10-Q - HLX - Equibles

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

Form 10-Q ****


☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2025


☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from__________ to__________

Commission File Number: 001-32936

HELIX ENERGY SOLUTIONS GROUP, INC.

(Exact name of registrant as specified in its charter)


Minnesota		95-3409686
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
3505 West Sam Houston Parkway North
Suite 400
Houston ** Texas**		77043
(Address of principal executive offices)		(Zip Code)

( 281 ) 618–0400

(Registrant’s telephone number, including area code)

NOT APPLICABLE

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

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


Title of each class		Trading Symbol(s)		Name of each exchange on which registered
Common Stock, 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. ☑ Yes ☐ No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No

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


Large accelerated filer ☑	Accelerated filer ☐	Non-accelerated filer ☐	Smaller reporting company ☐	Emerging growth company ☐

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

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

As of April 21, 2025, 151,530,339 shares of common stock were outstanding.

Table of Contents TABLE OF CONTENTS


PART I.	FINANCIAL INFORMATION	PAGE

Item 1.	Financial Statements:	3
	Condensed Consolidated Balance Sheets – March 31, 2025 (Unaudited) and December 31, 2024	3

	Condensed Consolidated Statements of Operations (Unaudited) – Three months ended March 31, 2025 and 2024	4

	Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) – Three months ended March 31, 2025 and 2024	4

	Condensed Consolidated Statements of Shareholders’ Equity (Unaudited) – Three months ended March 31, 2025 and 2024	5

	Condensed Consolidated Statements of Cash Flows (Unaudited) – Three months ended March 31, 2025 and 2024	6

	Notes to Condensed Consolidated Financial Statements (Unaudited)	7

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	22

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	33

Item 4.	Controls and Procedures	34

PART II.	OTHER INFORMATION	34

Item 1.	Legal Proceedings	34

Item 1A.	Risk Factors	34

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	34

Item 3.	Defaults Upon Senior Securities	34

Item 4.	Mine Safety Disclosures	34

Item 5.	Other Information	35

Item 6.	Exhibits	35

	Signatures	36

Table of Contents PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands)


		March 31,			December 31,
	****	2025		****	2024
ASSETS
Current assets:
Cash and cash equivalents		$	369,987		$	368,030
Accounts receivable, net of allowance for credit losses of $3,597 and $3,682, respectively			258,485			258,630
Other current assets			107,735			83,022
Total current assets			736,207			709,682
Property and equipment			3,113,515			3,068,755
Less accumulated depreciation			(1,679,150)			(1,630,902)
Property and equipment, net			1,434,365			1,437,853
Operating lease right-of-use assets			327,732			329,649
Deferred recertification and dry dock costs, net			89,115			71,718
Other assets, net			47,604			48,178
Total assets		$	2,635,023		$	2,597,080

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable		$	159,835		$	144,793
Accrued liabilities			90,606			90,455
Current maturities of long-term debt			9,412			9,186
Current operating lease liabilities			63,542			59,982
Total current liabilities			323,395			304,416
Long-term debt			301,697			305,971
Operating lease liabilities			281,146			285,984
Deferred tax liabilities			113,416			113,973
Other non-current liabilities			70,104			66,971
Total liabilities			1,089,758			1,077,315
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 151,530 and 150,243 shares issued, respectively			1,247,496			1,252,253
Retained earnings			371,159			368,087
Accumulated other comprehensive loss			(73,390)			(100,575)
Total shareholders’ equity			1,545,265			1,519,765
Total liabilities and shareholders’ equity		$	2,635,023		$	2,597,080

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
		March 31,
	****	2025		****	2024
Net revenues		$	278,064		$	296,211
Cost of sales			250,526			276,657
Gross profit			27,538			19,554
Loss on disposition of assets, net			—			(150)
Selling, general and administrative expenses			(19,366)			(20,680)
Income (loss) from operations			8,172			(1,276)
Net interest expense			(5,706)			(5,477)
Losses related to convertible senior notes			—			(20,922)
Other expense, net			(357)			(2,216)
Royalty income and other			1,416			1,906
Income (loss) before income taxes			3,525			(27,985)
Income tax provision (benefit)			453			(1,698)
Net income (loss)		$	3,072		$	(26,287)

Earnings (loss) per share of common stock:
Basic		$	0.02		$	(0.17)
Diluted		$	0.02		$	(0.17)

Weighted average common shares outstanding:
Basic			151,039			152,369
Diluted			152,174			152,369

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

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(UNAUDITED)

(in thousands)


	Three Months Ended
	March 31,
	2025		****	2024
Net income (loss)	$	3,072		$	(26,287)
Other comprehensive income (loss) - foreign currency translation gain (loss), net of tax		27,185			(6,683)
Comprehensive income (loss)	$	30,257		$	(32,970)

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

Table of Contents HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(UNAUDITED)

(in thousands)


										Accumulated
										Other			Total
		Common Stock					Retained			Comprehensive			Shareholders’
	****	Shares	****	Amount		****	Earnings		****	Loss		****	Equity
Balance, December 31, 2024		150,243		$	1,252,253		$	368,087		$	(100,575)		$	1,519,765
Net income		—			—			3,072			—			3,072
Foreign currency translation adjustments		—			—			—			27,185			27,185
Activity in company stock plans, net and other		1,287			(6,279)			—			—			(6,279)
Share-based compensation		—			1,522			—			—			1,522
Balance, March 31, 2025		151,530		$	1,247,496		$	371,159		$	(73,390)		$	1,545,265

Balance, December 31, 2023		152,291		$	1,271,565		$	312,450		$	(83,015)		$	1,501,000
Net loss		—			—			(26,287)			—			(26,287)
Foreign currency translation adjustments		—			—			—			(6,683)			(6,683)
Settlement of convertible debt conversion		—			(84)			—			—			(84)
Repurchases of common stock		(463)			(5,032)			—			—			(5,032)
Termination of capped calls		—			4,381			—			—			4,381
Activity in company stock plans, net and other		622			(2,071)			—			—			(2,071)
Share-based compensation		—			1,598			—			—			1,598
Balance, March 31, 2024		152,450		$	1,270,357		$	286,163		$	(89,698)		$	1,466,822

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)


		Three Months Ended
		March 31,
	****	2025		****	2024
Cash flows from operating activities:
Net income (loss)		$	3,072		$	(26,287)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization, excluding amortization of deferred recertification and dry dock costs			33,248			36,656
Amortization of deferred recertification and dry dock costs			9,234			9,697
Deferred recertification and dry dock costs			(17,855)			(9,594)
Amortization of debt discount			57			53
Amortization of debt issuance costs			502			570
Share-based compensation			1,651			1,711
Deferred income taxes			(400)			(574)
Loss on disposition of assets, net			—			150
Losses related to convertible senior notes			—			20,922
Unrealized foreign currency (gain) loss			(572)			2,117
Changes in operating assets and liabilities:
Accounts receivable, net			(1,116)			59,059
Other current assets			(16,835)			23,196
Income tax receivable, net of income tax payable			(2,702)			(2,510)
Accounts payable and accrued liabilities			4,518			(50,489)
Other, net			3,640			(193)
Net cash provided by operating activities			16,442			64,484

Cash flows from investing activities:
Capital expenditures			(4,488)			(3,605)
Proceeds from insurance recoveries			—			363
Net cash used in investing activities			(4,488)			(3,242)

Cash flows from financing activities:
Payments related to convertible senior notes			—			(60,699)
Repayment of MARAD Debt			(4,537)			(4,322)
Proceeds from settlement of capped calls			—			4,381
Debt issuance costs			—			(984)
Repurchases of common stock			—			(4,177)
Payments related to tax withholding for share-based compensation			(7,266)			(4,003)
Proceeds from issuance of ESPP shares			728			500
Net cash used in financing activities			(11,075)			(69,304)

Effect of exchange rate changes on cash and cash equivalents			1,078			(280)
Net increase (decrease) in cash and cash equivalents			1,957			(8,342)
Cash and cash equivalents:
Balance, beginning of year			368,030			332,191
Balance, end of period		$	369,987		$	323,849

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

Table of Contents 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”). 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 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 accounting principles generally accepted in the U.S. (“GAAP”).

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, unless otherwise disclosed, are of normal recurring nature, that we believe are necessary for a fair presentation of the condensed consolidated balance sheets, statements of operations, statements of comprehensive loss, statements of shareholders’ equity and statements of cash flows, as applicable. The operating results for the three-month period ended March 31, 2025 are not necessarily indicative of the results that may be expected for the year ending December 31, 2025. Our balance sheet as of December 31, 2024 included herein has been derived from the audited balance sheet as of December 31, 2024 included in our 2024 Annual Report on Form 10-K (our “2024 Form 10-K”). These unaudited condensed consolidated financial statements should be read in conjunction with the audited annual consolidated financial statements and notes thereto included in our 2024 Form 10-K.

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

New accounting standards

In November 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2023-07, “Improvements to Reportable Segment Disclosures,” which requires entities to disclose, on an annual and interim basis, significant segment expenses that are regularly provided to the chief operating decision maker (the “CODM”) and included within each reported measure of segment profit or loss as well as an amount for other segment items by reportable segment and a description of its composition. ASU No. 2023-07 requires all annual disclosures about a reportable segment’s profit or loss and assets to be provided in interim periods as well. Among other things, this ASU also requires that a public entity disclose the title and position of the CODM and an explanation of how the CODM uses the reported measure(s) of segment profit or loss in assessing segment performance and deciding how to allocate resources. We adopted ASU No. 2023-07 on a retrospective basis starting with our 2024 Form 10-K. The adoption of this ASU increased segment disclosures, which are reflected in Note 11, but otherwise had no impact on our earnings, cash flows or financial condition.

In December 2023, the FASB issued ASU No. 2023-09, “Improvements to Income Tax Disclosures,” which requires entities to disclose, on an annual basis, specific categories in a tabular rate reconciliation using both percentages and reporting currency amounts and to provide additional information for reconciling items that meet a quantitative threshold. This ASU also requires that entities disclose on an annual basis: a) income taxes paid (net) disaggregated by federal, state and foreign taxes; b) income taxes paid (net) by individual jurisdiction; c) income (or loss) from continuing operations before income tax expense (or benefit) between domestic and foreign; and d) income tax expense (or benefit) from continuing operations by federal, state and foreign. Certain previous disclosure requirements on unrecognized tax benefits and cumulative amount of temporary differences are eliminated. ASU No. 2023-09 will be effective for us for annual periods beginning January 1, 2025. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements. 7

Table of Contents In November 2024, the FASB issued ASU No. 2024-03, “Disaggregation of Income Statement Expenses,” which requires entities to disclose, on an annual and interim basis, specified information about certain costs and expenses: a) the amounts of (i) purchases of inventory, (ii) employee compensation, (iii) depreciation, (iv) intangible asset amortization, and (v) depreciation, depletion, and amortization recognized as part of oil and gas-producing activities (or other amounts of depletion expense) included in each relevant expense caption; b) certain amounts that are already required to be disclosed under current GAAP in the same disclosure as the other disaggregation requirements; c) a qualitative description of the amounts remaining in relevant expense captions that are not separately disaggregated quantitatively; and d) the total amount of selling expenses and, in annual periods, an entity’s definition of selling expenses. ASU No. 2024-03 will be effective for us for annual periods beginning January 1, 2027 and for interim periods beginning January 1, 2028. This ASU is not expected to have a material impact on our consolidated financial statements other than increased disclosure requirements.

We do not expect other recently issued accounting standards to have a material impact on our financial position, results of operations or cash flows when they become effective.

Note 2 — Company Overview

●	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
---	---
●	Renewables — we are an established global leader in jet trenching and provide specialty support services to renewable energy developments such as offshore wind farms, including boulder removal and unexploded ordnance clearance.
---	---

We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of America (deepwater and shelf), U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations and our Gulf of America shelf operations are usually subject to seasonal changes in activity levels, which generally peaks in the summer months and declines in the winter months. Our services are segregated into four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities.

Our Well Intervention segment provides services enabling our customers to safely access subsea offshore wells for the purpose of performing production enhancement or decommissioning operations, thereby mitigating the need to drill new wells by extending the useful lives of existing wells and preserving the environment by preventing uncontrolled releases of oil and natural gas. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and two chartered vessels, the Siem Helix 1 and the Siem Helix 2. Our well intervention equipment includes intervention systems such as intervention riser systems (“IRSs”), 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 renewable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, IROV boulder grabs and robotics support vessels under term charters as well as spot vessels as needed. We offer our ROVs, trenchers and IROV boulder grabs on a stand-alone basis or on an integrated basis with chartered robotics support vessels. 8

Table of Contents Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of America shelf, including offshore oilfield decommissioning and ‎reclamation, well intervention, IRM, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022, a vertically integrated company which offers 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 (“CT”) systems.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, the Helix Fast Response System (the “HFRS”), which combines our capabilities with certain well control equipment that can be deployed to respond to a well control incident, and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the Gulf of America.

Note 3 — Details of Certain Accounts

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


		March 31,			December 31,
	****	2025		****	2024
Prepaids		$	24,333		$	26,780
Income tax receivable			9,441			2,635
Contract assets (Note 8)			25,974			12,221
Deferred costs (Note 8)			38,823			31,874
Other			9,164			9,512
Total other current assets		$	107,735		$	83,022

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


		March 31,			December 31,
	****	2025		****	2024
Prepaid charter ^(1)^		$	12,544		$	12,544
Deferred costs (Note 8)			4,358			5,348
Other receivable ^(2)^			25,422			24,827
Intangible assets with finite lives, net			3,555			3,630
Other			1,725			1,829
Total other assets, net		$	47,604		$	48,178
(1)	Represents prepayments to the owner of the Siem Helix 1 and the Siem Helix 2 to offset certain payment obligations associated with the vessels at the end of their respective charter term.
---	---
(2)	Represents the present value of receivables for P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil Corporation in 2019.
---	---

Accrued liabilities consist of the following (in thousands):


		March 31,			December 31,
	****	2025		****	2024
Accrued payroll and related benefits		$	30,101		$	49,521
Accrued interest			2,634			10,278
Deferred revenue (Note 8)			37,756			14,914
Other			20,115			15,742
Total accrued liabilities		$	90,606		$	90,455

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


		March 31,			December 31,
	****	2025		****	2024
Deferred revenue (Note 8)		$	2,471		$	699
Asset retirement obligations (Note 12)			64,355			62,947
Other			3,278			3,325
Total other non-current liabilities		$	70,104		$	66,971

Note 4 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2034.

The following table details the components of our lease cost (in thousands):


		Three Months Ended
		March 31,
	****	2025		****	2024
Operating lease cost		$	21,230		$	20,475
Variable lease cost			2,346			3,057
Short-term lease cost			8,943			8,914
Sublease income			(29)			(22)
Net lease cost		$	32,490		$	32,424

Maturities of our operating lease liabilities as of March 31, 2025 are as follows (in thousands):


	****			****	Facilities and		****
	****	Vessels		****	Equipment		****	Total
Less than one year		$	81,873		$	4,883		$	86,756
One to two years			68,327			3,295			71,622
Two to three years			65,904			4,415			70,319
Three to four years			53,539			2,963			56,502
Four to five years			52,748			3,761			56,509
Over five years			73,250			14,968			88,218
Total lease payments		$	395,641		$	34,285		$	429,926
Less: imputed interest			(75,728)			(9,510)			(85,238)
Total operating lease liabilities		$	319,913		$	24,775		$	344,688

Current operating lease liabilities		$	59,516		$	4,026		$	63,542
Non-current operating lease liabilities			260,397			20,749			281,146
Total operating lease liabilities		$	319,913		$	24,775		$	344,688

Table of Contents Maturities of our operating lease liabilities as of December 31, 2024 are as follows (in thousands):


	****			****	Facilities and		****
	****	Vessels		****	Equipment		****	Total
Less than one year		$	78,442		$	5,324		$	83,766
One to two years			66,020			3,442			69,462
Two to three years			61,771			3,871			65,642
Three to four years			55,933			3,368			59,301
Four to five years			52,748			3,185			55,933
Over five years			86,257			15,736			101,993
Total lease payments		$	401,171		$	34,926		$	436,097
Less: imputed interest			(80,564)			(9,567)			(90,131)
Total operating lease liabilities		$	320,607		$	25,359		$	345,966

Current operating lease liabilities		$	55,643		$	4,339		$	59,982
Non-current operating lease liabilities			264,964			21,020			285,984
Total operating lease liabilities		$	320,607		$	25,359		$	345,966

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


		March 31,		December 31,
	****	2025		2024
Weighted average remaining lease term		5.7	years	5.9	years
Weighted average discount rate		7.86	%	7.89	%

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


		Three Months Ended
		March 31,
	****	2025		****	2024
Cash paid for operating lease liabilities		$	20,428		$	18,720
Right-of-use assets related to new operating lease liabilities ^(1)^			12,073			203,040
(1)	Our operating lease additions are primarily related to the charter for the Trym during the three-month period ended March 31, 2025, and the charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon during the three-month period ended March 31, 2024 (Note 13).
---	---

Note 5 — Long-Term Debt

Scheduled maturities of our long-term debt outstanding as of March 31, 2025 are as follows (in thousands):


		MARAD			2029
	****	Debt		****	Notes		****	Total
Less than one year		$	9,412		$	—		$	9,412
One to two years			9,882			—			9,882
Two to three years			—			—			—
Three to four years			—			300,000			300,000
Gross debt			19,294			300,000			319,294
Unamortized debt discount ^(1)^			—			(1,129)			(1,129)
Unamortized debt issuance costs ^(1)^			(976)			(6,080)			(7,056)
Total debt			18,318			292,791			311,109
Less current maturities			(9,412)			—			(9,412)
Long-term debt		$	8,906		$	292,791		$	301,697
(1)	Debt discount and debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.
---	---

Table of Contents Below is a summary of our indebtedness:

Credit Agreement

On September 30, 2021 we entered into an asset-based credit agreement with Bank of America, N.A. (“Bank of America”), Wells Fargo Bank, N.A. and Zions Bancorporation and subsequently we entered into various amendments (collectively, the “Amended ABL Facility”). The most recent amendment on August 2, 2024 extended the maturity of the Amended ABL Facility and increased the letter of credit basket size. The Amended ABL Facility provides a $120 million asset-based revolving credit facility, which matures on August 2, 2029, 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 $30 million, 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 Amended ABL Facility 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 $55 million sub-limit for the issuance of letters of credit. As of March 31, 2025, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $62.7 million, net of $31.8 million of letters of credit issued.

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.

U.S. borrowings under the Amended ABL Facility bear interest at the Term SOFR rate (also known as CME Term SOFR as administered by CME Group, Inc.) plus a margin of 1.50% to 2.00% or at a base rate plus a margin of 0.50% to 1.00%. U.K. borrowings under the Amended ABL Facility denominated in U.S. dollars bear interest at the Term SOFR rate with SOFR adjustment of 0.10% and U.K. borrowings denominated in the British pound bear interest at the SONIA daily rate, each plus a margin of 1.50% to 2.00%. We also pay a commitment fee of 0.375% to 0.50% per annum on the unused portion of the facility.

The Amended ABL Facility includes certain limitations on our ability to incur additional indebtedness, grant liens on assets, pay dividends and make 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 satisfy and maintain a fixed charge coverage ratio of not less than 1.0 to 1.0 if availability is less than the greater of 10% of the borrowing base or $12 million.

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 ESG-related pricing adjustments based on specific metrics and performance targets determined by us and Bank of America, as agent with respect to the Amended ABL Facility.

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 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 (“MARAD”). The obligation of CDI-Title XI to reimburse MARAD in the event CDI-Title XI fails to repay 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 through February 2027 and bears interest at a rate of 4.93%. 12

Table of Contents Senior Notes Due 2029 (“2029 Notes”)

On December 1, 2023, we issued $300 million aggregate principal amount of the 2029 Notes. The net proceeds from the issuance of the 2029 Notes were approximately $291.1 million, after deducting the purchasers’ discount and debt issuance costs. We used cash proceeds from the offering to redeem our former Convertible Senior Notes due 2026 (the “2026 Notes”). See details regarding the redemption of the 2026 Notes below.

The 2029 Notes bear interest at a coupon interest rate of 9.75% per annum payable semi-annually in arrears on March 1 and September 1 of each year, beginning on March 1, 2024. The 2029 Notes mature on March 1, 2029 unless earlier redeemed or repurchased by us.

Prior to March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at a price equal to 100% of the aggregate principal amount of the notes to be redeemed, plus a make-whole premium and accrued and unpaid interest, if any, to, but excluding, the redemption date. On or after March 1, 2026, we may, at our option, redeem the 2029 Notes, in whole or in part, at the redemption prices (expressed as percentages of the principal amount of the notes to be redeemed) set forth below, plus accrued and unpaid interest, if any, to, but excluding, the redemption date. Prior to March 1, 2026, following certain equity offerings we may, at our option, on any one or more occasions, redeem up to 40% of the 2029 Notes at a price equal to 109.750% of the aggregate principal amount of the notes to be redeemed, plus accrued and unpaid interest, if any, to, but excluding, the redemption date, in an amount not exceeding the proceeds of such equity offerings.


		Redemption
Year	****	Price
2026		104.875%
2027		102.438%
2028 and thereafter		100.000%

Upon the occurrence of a Change of Control Triggering Event, as defined in the indenture governing the 2029 Notes, we may be required to make an offer to repurchase all of the notes then outstanding at a price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to, but not including, the repurchase date.

The indenture governing the 2029 Notes contains customary terms and covenants, including limitations on additional indebtedness, restricted payments, liens, asset sales, transactions with affiliates, mergers and consolidations, designation of unrestricted subsidiaries, and dividend and other restrictions affecting restricted subsidiaries.

The 2029 Notes are guaranteed on a senior unsecured basis by the subsidiaries that guarantee the Amended ABL Facility, as well as certain future subsidiaries that may guarantee certain of our indebtedness, including the Amended ABL Facility. The 2029 Notes are junior in right of payment to all our existing and future secured indebtedness and obligations and rank equally in right of payment with all our existing and future senior unsecured indebtedness. The 2029 Notes rank senior in right of payment to any of our future subordinated indebtedness and are fully and unconditionally guaranteed by the guarantors described above on a senior basis.

2026 Notes Redemption

In January 2024, we issued a notice for the redemption of the remaining $40.0 million aggregate principal amount of the 2026 Notes to be settled in March 2024 (the “2026 Notes Redemptions”). The redemption price consisted of the principal amount and the make-whole premium, plus accrued and unpaid interest. Our redemption notice enabled holders of $39.7 million aggregate principal amount of the 2026 Notes to tender their notes for conversion prior to the redemption date, with the remaining $0.3 million aggregate principal amount of the notes redeemed. We settled both the conversions and redemptions for an aggregate $60.2 million cash in March 2024 and recognized pre-tax losses of $20.9 million. These losses are reflected in “Losses related to convertible senior notes” in the accompanying condensed consolidated statement of operations. The 2026 Notes had a coupon interest rate of 6.75% per annum and an effective interest rate of 7.6%. For the three-month period ended March 31, 2024, total interest expense related to the 2026 Notes was $0.4 million with coupon interest expense of $0.3 million and the amortization of debt issuance costs of $0.1 million. 13

Table of Contents In connection with the 2026 Notes offering, we had entered into capped call transactions (the “2026 Capped Calls”) with three separate counterparties to hedge the dilution risk of the 2026 Notes. Concurrent with the settlement of the 2026 Notes Redemptions in March 2024, we terminated the remaining 2026 Capped Calls and received $4.4 million in cash, recognizing an increase to “Common stock” in the shareholders’ equity section of the accompanying condensed consolidated balance sheets.

Other

In accordance with the Amended ABL Facility, the MARAD Debt and the 2029 Notes, we are required to comply with certain covenants, including minimum liquidity and a springing fixed charge coverage ratio (applicable under certain conditions that are currently not applicable) with respect to the Amended ABL Facility and the maintenance of net worth, working capital and debt-to-equity requirements with respect to the MARAD Debt. As of March 31, 2025, we were in compliance with these covenants.

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


		March 31,
	****	2025		****	2024
Interest expense		$	8,239		$	8,778
Interest income			(2,533)			(3,301)
Net interest expense		$	5,706		$	5,477

Note 6 — Income Taxes

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

For the three-month periods ended March 31, 2025 and 2024, we recognized income tax provision (benefit) of $0.5 million and $(1.7) million, respectively, resulting in effective tax rates of 12.9% and 6.1%, respectively. The effective tax rate for the three-month period ended March 31, 2025 was impacted by a discrete non-U.S. tax benefit. The effective rate for the three-month period ended March 31, 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

Note 7 — Share Repurchase Programs

In February 2023, our Board of Directors (our “Board”) authorized a share repurchase program to repurchase issued and outstanding shares of our common stock up to $200 million (the “2023 Repurchase Program”). As of March 31, 2025, approximately $158.4 million remain authorized for repurchase under the 2023 Repurchase Program.

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 at its discretion 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. Any repurchased shares are cancelled.

Table of Contents Note 8 — Revenue from Contracts with Customers

Disaggregation of Revenue

Our service contracts generally contain provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) but we occasionally contract on a lump sum basis (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities.

Our revenues are primarily derived from short-term and long-term service contracts with customers. 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. We provide services to our customers in the following markets that are key to our energy transition strategy: Production maximization, Decommissioning and Renewables. The following tables provide information about disaggregated revenue by contract duration and by market strategy (in thousands):


		Well						Shallow Water			Production			Intercompany			Total
	****	Intervention		****	Robotics		****	Abandonment		****	Facilities		****	Eliminations		****	Revenue
Three months ended March 31, 2025
Short-term		$	24,223		$	22,550		$	15,571		$	—		$	(52)		$	62,292
Long-term			174,151			28,492			1,247			19,837			(7,955)			215,772
Total		$	198,374		$	51,042		$	16,818		$	19,837		$	(8,007)		$	278,064

Three months ended March 31, 2024 ^(1)^
Short-term		$	134,414		$	25,176		$	25,363		$	—		$	(6,327)		$	178,626
Long-term			76,886			25,133			1,490			24,152			(10,076)			117,585
Total		$	211,300		$	50,309		$	26,853		$	24,152		$	(16,403)		$	296,211


		Well						Shallow Water			Production			Intercompany			Total
	****	Intervention		****	Robotics		****	Abandonment		****	Facilities		****	Eliminations		****	Revenue
Three months ended March 31, 2025
Production maximization		$	96,962		$	24,726		$	1,076		$	19,837		$	(3,972)		$	138,629
Decommissioning			100,683			4,016			15,666			—			(4,035)			116,330
Renewables			—			16,774			76			—			—			16,850
Other			729			5,526			—			—			—			6,255
Total		$	198,374		$	51,042		$	16,818		$	19,837		$	(8,007)		$	278,064

Three months ended March 31, 2024 ^(1)^
Production maximization		$	69,935		$	18,436		$	3,242		$	24,152		$	(10,878)		$	104,887
Decommissioning			141,278			5,412			23,611			—			(5,521)			164,780
Renewables			—			24,172			—			—			—			24,172
Other			87			2,289			—			—			(4)			2,372
Total		$	211,300		$	50,309		$	26,853		$	24,152		$	(16,403)		$	296,211
(1)	For the three-month period ended March 31, 2024, $5.2 million have been removed from Well Intervention segment revenues and related intersegment eliminations. See Note 11 regarding this change in prior year reported segment information.
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Contract Balances

Net contract assets were $26.0 million as of March 31, 2025 and $12.2 million as of December 31, 2024 and are reflected in “Other current assets” in the accompanying condensed consolidated balance sheets (Note 3). The increase in net contract assets was primarily attributable to more revenue recognized for demobilization fees and more revenue recognized in excess of the amount billed to the customer for lump sum contracts. We had no credit losses on our contract assets for the three-month periods ended March 31, 2025 and 2024. 15

Table of Contents Net contract liabilities totaled $40.2 million as of March 31, 2025 and $15.6 million as of December 31, 2024 and are reflected as “Deferred revenue,” a component of “Accrued liabilities” and ‘Other non-current liabilities” in the accompanying condensed consolidated balance sheets (Note 3). The increase was primarily attributable to the increase in deferred mobilization revenue due to the timing of mobilization payments for contracts. Revenue recognized for the three-month periods ended March 31, 2025 and 2024 included $15.6 million and $16.4 million, respectively, that were included in the contract liability balance at the beginning of each period.

Performance Obligations

As of March 31, 2025, $1.4 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $592.1 million, $429.3 million and $394.4 million in 2025, 2026, 2027 and beyond, 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 the estimated start date and duration of each contract according to the information known at March 31, 2025.

For the three-month periods ended March 31, 2025 and 2024, revenues recognized from performance obligations satisfied (or partially satisfied) in previous periods were immaterial.

Contract Fulfillment Costs

Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $43.2 million as of March 31, 2025 and $37.2 million as of December 31, 2024. For the three-month periods ended March 31, 2025 and 2024, we recorded $16.4 million and $20.3 million, respectively, related to amortization of these deferred contract costs. There were no associated impairment losses for any period presented.

For additional information regarding revenue recognition, see Notes 2 and 11 to our 2024 Form 10-K.

Note 9 — Earnings Per Share

The computations of the numerator (earnings or loss) and denominator (shares) to derive the basic and diluted earnings per share (“EPS”) amounts presented on the face of the accompanying condensed consolidated statements of operations are as follows (in thousands, except per share amounts):


		Three Months Ended					Three Months Ended
		March 31, 2025					March 31, 2024
	****	Income		****	Shares	****	Income		****	Shares
Basic:
Net income (loss)		$	3,072				$	(26,287)
Less: Undistributed earnings allocated to participating securities			(2)					—
Net income (loss) available to common shareholders, basic		$	3,070		151,039		$	(26,287)		152,369

Earnings (loss) per share, basic		$	0.02				$	(0.17)

Diluted:
Net income (loss) available to common shareholders, basic		$	3,070		151,039		$	(26,287)		152,369
Effect of dilutive securities:
Share-based awards other than participating securities			—		1,135			—		—
Undistributed earnings reallocated to participating securities			—		—			—		—
Net income (loss) available to common shareholders, diluted		$	3,070		152,174		$	(26,287)		152,369

Earnings (loss) per share, diluted		$	0.02				$	(0.17)

Table of Contents We had a net loss for the three-month period ended March 31, 2024. Accordingly, our diluted EPS calculation for this period excluded the dilutive effect of 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 period. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):


		Three Months Ended
		March 31,
	****	2024
Diluted shares (as reported)		152,369
Share-based awards		2,705
Total		155,074

The following potentially dilutive shares related to the 2026 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):


		Three Months Ended
		March 31,
	****	2025	****	2024
2026 Notes		—		5,187

We have outstanding restricted stock units (“RSUs”) (Note 10) that can 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 10 — Employee Benefit Plans

Long-Term Incentive Plan

We currently have one active long-term incentive plan: the 2005 Long-Term Incentive Plan, as amended and restated (the “2005 Incentive Plan”). As of March 31, 2025, there were approximately 8.1 million shares of our common stock available for issuance under the 2005 Incentive Plan, assuming outstanding performance share units (“PSUs”) vest in shares of our common stock at 100% of the original awards and outstanding RSUs are settled in cash. During the three-month period ended March 31, 2025, 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/Vesting Date
January 1, 2025 ^(1)^		RSU	443,401	$	9.32	33% per year over three years
January 1, 2025 ^(2)^		PSU	397,264	$	10.56	100% on December 31, 2027
January 1, 2025 ^(3)^		Restricted stock	3,018	$	9.32	100% on January 1, 2027
(1)	Reflects grants to certain officers including our executive officers.
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(2)	Reflects grants to our executive officers.
---	---
(3)	Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash.
---	---

We grant restricted stock to members of our Board and from time to time our executive officers and select management employees. For the three-month periods ended March 31, 2025 and 2024, we recognized $0.2 million and $0.3 million, respectively, as share-based compensation related to restricted stock. 17

Table of Contents Our outstanding PSUs can be settled in either cash or shares of our common stock, or a combination thereof, at the discretion of the Compensation Committee of our Board upon vesting and generally have been accounted for as equity awards. Those PSUs consist of two components measured across a three-year performance period: (i) 50% based on the performance of our common stock against peer group companies (TSR component), which component contains a service and a market condition, and (ii) 50% based on cumulative total Free Cash Flow (FCF component), 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 the three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

For each of the three-month periods ended March 31, 2025 and 2024, $1.3 million were recognized as share-based compensation related to PSUs. In the first quarter 2025, based on the performance of our common stock price as compared to our performance peer group and our cumulative total Free Cash Flow, in each case over a three-year performance period, 1,065,705 PSUs granted in 2022 vested at 200%, resulting in 1,958,334 shares of our common stock with a total market value of $18.3 million and $1.6 million of cash.

Our currently outstanding RSUs can be settled in either cash or shares of our common stock, or a combination thereof, at the discretion of the Compensation Committee of our Board upon vesting and generally have been accounted for as liability awards. For the three-month periods ended March 31, 2025 and 2024, $1.0 million and $1.5 million, respectively, were recognized as compensation cost.

During the three-month period ended March 31, 2025 and the year ended December 31, 2024, we granted fixed-value cash awards of $6.7 million and $6.1 million, respectively, to select management employees under the 2005 Incentive Plan. The value of these cash awards is recognized on a straight-line basis over a vesting period of three years. For the three-month periods ended March 31, 2025 and 2024, $1.5 million and $1.4 million, respectively, were recognized as compensation cost.

Defined Contribution Plans

We sponsor a defined contribution 401(k) retirement plan in the U.S. We also contribute to various other defined contribution plans globally. For the three-month periods ended March 31, 2025 and 2024, we made contributions to our defined contribution plans totaling $1.5 million and $1.4 million, respectively.

Employee Stock Purchase Plan (“ESPP”)

As of March 31, 2025, 0.9 million shares were available for issuance under the ESPP. The ESPP currently has a purchase limit of 260 shares per employee per purchase period.

For more information regarding our employee benefit plans, including the 2005 Incentive Plan, the defined contribution plans and the ESPP, see Note 13 to our 2024 Form 10-K.

Note 11 — Business Segment Information

We have four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. Our U.S., U.K. and Brazil Well Intervention operating segments are aggregated into the Well Intervention segment for financial reporting purposes. These reportable segments are strategic business units that utilize different mix of vessels and/or equipment to perform different types of services. All material intercompany transactions between the segments have been eliminated. See Note 2 for more information on our business segments. 18

Table of Contents Our chief operating decision maker (“CODM”) is the chief operating officer. The CODM uses segment operating income or loss as the measure of segment profit or loss to evaluate segment performance by comparing the results of each segment with its annual budgeted amounts and monthly forecasts as well as the results of other segments. The CODM also uses segment operating income or loss to allocate company resources (including employees, property, and financial resources) to each segment. Information about our segment revenues and our measure of segment profit or loss is shown as follows (in thousands):


		Well						Shallow Water			Production
		Intervention		****	Robotics		****	Abandonment		****	Facilities		Total
Three months ended March 31, 2025
External revenues		$	198,374		$	43,087		$	16,766		$	19,837	$	278,064
Intersegment revenues ^(1)^			—			7,955			52			—		8,007
Segment revenues			198,374			51,042			16,818			19,837		286,071
Elimination of intersegment revenues														(8,007)
Total consolidated net revenues													$	278,064

Less ^(2)^:
Direct cost of revenues			(170,033)			(41,635)			(25,539)			(12,264)
Operations support			(4,019)			(1,391)			(2,861)			(113)
Selling, general and administrative expenses			(4,352)			(2,669)			(1,859)			(516)
Segment operating income (loss)		$	19,970		$	5,347		$	(13,441)		$	6,944	$	18,820

Three months ended March 31, 2024
External revenues		$	205,207		$	40,081		$	26,771		$	24,152	$	296,211
Intersegment revenues ^(1)^			6,093			10,228			82			—		16,403
Segment revenues			211,300			50,309			26,853			24,152		312,614
Elimination of intersegment revenues														(16,403)
Total consolidated net revenues													$	296,211

Less ^(2)^:
Direct cost of revenues			(184,193)			(40,713)			(33,224)			(25,315)
Operations support			(3,963)			(1,413)			(3,392)			(143)
Selling, general and administrative expenses			(4,465)			(2,733)			(2,515)			(237)
Other segment items ^(3)^			—			—			(150)			—
Segment operating income (loss)		$	18,679		$	5,450		$	(12,428)		$	(1,543)	$	10,158
(1)	Intersegment amounts are derived primarily from equipment and services provided to other business segments. Beginning in 2024, certain intersegment revenues of Well Intervention are no longer evaluated by the CODM in his assessment of the segment’s results as those revenues are pass-through amounts related to non-core services. For the three-month period ended March 31, 2024, $5.2 million have been removed from Well Intervention segment revenues and related intersegment eliminations. This change has no impact on our segment profit or our consolidated revenues and operating income (loss).
---	---
(2)	The significant expense categories and amounts align with the segment-level information that is regularly provided to the CODM. Intersegment expenses are included within the amounts shown.
---	---
(3)	Other segment items relate to gain (loss) on disposition of assets, net.
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Table of Contents The table below provides a reconciliation of segment profit to income (loss) before income taxes (in thousands):


	Three Months Ended
	March 31,
	2025		2024
Reconciliation of segment profit —
Segment operating income	$	18,820	$	10,158
Corporate, eliminations and other		(10,648)		(11,434)
Net interest expense		(5,706)		(5,477)
Losses related to convertible senior notes		—		(20,922)
Other non-operating expense, net		1,059		(310)
Income (loss) before income taxes	$	3,525	$	(27,985)

The following items are also regularly provided to the CODM (in thousands):


		Three Months Ended
		March 31,
		2025		2024
Capital expenditures ^(1)^ —
Well Intervention		$	2,968	$	2,216
Robotics			1,199		757
Shallow Water Abandonment			214		506
Production Facilities			—		—
Corporate, eliminations and other			107		126
Total		$	4,488	$	3,605

Depreciation and amortization ^(2)^ —
Well Intervention		$	30,591	$	31,309
Robotics			1,369		2,305
Shallow Water Abandonment			5,678		5,497
Production Facilities			4,749		7,138
Corporate and eliminations			95		104
Total		$	42,482	$	46,353
(1)	Represent cash paid principally for the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment.
---	---
(2)	Represents an aggregate of depreciation and amortization expense related to property and equipment and deferred recertification and dry dock costs, which is included within the segment expense captions “Direct cost of revenues” and “Selling, general and administrative expenses” as well as the line item caption “Corporate, eliminations and other” presented above.
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The CODM does not regularly review segment asset information as management’s focus is on operating performance and cash flow generation. As such, we have omitted the disclosure of total assets by segment.

Note 12 — Asset Retirement Obligations

Our asset retirement obligations (“AROs”) relate to mature offshore oil and gas properties (Droshky and Thunder Hawk Field) that we acquired with the intention to perform decommissioning work at the end of their life cycles. The following table describes the changes in our AROs (in thousands):


	2025		2024
AROs at January 1,	$	62,947	$	61,356
Accretion expense		1,408		1,376
AROs at March 31,	$	64,355	$	62,732

Table of Contents Note 13 — Commitments and Contingencies and Other Matters

Commitments

Our Well Intervention segment has long-term charter agreements with Sea1 Offshore (formerly Siem Offshore) for the Siem Helix 1 and Siem Helix 2 vessels, whose terms expire in December 2030 and December 2031, respectively. Our Robotics segment has vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon, the North Sea Enabler and the Glomar Wave, which charter terms expire in December 2030, May 2028, June 2026, December 2025 and December 2025, respectively. In February 2025, our Robotics segment took delivery of the Trym with a three-year charter that expires in February 2028. On April 1, 2025, we extended the Trym charter by one year.

Contingencies and Claims

From time to time, we may incur losses related to our contracts for matters such as costs in excess of contract consideration or claims related to disputes with customers and any obligations thereunder. While we believe we maintain appropriate accruals for such matters, the actual cost to us may be more or less than the amounts reserved.

We are involved in various legal proceedings in the normal course of business, including claims under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as the Jones Act), contract-related disputes, employee-related disputes and legacy issues related to Alliance. We recognize losses for lawsuits when the probability of an unfavorable outcome is probable and we can reasonably estimate the amount of the loss. For insured claims, we recognize such losses to the extent they exceed applicable insurance coverage. Although we can give no assurance about the outcome of litigation, claims or other proceedings, we do not currently believe that any loss resulting from litigation, claims or other proceedings, to the extent not otherwise covered by insurance, will have a material adverse impact on our consolidated financial statements.

Note 14 — Statement of Cash Flow Information

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


		Three Months Ended
		March 31,
		2025		2024
Interest paid		$	15,324	$	9,613
Income taxes paid ^(1)^			4,504		1,509
(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 $0.2 million at March 31, 2025 and $0.1 million at December 31, 2024.

Note 15 — 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):


		2025		2024
Balance at January 1,		$	3,682	$	3,407
Additions (reductions) ^(1)^			(85)		293
Balance at March 31,		$	3,597	$	3,700
(1)	Additions reflect reserves for expected credit losses during the respective periods.
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Table of Contents Note 16 — Fair Value Measurements

Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term 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 principal amount and estimated fair value of our long-term debt are as follows (in thousands):


		March 31, 2025				December 31, 2024
		Principal		Fair		Principal		Fair
		Amount ^(1)^		Value ^(2)^		Amount ^(1)^		Value ^(2)^
MARAD Debt (matures February 2027)		$	19,294	$	18,994	$	23,831	$	23,505
2029 Notes (mature March 2029)			300,000		321,000		300,000		319,500
Total debt		$	319,294	$	339,994	$	323,831	$	343,005
(1)	Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 5 for additional disclosures on our long-term debt.
---	---
(2)	The estimated fair value was determined using Level 2 fair value inputs under the market approach, which was determined using quotes in inactive markets.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results 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 and represent our current expectations 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 of 1934, as amended (the “Exchange Act”). All statements included herein or incorporated 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 although not all forward-looking statements contain such identifying words. Included in forward-looking statements are, among other things:

●	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, cash flows, future operations expenditures or other financial items;
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●	statements regarding our backlog and commercial contracts and rates thereunder;
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●	statements regarding our ability to enter into, renew and/or perform commercial contracts, including the scope, timing and outcome of those contracts;
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●	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;
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●	statements regarding general economic or political conditions, whether international, national or in the regional or local markets in which we do business;
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●	statements regarding energy transition and energy security;
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●	statements regarding our ability to identify, effect and integrate mergers, acquisitions, joint ventures or other transactions and any subsequently identified legacy issues with respect thereto;
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●	statements regarding the acquisition, construction, completion, upgrades to or maintenance and/or regulatory certification of vessels, systems or equipment and any anticipated costs or downtime related thereto;
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●	statements regarding any financing transactions or arrangements, or our ability to enter into such transactions or arrangements;
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●	statements regarding our trade receivables and their collectability;
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Table of Contents

●	statements regarding potential legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
●	statements regarding our sustainability initiatives and the successes thereon or regarding our environmental efforts, including with respect to greenhouse gas emissions;
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●	statements regarding global, market or investor sentiment with respect to fossil fuels;
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●	statements regarding our existing activities in, and future expansion into, the offshore renewable energy market;
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●	statements regarding potential developments, industry trends, performance or industry ranking;
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●	statements regarding our human capital management, including our ability to retain our senior management and other key employees;
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●	statements regarding our share repurchase authorization or program;
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●	statements regarding the underlying assumptions related to any projection or forward-looking statement; and
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●	any other statements that relate to non-historical or future information.
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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 differ materially from those in the forward-looking statements. These factors include:

●	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 natural gas price volatility and the cyclical nature of the oil and gas market;
---	---
●	the potential impact of geopolitical and domestic policy changes, including tariffs, that may negatively affect oil and gas production and/or pricing or adversely impact offshore renewable energy projects, costs of materials, regulations surrounding safe offshore well intervention, regulations of decommissioning offshore oil and gas wells, and global trade, economic growth and stability;
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●	the potential effects of regional tensions that have escalated or may escalate, including into conflicts or wars, and their impact on the global economy, the 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;
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●	the results of corporate initiatives such as alliances, partnerships, joint ventures, mergers, acquisitions, divestitures and restructurings, and any amounts payable in connection therewith, or the determination not to pursue or effect such initiatives;
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●	the operating results of acquired properties and/or equipment;
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●	the impact of inflation and our ability to recoup rising costs in the rates we charge to our customers;
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●	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;
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●	the ability to effectively bid, renew and perform our contracts, including the impact of equipment problems or failure;
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●	the impact of the imposition by our customers of rate reductions, fines and penalties with respect to our operating assets;
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●	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;
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●	the future impact of international activity and trade agreements on our business, operations and financial condition;
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●	the performance of contracts by customers, suppliers and other counterparties;
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●	the results of our continuing efforts to control costs and improve performance;
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●	unexpected future operations expenditures, including the amount and nature thereof;
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●	the effectiveness and timing of our vessel and/or system upgrades, regulatory certification and inspection as well as major maintenance items;
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●	operating hazards, including unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;
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●	the effect of adverse weather conditions and/or other risks associated with marine operations;
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●	the impact of foreign currency exchange controls, potential illiquidity of those currencies and exchange rate fluctuations;
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●	the effectiveness of our risk management activities and processes, including with respect to our cybersecurity initiatives and disclosures;
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●	the effects of competition;
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Table of Contents

●	the availability of capital (including any financing) to fund our business strategy and/or operations;
●	the effects of our indebtedness, our ability to comply with debt covenants and our ability to reduce capital commitments;
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●	the impact of our stock price on our financing activities such as repurchases of our common stock under share repurchase programs;
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●	the effectiveness of our sustainability initiatives and disclosures;
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●	the effectiveness of any future hedging activities;
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●	the potential impact of a negative event related to our human capital management, including a loss of one or more key employees;
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●	the impact of general, market, industry or business conditions; and
---	---
●	the factors generally described in Item 1A. Risk Factors in our 2024 Form 10-K.
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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 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Form 10-K. 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.

We caution you not to place undue reliance on 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 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 2024 Form 10-K that attempt to advise interested parties of the risks and factors that may affect our business.

EXECUTIVE SUMMARY

Our Business

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 decommissioning operations. Our services are key in supporting a global energy transition by maximizing production of existing oil and gas reserves, decommissioning end-of-life oil and gas fields and supporting renewable energy developments. Our Well Intervention segment includes seven purpose-built well intervention vessels and 12 intervention systems. Our Robotics segment includes 39 work-class ROVs, six trenchers, two IROV boulder grabs, and robotics support vessels chartered 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 CT systems. Our Production Facilities segment includes the HP I, the HFRS and our ownership of mature oil and gas properties.

Demand for our services is primarily influenced by the condition of the oil and gas and the renewable energy markets and, in particular, the level of spending of offshore energy companies on operational activities and capital projects. The performance of our business is largely 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 various other factors. Demand for decommissioning is affected by commodity prices as well as governmental regulations and political forces globally.

We maximize production of existing oil and gas reserves for our customers primarily in our Well Intervention segment. Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig 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, 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 and services. 24

Table of Contents Once end-of-life oil and gas wells have depleted their production, we decommission wells and infrastructure in our Well Intervention and Shallow Water Abandonment segments. 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. We believe that our well intervention vessels have a competitive advantage in performing these services efficiently and with our suite of shallow water assets and capabilities, we are the only provider capable of providing all facets of decommissioning services in the Gulf of America shelf.

We support the energy transition to renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, including subsea cable trenching and burial as well as seabed clearance and preparation services. Demand for our services in the renewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the generation and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water and other regions, and government subsidies for renewable energy projects and/or other governmental regulations supporting or restricting renewable energy developments.

Current Market Environment

Commodity prices continued to be volatile during the first quarter 2025. Oil prices dropped precipitously into the low $60s in early April 2025 following the U.S. government’s enactment of record tariffs levied globally and the announcement of significant increases in oil production by members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”). These events follow increasing regulatory actions in the U.K., where the British government has enacted the Energy Profits Levy (windfall tax) and other changes that have significantly increased our customers’ costs in that region. Furthermore, there have been recent merger announcements of operators in the U.K. North Sea. Pending mergers historically result in reductions in spending during the merger process.

The production increases, tariffs and resulting trade wars are expected to result in slower economic growth and substantially increase the risk of a recession, both of which would reduce global demand for oil, putting further pressure on commodity prices, which is likely to result in lower customer spending for the industry. Additionally, the industry continues to be threatened by decisions from OPEC+, governmental regulations and changes thereto, geopolitical instability and uncertainty, regional conflicts, unrest in the Middle East, various governmental and customer sustainability initiatives and continued shifting of resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility and may prolong existing lower commodity prices with the potential to temper customer spending for offshore oil and gas projects.

The international wind market continues to be robust, with continued activity and sanctioned work primarily in Europe and Asia Pacific. U.S. windfarm activity is expected to decline following the 2025 Wind Energy Ban, a Presidential Memorandum issued in the U.S. in January 2025 temporarily withdrawing wind energy leasing in the U.S. Outer Continental Shelf.

Outlook

Following the production increases announced by OPEC+ and the tariffs announced by the U.S. government in early April as described above, we anticipate more uncertainty and expect a more challenging spot market for Well Intervention and Shallow Water Abandonment in 2025, although our performance should be supported by our backlog from new contracting at improved rates and by increasing demand for our decommissioning services internationally, which should grow over mid- to long-term as the subsea tree base expands, as customers reduce their decommissioning obligations, and as customers shift resources to renewable energy. We expect the demand for shallow water decommissioning services in the Gulf of America to improve over the mid- to long-term as oil and gas properties revert to former owners due to bankruptcies, who are expected to address their decommissioning obligations. We expect growth in our renewables services as the global demand for energy increases and the international energy market continues offshore renewable energy developments. 25

Table of Contents Backlog

Our backlog is represented by signed contracts. As of March 31, 2025, our consolidated backlog totaled approximately $1.4 billion, of which $592 million is expected to be performed over the remainder of 2025. Our various contracts with Shell and Subsea 7 globally, our contracts with Trident Energy and Petrobras in Brazil, and our contracts with Talos in the Gulf of America represented approximately 86% of our total backlog as of March 31, 2025. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as (i) services are often added but may sometimes be subtracted; (ii) contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and (iii) reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in 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 GAAP. Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.

We evaluate our operating performance and financial condition based on EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt. EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt are non-GAAP financial measures that are commonly used but are not recognized accounting terms under 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 measures of EBITDA, 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 and compare our results to other companies that have different financing, capital and tax structures. Other companies may calculate their measures of EBITDA, Adjusted EBITDA, Free Cash Flow and Net Debt differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA, 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 data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude gains or losses on disposition of assets, acquisition and integration costs, gains or losses related to convertible senior notes, the change in fair value of contingent consideration and the general provision for (release of) current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from asset sales and insurance recoveries (related to property and equipment), if any. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents. In the following reconciliations, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted. 26

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


		Three Months Ended
		March 31,
	****	2025		****	2024
Net income (loss)		$	3,072		$	(26,287)
Adjustments:
Income tax provision (benefit)			453			(1,698)
Net interest expense			5,706			5,477
Other expense, net			357			2,216
Depreciation and amortization			42,482			46,353
EBITDA			52,070			26,061
Adjustments:
Loss on disposition of assets, net			—			150
General release of current expected credit losses			(85)			(143)
Losses related to convertible senior notes			—			20,922
Adjusted EBITDA		$	51,985		$	46,990

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


		Three Months Ended
		March 31,
	****	2025		****	2024
Cash flows from operating activities		$	16,442		$	64,484
Less: Capital expenditures, net of proceeds from asset sales and insurance recoveries			(4,488)			(3,242)
Free Cash Flow		$	11,954		$	61,242

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


		March 31,			December 31,
	****	2025		****	2024
Long-term debt including current maturities		$	311,109		$	315,157
Less: Cash and cash equivalents			(369,987)			(368,030)
Net Debt		$	(58,878)		$	(52,873)

Table of Contents Comparison of Three Months Ended March 31, 2025 and 2024

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/				****
		March 31,						(Decrease)				****
	****	2025		****	2024		****	Amount		****	Percent	****
Net revenues —
Well Intervention		$	198,374		$	211,300		$	(12,926)		(6)	%
Robotics			51,042			50,309			733		1	%
Shallow Water Abandonment			16,818			26,853			(10,035)		(37)	%
Production Facilities			19,837			24,152			(4,315)		(18)	%
Intercompany eliminations			(8,007)			(16,403)			8,396
		$	278,064		$	296,211		$	(18,147)		(6)	%

Gross profit (loss) —
Well Intervention		$	24,322		$	23,144		$	1,178		5	%
Robotics			8,016			8,183			(167)		(2)	%
Shallow Water Abandonment			(11,582)			(9,763)			(1,819)		19	%
Production Facilities			7,460			(1,306)			8,766		671	%
Corporate, eliminations and other			(678)			(704)			26
		$	27,538		$	19,554		$	7,984		41	%

Gross margin —
Well Intervention			12	%		11	%
Robotics			16	%		16	%
Shallow Water Abandonment			(69)	%		(36)	%
Production Facilities			38	%		(5)	%
Total company			10	%		7	%

Number of vessels, Robotics assets or Shallow Water Abandonment systems ^(1)^ / Utilization ^(2)^
Well Intervention vessels			7 / 67	%		7 / 90	%
Robotics assets ^(3)^			47 / 51	%		47 / 58	%
Chartered Robotics vessels			6 / 67	%		6 / 74	%
Shallow Water Abandonment vessels ^(4)^			20 / 30	%		20 / 41	%
Shallow Water Abandonment systems ^(5)^			26 / 11	%		26 / 26	%
(1)	Represents the number of vessels, Robotics assets or 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.
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(2)	Represents the average utilization rate, which is calculated by dividing the total number of days the vessels, Robotics assets or Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period. Utilization rate of chartered Robotics vessels during the three-month period ended March 31, 2024 included 91 spot vessel days at full utilization.
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(3)	Consists of ROVs, trenchers and IROV boulder grabs.
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(4)	Consists of liftboats, OSVs, DSVs, a heavy lift derrick barge and a crew boat.
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(5)	Consists of P&A and CT systems.
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Table of Contents Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


		Three Months Ended
		March 31,						Increase/
	****	2025		****	2024		****	(Decrease)
Well Intervention		$	—		$	6,093		$	(6,093)
Robotics			7,955			10,228			(2,273)
Shallow Water Abandonment			52			82			(30)
		$	8,007		$	16,403		$	(8,396)

Net Revenues. Our consolidated net revenues for the three-month period ended March 31, 2025 decreased by 6% as compared to the same period in 2024, reflecting lower revenues in our Well Intervention, Shallow Water Abandonment and Production Facilities business segments, offset in part by higher revenues in our Robotics segment.

Our Well Intervention revenues decreased by 6% for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting lower utilization on the Seawell and the Q7000, offset in part by higher rates during the first quarter 2025. Revenues decreased on the Seawell, which was idle during the first quarter 2025 as compared to being nearly fully utilized operating in the western Mediterranean during the first quarter 2024. Revenues on the Q7000 were lower due to the vessel recognizing only six days of revenue in Brazil during the first quarter 2025 as compared to being fully utilized in Australia during the first quarter 2024. The Q7000 completed its mobilization and regulatory docking and commenced its 400-day contract in Brazil at the end of March 2025. During the first quarter 2025, the Q4000 generated higher integrated project revenues while the Q5000 worked at higher contracted rates as compared to the first quarter 2024. Additionally during the first quarter 2025, the Siem Helix 1 operated at higher rates on its contract extension with Trident as compared to the first quarter 2024 and the Siem Helix 2 operated at higher rates on its new contract with Petrobras that commenced early January 2025.

Our Robotics revenues increased by 1% for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting increased trenching activities, offset in part by a reduction in other ROV and vessel utilization. The first quarter 2025 included 135 integrated vessel trenching days and 90 days of trenching on a third-party vessel as compared to 85 integrated vessel trenching days during the first quarter 2024. Chartered vessel activity decreased to 244 days during the first quarter 2025 as compared to 333 days during the first quarter 2024. Overall ROV and trencher utilization decreased to 51% during the first quarter 2025 from 58% during the first quarter 2024.

Our Shallow Water Abandonment revenues decreased by 37% for the three-month period ended March 31, 2025 as compared to the same period in 2024 due to lower vessel and system utilization. Overall vessel utilization was 30% during the first quarter 2025 as compared to 41% during the first quarter 2024. P&A systems and CT systems utilization decreased to 264 days, or 11%, during the first quarter 2025 as compared to 626 days, or 26%, during the first quarter 2024.

Our Production Facilities revenues decreased by 18% for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting lower oil and gas production and prices during the first quarter 2025. Oil and gas production during the first quarter 2025 did not include production from the Thunder Hawk wells, which were active during the first quarter 2024 but have been shut-in since the third quarter 2024.

Gross Profit (Loss). Our consolidated gross profit increased by $8.0 million for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting increased profitability from our Well Intervention and Production Facilities business segments, offset in part by reduced profitability from our Shallow Water Abandonment segment.

Our Well Intervention segment gross profit increased by $1.2 million for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting lower idle vessel costs in the North Sea and cost deferrals on the Q7000 during its mobilization and regulatory docking, offset in part by lower revenues during the first quarter 2025.

Our Robotics gross profit remained relatively flat for the three-month period ended March 31, 2025 as compared to the same period in 2024. 29

Table of Contents Our Shallow Water Abandonment gross loss increased by $1.8 million for the three-month period ended March 31, 2025 as compared to the same period in 2024, primarily reflecting lower revenues, offset in part by lower costs during the first quarter 2025.

Our Production Facilities had a gross profit of $7.5 million for the three-month period ended March 31, 2025 as compared to a gross loss of $1.3 million for the same period in 2024 primarily due to the incurrence of well workover costs related to the Thunder Hawk wells during the first quarter 2024.

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $19.4 million for the three-month period ended March 31, 2025 as compared to $20.7 million for the same period in 2024, primarily reflecting lower employee compensation costs.

Net Interest Expense. Our net interest expense totaled $5.7 million for the three-month period ended March 31, 2025 as compared to $5.5 million for the same period in 2024, primarily reflecting lower interest income on our invested cash (Note 5).

Losses Related to Convertible Senior Notes. The losses during the three-month period ended March 31, 2024 were associated with the redemption of our 2026 Notes (Note 5).

Other Expense, Net. Net other expense was $0.4 million for the three-month period ended March 31, 2025 as compared to $2.2 million for the same period in 2024. Net other expense during the first quarter 2025 primarily reflects foreign currency losses related to the appreciation of the British pound on net cash balances denominated in U.S. dollar in our U.K. entities. Net other expense during the first quarter 2024 primarily reflects 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 (Benefit). Income tax provision was $0.5 million for the three-month period ended March 31, 2025 as compared to income tax benefit of $1.7 million for the same period in 2024. The effective tax rate for the three-month period ended March 31, 2025 was impacted by a discrete non-U.S. tax benefit. The effective rate for the three-month period ended March 31, 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

LIQUIDITY AND CAPITAL RESOURCES

Financial Condition and Liquidity

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


		March 31,			December 31,
	****	2025		****	2024
Net working capital		$	412,812		$	405,266
Long-term debt (excluding current maturities)			301,697			305,971
Liquidity			404,673			429,586

Net Working Capital

Net working capital is equal to current assets minus current liabilities and includes cash and cash equivalents, current maturities of long-term debt and current operating lease liabilities. 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, presented net of unamortized debt discount and debt issuance costs, includes our MARAD Debt and the 2029 Notes and excludes current maturities of $9.4 million at March 31, 2025 and $9.2 million at December 31, 2024. See Note 5 for information relating to our long-term debt. 30

Table of Contents Liquidity

We define liquidity as cash and cash equivalents plus available capacity under our credit facility, but excluding cash pledged as collateral toward the Amended ABL Facility. Our liquidity at March 31, 2025 included $370.0 million of cash and cash equivalents and $62.7 million of available borrowing capacity under the Amended ABL Facility (Note 5) and excluded $28.0 million of pledged cash. Our liquidity at December 31, 2024 included $368.0 million of cash and cash equivalents and $66.6 million of available borrowing capacity under the Amended ABL Facility and excluded $5.0 million of pledged cash. The reduction in availability on the facility was primarily attributable to higher letter of credit usage in order to support the Nigeria project on the Q4000.

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 expected capital spending, service our debt and other obligations, and execute our share repurchase program over at least the next 12 months. We expect availability on the Amended ABL Facility to increase following the completion of the Q4000 Nigeria campaign. We currently do not anticipate borrowing under the Amended ABL Facility and expect to only use the facility for the issuance of letters of credit.

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.

Cash Flows

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


		Three Months Ended
		March 31,
	****	2025		****	2024
Cash provided by (used in):
Operating activities		$	16,442		$	64,484
Investing activities			(4,488)			(3,242)
Financing activities			(11,075)			(69,304)

Operating Activities

Our operating cash flows for the three-month period ended March 31, 2025 decreased despite higher earnings as compared to the same period in 2024, primarily reflecting higher regulatory recertification costs on our vessels and systems and lower working capital inflows. Regulatory recertification spending on our vessels and systems was $17.9 million and $9.6 million, respectively, during the comparable year over year periods.

Investing Activities

Cash flows used in investing activities for the three-month period ended March 31, 2025 increased slightly as compared to the same period in 2024 primarily due to higher capital expenditures.

Financing Activities

Net cash outflows from financing activities for the three-month period ended March 31, 2025 primarily reflect the principal repayment of $4.5 million related to the MARAD Debt and payments in satisfaction of tax obligations upon vesting of share-based awards. Net cash outflows from financing activities for the three-month period ended March 31, 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, the principal repayment of $4.3 million related to the MARAD Debt and $4.2 million in repurchases of our common stock under the 2023 Repurchase Program. These outflows were offset in part by $4.4 million of cash inflows from the proportionate settlement of the 2026 Capped Calls. 31

Table of Contents 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.

Long-term debt and other contractual commitments

The following table summarizes (in thousands) 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 and operating lease obligations, as of March 31, 2025 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. 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 March 31, 2025.


	****	Total		****	Short-Term		****	Long-Term
MARAD debt		$	19,294		$	9,412		$	9,882
2029 Notes			300,000			—			300,000
Interest related to debt			116,702			30,717			85,985
Property and equipment			11,998			11,998			—
Operating leases ^(1)^			839,828			160,099			679,729
Total cash obligations		$	1,287,822		$	212,226		$	1,075,596
(1)	Operating leases include vessel charters and facility and equipment leases, including commitments related to leases executed but not yet commenced. At March 31, 2025, our commitment related to long-term vessel charters totaled approximately $804.9 million, of which $409.3 million was related to the non-lease (services) components that are not included in operating lease liabilities in the condensed consolidated balance sheet as of March 31, 2025.
---	---

Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 12). Those obligations, which are presented on a discounted basis on the condensed consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk Field oil and gas properties and $37.1 million (undiscounted) for Droshky oil and gas properties as of March 31, 2025, 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 Corporation as certain decommissioning obligations associated with Droshky oil and gas properties are fulfilled.

Regulatory recertification and dry dock. Our 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 $0.2 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. 32

Table of Contents CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our discussion and analysis of our financial condition and results of operations, as reflected in the condensed consolidated financial statements and related footnotes, are prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that have had or are reasonably likely to have a material impact on our financial condition or results of 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 information regarding our critical accounting estimates, see our “Critical Accounting Estimates” as disclosed in our 2024 Form 10-K.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

As a multi-national organization, we are subject to market risks associated with foreign currency exchange rates, interest rates and 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 impacted by movements in foreign currency exchange rates when (i) transactions are denominated in currencies other than the functional currency of the relevant Helix entity or (ii) the functional currency of our subsidiaries is not the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the U.S., we 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.

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 three-month period ended March 31, 2025, we recorded foreign currency translation gains of $27.2 million to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as any outside stock basis differences would be realized in a tax-free manner.

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 monetary assets and liabilities as well as unsettled foreign currency transactions, including intercompany transactions that are not of a long-term investment nature, are also recognized as a component of “Other income (expense), net.” For the three-month period ended March 31, 2025, we recorded net foreign currency losses of $0.4 million, primarily related to U.S. dollar denominated cash balances in our U.K. entities.

Interest Rate Risk. In order to minimize the risk of changes to our cash flow due to changing interest rates, we generally borrow at fixed rates, but may borrow at variable rates from time to time. 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 and we may be at risk upon refinancing maturing debt. For variable rate debt, changes in interest rates could affect our future interest expense and cash flows. We currently have no amounts outstanding under the Amended ABL Facility or other debt subject to floating rates.

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 2024 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 March 31, 2025. Based on this evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2025 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 three-month period ended March 31, 2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1, Note 13 — Commitments and Contingencies and Other Matters 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 March 31, 2025 in our “Risk Factors” as discussed in Item 1A of our Annual Report on Form 10-K for the year ended December 31, 2024.

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 ^(2)^
Period	****	purchased ^(1)^	****	per share		****	or programs	****	(in thousands)
January 1 to January 31, 2025		394,215		$	9.32		—		$	158,392
February 1 to February 28, 2025		385,304			9.32		—			158,392
March 1 to March 31, 2025		—			—		—			158,392
		779,519		$	9.32		—
(1)	Includes shares forfeited in satisfaction of tax obligations upon vesting of share-based awards under our existing long-term incentive plans.
---	---
(2)	See Note 7 to this Quarterly Report on Form 10-Q and Note 10 to our 2024 Annual Report on Form 10-K for additional information regarding our share repurchase programs.
---	---

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Table of Contents Item 5. Other Information

(c) During the three-month period ended March 31, 2025, 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.

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 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 Energy Solutions Group, Inc., as amended.		Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
10.1		Amendment and Assignment Agreement to Strategic Alliance Agreement.		Exhibit 10.1 to the Current Report on Form 8-K filed on February 21, 2025 (001-32936)
31.1		Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer.		Filed herewith
31.2		Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Erik Staffeldt, Chief Financial Officer.		Filed herewith
32.1		Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes–Oxley Act of 2002.		Furnished herewith
101.INS		XBRL Instance Document.		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.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
104		Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).		Filed herewith

Table of Contents SIGNATURES

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


		HELIX ENERGY SOLUTIONS GROUP, INC.
		(Registrant)

Date: April 24, 2025	By:	/s/ Owen Kratz
		Owen Kratz
		President and Chief Executive Officer
		(Principal Executive Officer)

Date: April 24, 2025	By:	/s/ Erik Staffeldt
		Erik Staffeldt
		Executive Vice President and
		Chief Financial Officer
		(Principal Financial Officer)

EXHIBIT 31.1

SECTION 302 CERTIFICATION

I, Owen Kratz, the President and Chief Executive Officer of Helix Energy Solutions Group, Inc., certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Helix Energy Solutions Group, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
---	---
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
---	---
(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
---	---
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
---	---
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
---	---
(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
---	---

Date: April 24, 2025

	/s/ Owen Kratz
	Owen Kratz
	President and Chief Executive Officer

EXHBIT 31.2

SECTION 302 CERTIFICATION

I, Erik Staffeldt, the Executive Vice President and Chief Financial Officer of Helix Energy Solutions Group, Inc., certify that:

1.	I have reviewed this Quarterly Report on Form 10-Q of Helix Energy Solutions Group, Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
---	---
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
---	---
(a)	designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
---	---
(c)	evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
---	---
5.	The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
---	---
(a)	all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
---	---
(b)	any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
---	---

Date: April 24, 2025

	/s/ Erik Staffeldt
	Erik Staffeldt
	Executive Vice President and Chief Financial Officer

EXHIBIT 32.1

CERTIFICATION OF CEO AND CFO PURSUANT TO 18 U.S.C. SECTION 1350

(As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002)

In connection with the Quarterly Report of Helix Energy Solutions Group, Inc. (“Helix”) on Form 10-Q for the quarterly period ended March 31, 2025, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Owen Kratz, as President and Chief Executive Officer, and Erik Staffeldt, as Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1)	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Helix.
---	---

Date: April 24, 2025


	/s/ Owen Kratz
	Owen Kratz
	President and Chief Executive Officer

Date: April 24, 2025


	/s/ Erik Staffeldt
	Erik Staffeldt
	Executive Vice President and Chief Financial Officer