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment, operating lease obligations and contingent earn-out consideration, as of September 30, 2023 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated maturities (in thousands). Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory recertification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of September 30, 2023.

We acquired Helix Alliance in July 2022 for total consideration that included cash plus an earn-out to the extent Helix Alliance’s financial results exceed certain thresholds in 2022 and 2023 (Note 3). We reported $74.1 million of contingent earn-out consideration in “Accrued liabilities” in the accompanying condensed consolidated balance sheet as of September 30, 2023 (Note 4), which was the estimated fair value of the expected future earn-out payment. The earn-out is based on Helix Alliance’s financial performance through the end of 2023 and is expected to be paid in cash in the first half of 2024, and the final amount could change based on the ultimate financial performance of Helix Alliance.

Table of Contents

Our 2026 Notes have certain early redemption and conversion features that could affect the timing and amount of any cash requirements. On September 29, 2023, we announced that the 2026 Notes are convertible at the option of the holders from October 1, 2023 through December 31, 2023 as a result of the ~~sale~~closing price of our common stock ~~under at-the-market equity offering programs.~~

~~Table~~exceeding 130% of ~~Contents~~

~~Outlook~~

the conversion price for at least 20 days of the last 30 consecutive trading days in the quarter ended September 30, 2023. Should the closing share price conditions continue to be met in a future quarter for the 2026 Notes, the 2026 Notes will be convertible at their holders’ option during the immediately following quarter. We ~~anticipate that~~have the right to satisfy our ~~capital expenditures and deferred dry dock costs for 2017 will approximate $245 million. We believe that our~~conversion obligation by delivering cash, on hand, internally generated cash flows and availability under our Revolving Credit Facility will provide the capital necessary to continue funding our 2017 capital spending. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the levelshares of our ~~planned capital expenditures given a prolonged industry downturn.~~

~~Contractual Obligations and Commercial Commitments~~

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

common stock or any combination thereof (Note 6).


	Total		Short-Term		Long-Term
MARAD debt	$	32,580	$	8,749	$	23,831
2026 Notes		200,000		—		200,000
Interest related to debt		36,943		15,566		21,377
Property and equipment		10,504		10,504		—
Operating leases ⁽¹⁾		357,952		119,579		238,373
Earn-out consideration		74,073		74,073		—
Total cash obligations	$	712,052	$	228,471	$	483,581

Total ⁽¹⁾

Less Than
1 Year
1-3 Years 3-5 Years
More Than
5 Years

Term Loan $ 98,750
$ 6,250
$ 92,500
$ —
$ —
Nordea Q5000 Loan 169,643
35,714
133,929
—
—
MARAD Debt 77,000
6,532
14,058
15,497
40,913
2022 Notes ⁽²⁾
125,000
—
—
125,000
—
2032 Notes ⁽³⁾
60,115
60,115
—
—
—
Interest related to debt ⁽⁴⁾
78,706
23,411
35,804
14,614
4,877
Property and equipment ⁽⁵⁾
262,626
113,149
149,477
—
—
Operating leases ⁽⁶⁾
694,257
140,345
250,424
207,824
95,664
Total cash obligations $ 1,566,097
$ 385,516
$ 676,192
$ 362,935
$ 141,454


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

~~(2)~~

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

~~(3)~~

Notes mature March 2032. The 2032 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds 130% of their issuance price on that 30th trading day (i.e., $32.53 per share). At September 30, 2017, the conversion trigger was not met. The first date that the holders of these notes may require us to repurchase the notes is March 15, 2018. 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 for variable rate debt.~~


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

~~(6)~~

Operating leases include vessel charters and facility and equipment leases. At September 30, ~~2017,~~2023, our commitment related to long-term vessel ~~charter commitments~~charters totaled approximately ~~$652.3~~$341.6 million, ~~including~~of which $139.1 million was 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~~operating lease liabilities in the ~~fourth quarter~~condensed consolidated balance sheet as of ~~2017.~~

September 30, 2023.

~~Table~~

Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 13). Those obligations, which are presented on a discounted basis on the condensed consolidated balance sheets, approximate $45.0 million (undiscounted) for Thunder Hawk Field oil and gas properties and $33.5 million (undiscounted) for Droshky oil and gas properties as of ~~Contents~~

September 30, 2023, none of which is expected to be paid during the next 12 months. We are entitled to receive $30.0 million (undiscounted) from Marathon Oil as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Regulatory recertification and dry dock. Our Well Intervention vessels and systems are subject to certain regulatory recertification requirements that must be satisfied in order for the vessels and systems to operate. Recertification may require dry dock and other compliance costs on a periodic basis, usually every 30 months. Although the amount and timing of these costs may vary and are dependent on the timing of the certification renewal period, they generally range between $3.0 million to $15.0 million per vessel and $0.5 million to $5.0 million per system.

We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations and existing cash on hand, but may also come from availability under the Amended ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ~~POLICIES~~ESTIMATES AND ~~ESTIMATES~~

POLICIES

Our discussion and analysis of our financial condition and results of operations, ~~are based upon our~~as reflected in the condensed consolidated ~~financial statements. We prepare these~~ financial statements and related footnotes, are prepared in conformity with ~~accounting principles generally accepted in the United States.~~GAAP. As such, we are required to make certain estimates, judgments and assumptions that ~~affect the reported amounts~~have had or are reasonably likely to have a material impact on our financial condition or results of ~~assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented.~~operations. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates involve a significant level of estimation uncertainty and may change over time 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~~see our “Critical Accounting ~~Policies and~~ Estimates” as disclosed in our ~~2016~~2022 Form 10-K.

Table of Contents

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a multi-national organization, we are ~~currently exposed~~subject to market ~~risk in two areas:~~risks associated with foreign currency exchange rates, interest rates and ~~foreign currency exchange rates.~~

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

commodity prices.

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,~~U.S., we ~~generally~~endeavor to pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts are denominated, and provide for collections from our customers, in U.S. dollars. ~~During~~

Assets and liabilities of our subsidiaries that do not have the U.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, and changes in the exchange rates can result in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our condensed consolidated balance sheets. For the nine-month period ended September 30, ~~2017,~~2023, we recorded foreign currency translation gains of $4.1 million to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as the related undistributed earnings are permanently reinvested.

When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the condensed consolidated statements of operations as a component of “Other income (expense), net.” Foreign currency gains or losses from the remeasurement of ~~$2.2 million related to~~monetary assets and liabilities as well as unsettled foreign currency transactions, inincluding intercompany transactions that are not of a long-term investment nature, are also recognized as a component of “Other income (expense), ~~net”~~net.” For the three-month period ended September 30, 2023, we recorded net foreign currency losses of $8.3 million, primarily reflecting foreign currency losses related to U.S. dollar denominated intercompany debt 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 foreign currency exchange contracts to hedge our foreign currency exposure with respect to the ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. In December 2015, we re-designated the hedging relationship between a portion of our foreign currency exchange contracts and our forecasted ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring (Note 14). The foreign currency exchange contracts associated with the ~~Grand Canyon~~ ~~charter payments and the re-designated contracts associated with the~~ ~~Grand Canyon II~~ ~~and~~ ~~Grand Canyon III~~ ~~charter payments currently qualify for cash flow hedge accounting treatment. There was no foreign currency hedge ineffectiveness for~~U.K. entities. For the nine-month period ended September 30, ~~2017.~~

2023, we recorded net foreign currency losses of $10.6 million, primarily reflecting foreign currency losses of $12.8 million related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains related to U.S. dollar denominated intercompany debt in our U.K. entities.

Interest Rate Risk. In order to maintain a cost-effective capital structure, we borrow funds using a mix of fixed and variable rate debt. For variable rate debt, changes in interest rates could affect our future interest expense and cash flows. Alternatively for fixed rate debt, changes in interest rates may not affect our interest expense, but could result in changes in the fair value of the debt instrument prior to maturity. We currently have no exposure to interest rate risks as we have no outstanding debt subject to floating rates. However, we are subject to risks upon refinancing our debt.

Commodity Price Risk. We are exposed to market price risks related to oil and natural gas with respect to offshore oil and gas production in our Production Facilities business. Prices are volatile and unpredictable and are dependent on many factors beyond our control. See Item 1A.Risk Factors in our 2022 Form 10-K for a list of factors affecting oil and gas prices.

~~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.~~2023. 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~~2023 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~~three-month period ended September 30, ~~2017~~2023 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 12 — Litigation to the Condensed Consolidated Financial Statements, which is incorporated herein by reference.

Item 1A. Risk Factors

There have been no material changes during the period ended September 30, 2023 in our “Risk Factors” as discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2022.

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

Issuer Purchases of Equity Securities


				(c)	(d)
				Total number	Approximate dollar
				of shares	value of shares
	(a)	(b)		purchased as	that may yet be
	Total number	Average		part of publicly	purchased under the
	of shares	price paid		announced plans	plans or programs ⁽³⁾
Period	purchased ⁽¹⁾	per share		or programs ⁽²⁾	(in thousands)
July 1 to July 31, 2023	—	$	—	—	$	189,941
August 1 to August 31, 2023	—		—	—		189,941
September 1 to September 30, 2023	176,172		11.08	174,045		188,012
	176,172	$	11.08	174,045

~~Period~~

~~(a)~~

~~Total number~~

~~of shares~~

~~purchased~~

~~(b)~~

~~Average~~

~~price paid~~

~~per share~~

~~(c)~~

~~Total number~~

~~of shares~~

~~purchased as~~

~~part of publicly~~

~~announced~~

~~program~~

~~(d)~~

~~Maximum~~

~~number of shares~~

~~that may yet be~~

~~purchased under~~

~~the program~~ ⁽¹⁾

~~July 1 to July 31, 2017~~

—

~~3,079,889~~

~~August 1 to August 31, 2017~~

—

~~3,079,889~~

~~September 1 to September 30, 2017~~

—

~~3,108,697~~

—


(1)	~~Under~~Includes shares repurchased in open-market transactions pursuant to the ~~terms~~2023 Repurchase Program as described in footnote (3) below and shares forfeited in satisfaction of tax obligations upon vesting of share-based awards under our existing long-term incentive plans.

(2)	Represents shares repurchased under the 2023 Repurchase Program.

(3)

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our ~~stock~~common stock. The 2023 Repurchase Program has no set expiration date. Concurrent with the authorization of the 2023 Repurchase Program, our Board revoked the prior authorization to repurchase ~~program, the issuance of~~ shares ~~to members~~ of our ~~Board~~common stock in an amount equal to any equity granted to our employees, officers and directors under our share-based compensation plans. See Note 8 to ~~certain employees, including shares issued under the ESPP~~this Quarterly Report on Form 10-Q and Note 10 to ~~participating employees (Note 10), increases the amount of shares available~~our 2022 Annual Report on Form 10-K for ~~repurchase. For~~ additional information regarding our ~~stock~~share repurchase ~~program, see Note 10 to our 2016 Form 10-K.~~programs.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

(c) During the three-month period ended September 30, 2023, no director or “officer” of Helix adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.

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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, as amended, 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., as amended.	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	Inline XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
~~101.PRE~~ 101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.	Filed herewith
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith
~~101.DEF~~ 104	Cover Page Interactive Data File (formatted as inline XBRL ~~Definition Linkbase Document.~~and contained in Exhibit 101).	Filed herewith
~~101.LAB~~	~~XBRL Label Linkbase Document.~~	~~Filed herewith~~

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SIGNATURES

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



				HELIX ENERGY SOLUTIONS GROUP, INC. ~~(Registrant)~~
~~Date:~~			(Registrant)

Date: October ~~24, 2017~~25, 2023		By:	/s/ Owen Kratz
				Owen Kratz
			President and Chief Executive Officer
			(Principal Executive Officer)

Date: October 25, 2023	~~October 24, 2017~~	By:	~~By:~~	/s/ Erik Staffeldt
				Erik Staffeldt ~~Senior~~
			Executive Vice President and
			Chief Financial Officer
			(Principal Financial Officer)



	September 30, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents	$	356,889		$	356,647
Accounts receivable:
Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively	90,480			101,825
Unbilled revenue and other	45,816			10,328
Current deferred tax assets	—			16,594
Other current assets	38,172			37,388
Total current assets	531,357			522,782
Property and equipment	2,612,407			2,450,890
Less accumulated depreciation	(878,248		)	(799,280		)
Property and equipment, net	1,734,159			1,651,610
Other assets, net	100,974			72,549
Total assets	$	2,366,490		$	2,246,941

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	91,412		$	60,210
Accrued liabilities	60,761			58,614
Income tax payable	1,756			—
Current maturities of long-term debt	108,611			67,571
Total current liabilities	262,540			186,395
Long-term debt	395,345			558,396
Deferred tax liabilities	154,158			167,351
Other non-current liabilities	42,736			52,985
Total liabilities	854,779			965,127
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 147,713 and 120,630 shares issued, respectively	1,281,747			1,055,934
Retained earnings	302,326			322,854
Accumulated other comprehensive loss	(72,362		)	(96,974		)
Total shareholders’ equity	1,511,711			1,281,814
Total liabilities and shareholders’ equity	$	2,366,490		$	2,246,941



	Three Months Ended September 30,
	2017			2016

Net revenues	$	163,260		$	161,245
Cost of sales	142,119			121,061
Gross profit	21,141			40,184
Selling, general and administrative expenses	(16,374		)	(18,714		)
Income from operations	4,767			21,470
Equity in losses of investment	(153		)	(122		)
Net interest expense	(3,615		)	(6,843		)
Gain on early extinguishment of long-term debt	—			244
Other income (expense), net	(551		)	830
Other income (expense) – oil and gas	303			(468		)
Income before income taxes	751			15,111
Income tax provision (benefit)	(1,539		)	3,649
Net income	$	2,290		$	11,462

Earnings per share of common stock:
Basic	$	0.02		$	0.10
Diluted	$	0.02		$	0.10

Weighted average common shares outstanding:
Basic	145,958			113,680
Diluted	145,958			113,680



	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



	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



	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



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

Less than one year	$	6,250		$	—		$	60,115		$	6,532		$	35,714		$	108,611
One to two years	11,250			—			—			6,858			35,714			53,822
Two to three years	81,250			—			—			7,200			98,215			186,665
Three to four years	—			—			—			7,560			—			7,560
Four to five years	—			125,000			—			7,937			—			132,937
Over five years	—			—			—			40,913			—			40,913
Total debt	98,750			125,000			60,115			77,000			169,643			530,508
Current maturities	(6,250		)	—			(60,115		)	(6,532		)	(35,714		)	(108,611		)
Long-term debt, less current 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		)
Long-term debt	$	90,685		$	108,018		$	(1,144	)	$	65,833		$	131,953		$	395,345



	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	)



	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



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

Liabilities:
Foreign exchange contracts	—		19,508		—		19,508		(c)
Interest rate swaps	—		82		—		82		(c)
Total liability	$	—	$	19,216	$	—	$	19,216



	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



	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



	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



	Three Months Ended September 30,						Increase/ (Decrease)
	2017			2016			Increase/ (Decrease)
Net revenues —
Well Intervention	$	111,522		$	108,287		$	3,235
Robotics	47,049			48,897			(1,848		)
Production Facilities	16,380			17,128			(748		)
Intercompany elimination	(11,691		)	(13,067		)	1,376
	$	163,260		$	161,245		$	2,015

Gross profit (loss) —
Well Intervention	$	20,642		$	28,174		$	(7,532	)
Robotics	(6,991		)	4,953			(11,944		)
Production Facilities	7,780			8,413			(633		)
Corporate and other	(489		)	(483		)	(6		)
Intercompany elimination	199			(873		)	1,072
	$	21,141		$	40,184		$	(19,043	)

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

Number of vessels or robotics assets ⁽¹⁾ / Utilization ⁽²⁾
Well Intervention vessels	5/88%			5/76%
Robotics assets	60/46%			60/57%
Chartered robotics vessels	5/80%			3/81%



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

Term Loan	$	98,750	$	6,250	$	92,500	$	—	$	—
Nordea Q5000 Loan	169,643		35,714		133,929		—		—
MARAD Debt	77,000		6,532		14,058		15,497		40,913
2022 Notes ⁽²⁾	125,000		—		—		125,000		—
2032 Notes ⁽³⁾	60,115		60,115		—		—		—
Interest related to debt ⁽⁴⁾	78,706		23,411		35,804		14,614		4,877
Property and equipment ⁽⁵⁾	262,626		113,149		149,477		—		—
Operating leases ⁽⁶⁾	694,257		140,345		250,424		207,824		95,664
Total cash obligations	$	1,566,097	$	385,516	$	676,192	$	362,935	$	141,454

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