UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

For the fiscal year ended December 31, ~~2024~~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)

Registrant’s telephone number, including area code (281) 618-0400

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

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☑ Yes ☐ No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☑ No

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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, ~~2024~~2025 was approximately $1855.72 ~~billion~~million based on the closing price of the registrant’s common stock as quoted on the New York Stock Exchange on June 30, ~~2024~~2025.

The number of shares of the registrant’s common stock outstanding as of February 19 17, ~~2025~~2026 was ~~150~~147,~~936~~296,~~476~~092.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 14 13, ~~2025~~2026 are incorporated by reference into Part III hereof.

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HELIX ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K

		Page
	PART I
Item 1.	Business	5
Item 1A.	Risk Factors	16
Item 1B.	Unresolved Staff Comments	2829
Item 1C.	Cybersecurity	2829
Item 2.	Properties	2930
Item 3.	Legal Proceedings	31
Item 4.	Mine Safety Disclosures	31
Unnumbered Item	Information about our Executive Officers	31
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	32
Item 6.	[Reserved]	34
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	34
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	4344
Item 8.	Financial Statements and Supplementary Data	45
	Report of Independent Registered Public Accounting Firm (KPMG LLP, Houston, Texas, Auditor Firm ID 185)	45
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	47
	Consolidated Balance Sheets as of December 31, ~~2024~~2025 and ~~2023~~2024	48
	Consolidated Statements of Operations for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023	49
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023	49
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023	50
	Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023	51
	Notes to Consolidated Financial Statements	52
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	80
Item 9A.	Controls and Procedures	80
Item 9B.	Other Information	81
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	81
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	81
Item 11.	Executive Compensation	81
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	82
Item 13.	Certain Relationships and Related Transactions, and Director Independence	82
Item 14.	Principal Accounting Fees and Services	82
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	82
Item 16.	Form 10-K Summary	87
	Signatures	88

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Forward Looking Statements

This Annual Report on Form 10-K (“Annual Report”) contains or incorporates by reference various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. 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 (the “Securities Act”), 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, capital spending, share repurchases, working capital, debt and liquidity, cash flows, future ~~operations~~operating expenditures or other financial items;

●

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;

●

statements regarding our trade receivables and their collectability;

●

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

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statements regarding our sustainability initiatives and the successes thereon or regarding our environmental efforts, including with respect to greenhouse gas emissions (“GHG Emissions”);

●

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;

●

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

●

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

●

statements regarding our share repurchase authorization or program;

●

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

●

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

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;

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● 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;

●

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;

●

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;

●

the operating results of acquired properties and/or equipment;

●

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

●

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

●

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

●

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

●

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

●

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

●

the performance of contracts by customers, suppliers and other counterparties;

●

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

●

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

●

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

●

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

●

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

●

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

●

the effectiveness of our risk management activities and processes, including with respect to our cybersecurity initiatives and disclosures;

●

the effects of competition;

●

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

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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;

●

the effectiveness of our sustainability initiatives and disclosures;

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the effectiveness of any future hedging activities;

●

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

●

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

●

the factors generally described in Item 1A. Risk Factors of this Annual Report.

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 “Risk Factors” beginning on page 16 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 34 of this Annual Report. Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

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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 Annual 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 Annual Report and our reports filed with the Securities and Exchange Commission (“SEC”) and incorporated by reference herein that attempt to advise interested parties of the risks and factors that may affect our business. Please see “Website and Other Available Information” for further details.

PART I

Item 1. Business

OVERVIEW

Helix Energy Solutions Group, Inc. (together with its subsidiaries, unless context requires otherwise, “Helix,” the “Company,” “we,” “us” or “our”) was incorporated in 1979 and in 1983 was re-incorporated in the state of Minnesota. 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. See “Our Operations” below for additional information regarding business operations.

Our principal executive offices are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas 77043; our phone number is 281-618-0400. Our common stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “HLX.” Our Chief Executive Officer submitted the annual CEO certification to the NYSE in May ~~2024~~2025 as required under its Listed Company Manual. Our principal executive officer and our principal financial officer have made the certifications required under Section 302 of the Sarbanes-Oxley Act, which are included as exhibits to this Annual Report.

Please refer to the subsection “Certain Definitions” on page 14 for definitions of additional terms commonly used in this Annual Report. Unless otherwise indicated, any reference to Notes herein refers to Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data of this Annual Report.

OUR OPERATIONS

We provide a range of services to the oil and gas and renewable energy markets primarily in the ~~U.S.~~ Gulf ~~Coast~~of America (deepwater and shelf), ~~U.S. East Coast,~~ Brazil, North Sea, ~~Asia~~West ~~Pacific~~Africa and ~~West~~Asia ~~Africa~~Pacific regions. Our services are segregated into four reportable business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities.

Services we currently offer to the offshore oil and gas market worldwide include:

●

Production. Well intervention; intervention engineering; production enhancement; coiled tubing (“CT”) operations; inspection, repair and maintenance (“IRM”) of production structures, trees, jumpers, risers, pipelines and subsea equipment; and related support services.

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Decommissioning. Reclamation and remediation services; well plug and abandonment (“P&A”) services; pipeline, cable and umbilical abandonment services; and site inspections.

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Production Facilities. Provision of the Helix Producer I (the “HP I”) as an oil and natural gas processing facility. Currently, the HP I is being utilized to process production from the Phoenix field in the Gulf of America.

●

Fast Response System. Provision of the Helix Fast Response System (the “HFRS”) as a response resource in the Gulf of America that can be identified in permit applications to U.S. federal and state agencies and respond to a well control incident.

●

Development. Installation of flowlines, control umbilicals, manifold assemblies and risers; trenching and burial of pipelines; installation and tie-in of riser and manifold assembly; commissioning, testing and inspection; and cable and umbilical lay and connection.

● Production Facilities. Provision of the Helix Producer I (the “HP I”) as an oil and natural gas processing facility. Currently, the HP I is being utilized to process production from the Phoenix field in the U.S. Gulf Coast.

● Fast Response System. Provision of the Helix Fast Response System (the “HFRS”) as a response resource in the U.S. Gulf Coast that can be identified in permit applications to U.S. federal and state agencies and respond to a well control incident.

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Services we currently offer to the offshore renewable energy market worldwide include:

● Trenching. Cable burial ~~via~~utilizing our jetting, ~~and/or~~ cutting byor ~~self-propelled trenching remotely operated vehicles (“ROVs”); trenching using our I-~~plough ~~trencher~~trenchers.

●

Site Clearance. Site preparation for construction of offshore wind farms, including boulder relocation and underwater unexploded ordnance identification and disposal.

● Subsea Support. General subsea support of engineering, procurement, construction and installation contractors with remotely operated vehicle (“ROV”) services standalone or with support vessels.

Well Intervention

We engineer, manage and conduct well intervention operations, which include production enhancement and abandonment, and construction operations in water depths ranging from 100 to 10,000 feet. As major and independent oil and gas companies develop deepwater reserves, we expect the number of subsea trees to increase, which can improve long-term demand for well intervention services. Drilling rigs ~~have~~ historically have been and ~~are~~ still are used in subsea well intervention ~~to enhance production and decommission wells~~. Our purpose-built well intervention vessels derive competitive advantages in the development and management of subsea reservoirs from their lower operating costs, with an ability to mobilize quickly and to maximize operational time by more efficiently performing a broad range of tasks related to intervention, construction and IRM services. ~~Our services provide cost advantages in the development and management of subsea reservoirs.~~

Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and two chartered vessels, the Sea Helix 1 (formerly Siem Helix 1) and the Siem Helix 2. Our well intervention equipment includes 12 intervention systems consisting of eight intervention riser systems (“IRSs”), three subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module (“ROAM”), some of which we provide on a stand-alone basis.

~~The~~In ~~Q4000~~the Gulf of America, awe operate the Q4000 and Q5000 riser-based semi-submersible well intervention ~~vessel,~~vessels. The Q4000 has served customers in the spot market in the ~~U.S.~~ Gulf ~~Coast~~of America since 2002. ~~Notably~~and ~~the~~notably ~~Q4000~~ served as a key emergency response vessel in the Macondo well control and containment efforts in 2010. The ~~vessel is currently performing integrated well intervention operations offshore Nigeria. The~~ Q5000 ~~riser-based~~has ~~semi-submersible~~operated ~~well intervention vessel commenced operations~~ in the ~~U.S.~~ Gulf ~~Coast~~of inAmerica ~~2015~~since ~~and is under a two-year contract with Shell through 2026~~2015.

In Brazil, we provide well intervention services with the ~~Siem~~Sea Helix 1 and Siem Helix 2 monohull riser-based well intervention vessels under long-term charter from Sea1 Offshore (formerly Siem Offshore). The ~~Siem~~Sea Helix 1 commenced operations in April 2017 and is ~~currently~~under ~~working~~contract onwith aPetrobras ~~long-term~~through ~~P&A~~at ~~project~~least ~~for Trident Energy do Brasil Ltda. (“Trident Energy”) through~~ November ~~2025~~2028. The Siem Helix 2 commenced operations in December 2017 and is under contract with Petrobras through at least ~~December~~January ~~2027~~2028.

In the North Sea, we operate the Seawell and Well Enhancer ~~has~~monohull ~~performed~~light well intervention, ~~abandonment and CT services since it joined our fleet in 2009~~vessels. The Seawell has provided well intervention and abandonment services since 1987. The vessel underwent major capital upgrades in 2015 to extend its estimated useful economic life by approximately 15 years. The Well Enhancer has performed well intervention, abandonment and CT services since it joined our fleet in 2009.

The Q7000 semi-submersible riser-based well intervention vessel commenced operations in January 2020, ~~performing~~operates ~~various~~globally ~~integrated~~with ~~well~~projects ~~intervention~~conducted ~~operations~~in ~~offshore~~ Nigeria, ~~and~~New isZealand ~~currently~~and inAustralia, ~~the~~and ~~mobilization~~is ~~phase~~currently ~~for~~performing well intervention work offshore Brazil.

Our Subsea Services Alliance with SLB leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. Through our ~~alliance~~collaboration, we and SLB jointly developed a 15K IRS and the ROAM.

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Robotics

Our Robotics segment provides trenching, seabed clearance, offshore construction and 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~~energy ~~away from a carbon-based economy~~transition. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes 39 work-class ROVs, six trenchers, ~~two~~three IROV boulder grabs, and robotics support vessels chartered on long-term, short-term, flexible and spot bases to facilitate our ROV and trenching operations. We offer our ROVs, trenchers and IROV boulder grabs on a stand-alone basis or on an integrated basis with chartered robotics support vessels.

We have been actively engaged in robotics for over three decades. We operate robotics assets to support offshore energy projects for the renewable energy market and to complement offshore construction, maintenance and well intervention services for the oil and gas market. We often integrate our services with chartered vessels. Our robotics business operates globally, with primary operations in the North Sea, ~~U.S~~the Gulf ~~Coast,~~of ~~U.S. East Coast~~America, Asia Pacific, Brazil and West Africa regions. As global marine construction activity levels increase and as the complexity and water depths of the facilities increase, the ~~use and~~ scope of robotics services has expanded. Our chartered vessels enable us to offer an integrated package to our customers including marine access, ROV services, project management and engineering services. Our robotics assets and experience allow us to meet the technological challenges of our customers’ subsea activities worldwide.

Over the last decade and especially in recent years there has been an increase in offshore activity associated with the growing renewable energy market. As the level of activity for offshore renewable energy projects, including wind farm projects, has increased, so has the need for reliable services and related equipment. Historically, this work was performed by barges and other similar vessels, but these types of services are increasingly being contracted to vessels more suitable for harsh offshore weather conditions where offshore wind farm activity is currently concentrated. We provide cable burial services related to subsea power cable installations as well as seabed clearance and site preparation services around the world using our chartered vessels, trenchers, ROVs and ~~ROVs~~IROV boulder grabs. In ~~2024~~2025, revenues derived from offshore renewable energy contracts accounted for 5149% of our global Robotics segment revenues. We believe that over the long term our robotics business is positioned to continue providing services to a range of clients in the renewable energy market.

Shallow Water Abandonment

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the ~~U.S.~~ Gulf ~~Coast~~of America shelf, including offshore oilfield decommissioning and ‎reclamation, ~~dry tree~~ well ~~P&A services, subsea infrastructure flushing and abandonments (or removals), platform decommissioning and structure removals, subsea site clearance, project management, engineered solutions,~~ intervention, ~~maintenance~~IRM, ~~repair,~~ heavy lift and commercial diving services. In addition to its end-of-life decommissioning services, our Shallow Water Abandonment segment offers services to support the full life cycle of offshore upstream and midstream industries, including oil and gas production through well intervention, CT and pumping, installations and construction, and IRM. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022, a vertically integrated company ~~which~~that offers a diversified fleet of marine assets including nine liftboats, six offshore supply vessels (“OSVs”), three dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat, 20 P&A systems and six CT systems.

Production Facilities

Our Production Facilities segment includes the HP I, the HFRS and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the ~~U.S.~~ Gulf ~~Coast~~of America.

WeThe ~~own and operate the~~ HP I, a ship-shaped dynamically positioned floating production vessel capable of processing up to 45,000 barrels of oil and 80 million cubic feet of natural gas per day., ~~The HP I~~ has been under contract to the Phoenix field operator since February 2013 and is currently under an agreement through at least June 1, ~~2026~~2027.

We developed the HFRS in 2011 as a culmination of our experience as a responder in the 2010 Macondo well control and containment efforts. The HFRS combines our capabilities with certain well control equipment that can be deployed to respond to a well control incident. We are under agreement through March 31, ~~2026~~2027 with various operators to provide access to the HFRS for well control purposes.

Our Production Facilities segment also includes acquired mature deepwater offshore wells and related subsea infrastructure.

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Our Production Facilities segment also includes acquired mature deepwater offshore wells and related subsea infrastructure.

GEOGRAPHIC AREAS

We primarily operate in the ~~U.S~~ Gulf ~~Coast~~of America (deepwater and shelf), ~~U.S. East Coast,~~ Brazil, North Sea, ~~Asia~~West ~~Pacific~~Africa and ~~West~~Asia ~~Africa~~Pacific regions. Our North Sea operations and our ~~U.S.~~ Gulf ~~Coast~~of America shelf operations are usually subject to seasonal changes in demand, which generally ~~peaks~~peak in the summer months and ~~declines~~decline in the winter months. See Note 14 for ~~revenues~~disclosures asregarding ~~well~~revenues asand property and equipment by geographic location.

CUSTOMERS

Our customers consist primarily of major, national and independent oil and gas producers and suppliers, pipeline transmission companies, renewable energy companies and offshore engineering and construction firms. The level of services required by any particular customer depends, in part, on the size of that customer’s budget in a particular year. Consequently, athe ~~customer~~level ~~that~~of ~~accounts~~revenues ~~for~~from a ~~significant~~particular ~~portion~~customer ofmay ~~revenues~~be significant in one ~~fiscal~~ year ~~may~~but ~~represent~~not ansignificant ~~immaterial portion of revenues~~ in ~~subsequent~~other ~~fiscal~~ years. The percentages of consolidated revenues from major customers (those representing 10% or more of our consolidated revenues) are as follows: ~~2024~~2025 — Shell (1218%) and ~~Talos~~Petrobras (1210%); ~~2023~~2024 — ~~Apache~~Shell (1112%) and ~~Shell~~Talos (1012%); and ~~2022~~2023 — Apache (11%) and Shell (1510%). We provided services to over 9080 customers in ~~2024~~2025.

COMPETITORS

The oilfield services and renewables services markets are highly competitive. Price and the ability to access specialized vessels, systems and other equipment, attract and retain skilled personnel, and operate safely are important factors to competing in these markets. Our principal competitors in well intervention are international drilling contractors and also include AKOFS Offshore, Baker Hughes, C-Innovation, Expro, Oceaneering, TechnipFMC, Trendsetter, and Well-Safe Solutions ~~and international drilling contractors~~. Our principal competitors in the robotics business include Asso Divers, Atlantic Marine, Briggs Marine, C-Innovation, DeepOcean, DOF Subsea, Fugro, James Fisher, Oceaneering and UTROV. Our principal competitors in shallow water abandonment include Aries Marine, C-Dive, Cardinal Services, Chet Morrison, Crescent Energy Services, Laredo Offshore Services, Manson Gulf, Offshore Liftboats, Offshore Marine Contractors, Seacor, Shore Offshore, Supreme Energy, Turnkey Offshore Project Services and White Fleet. Our competitors may have more or differing financial, personnel, technological and other resources available to them.

SUSTAINABILITY

Our vision as a preeminent offshore ~~Energy~~energy ~~Transition~~transition company is supported by our sustainability priorities of People, Governance, Health and Safety, Value Creation, Environmental Impact, and Ethics. Sustainability initiatives and disclosures are embedded in these business values and priorities with a top-down approach led by management and our Board of Directors (our “Board”). Each Committee of our Board oversees elements designed to support ~~our~~these ~~sustainability~~ priorities. Specifically, as a stated responsibility of its charter, our Board’s Corporate Governance and Nominating Committee (the “Governance Committee”) oversees, assesses and reviews the disclosure and reporting of any sustainability matters, ~~including~~impacting ~~with respect to climate change, regarding~~ the Company’s business and industry, ~~and~~including ~~that~~with ~~committee’s~~respect ~~charter~~to ~~formally~~climate ~~incorporates oversight of sustainability matters as a stated responsibility~~change. Sustainability is reviewed on an ongoing basis in conjunction with environmental, health and safety, and social matters at each Governance Committee meeting. Our Board’s Audit Committee (the “Audit Committee”) oversees Helix’s compliance program, enterprise risk management processes, including business continuity, and cybersecurity risk and prevention management. Lastly, our Board’s Compensation Committee (the “Compensation Committee”) oversees executive management performance and compensation, including sustainability key performance indicators and human capital management.

While the Board and its ~~Committees~~committees oversee strategic sustainability initiatives with respect to Helix’s strategy surrounding biodiversity and climate change, our Climate Change Action Committee, comprised of key leaders from Quality, Health, Safety, Environmental (“QHSE”), finance, legal, our business units and management, evaluates Helix’s impact on climate change, implements our go-forward strategies and assists in providing comprehensive disclosures. Our expectations and goals align with the underlying belief that fossil fuels will not be eliminated from consumption, but rather there will be a gradual global transition from relying primarily on fossil fuels to a more balanced approach that includes renewable energy, such as wind farms and other alternative fuels.

We emphasize continual improvement by establishing goals to improve our safety record and increase transparency for our stakeholders. Our services facilitate both extending the value and therefore the life cycle of underutilized wells, which in turn mitigates the need to drill new wells and the responsible transition to additional energy sources. These efforts are described in greater detail on our Corporate Sustainability Platform available at www.helixesg.com/sustainability.

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We emphasize continual improvement by establishing goals to improve our safety record and increase transparency for our stakeholders. We understand that establishing these targets provides value to us as a company and is valued by our stakeholders, and we are committed to providing transparency. In tandem with such disclosures and targets, we have continued to support renewable energy developments. Our services facilitate both the responsible transition from a carbon-based economy and extending the value and therefore the life cycle of underutilized wells, which in turn mitigates the need to drill new wells. These efforts are published in greater detail in our most recent Corporate Sustainability Report, a copy of which is available on the Investor Relations section of our website at www.helixesg.com.

HUMAN CAPITAL MANAGEMENT

As of December 31, ~~2024~~2025, we had 2,~~313~~212 employees. Of our total employees, we had ~~446~~441 employees covered by collective bargaining agreements or similar arrangements. We consider our overall relationships with our employees, suppliers and vendors to be satisfactory. Further, we expect all employees to maintain a work environment free from harassment, discrimination and abuse, and one where employees treat each other with respect, dignity and courtesy. These tenets are further described in our Human Rights Policy and our Supplier and Vendor Expectations, both of which are available on our website at www.helixesg.com/about-helix/our-company/ethics-and-compliance.

Employee Health and Safety

Our corporate vision of a zero-incident workplace is based on the belief that all incidents are preventable and that we manage our working conditions to eliminate unsafe behavior. We have established a corporate culture in which QHSE takes priority over our other business objectives. Everyone at Helix has the authority and the duty to “STOP WORK” they believe is unsafe. Helix management actively encourages critical safety behaviors to avoid injuries to people, environmental disturbances and damage to assets through Hazard Hunts, Behavioral Best Safety Standards, and employee consultations, among other initiatives. Our Health, Safety and Security Statement and Environmental and Energy Statement of Policy are available on our website, located at www.helixesg.com/about-helix/our-company/safety. ~~We empower our employees to feel safe and confident that their safety and the safety of those around them are our primary concern.~~ Our QHSE management systems and training programs were developed based on common industry work practices, and by employees with on-site experience who understand the risk and physical challenges of the offshore work environment. Certain management systems of our business units have been independently assessed and registered compliant with ISO 9000 (Quality Management Systems), ISO 14001 (Environmental Management Systems), and ISO 45001 (Occupational Health and Safety Management Systems).

We undertake to regularly and properly train our staff to be as prepared as possible to perform our operations safely. Our staff receives updated and relevant training required for their jobs, and Helix leadership actively engages staff so that behaviors reflect the training and a critical safety approach. Each vessel and shore-based employee is assigned a Qualifications and Training Matrix that specifies qualifications and training required of the employee. Training is tracked and evaluated for quality assurance. Ongoing and thoughtful employee participation is a vital element in the success of our QHSE processes. While we believe in the strength and effectiveness of our QHSE programs, we continuously review how we can improve our control of QHSE risks through ~~the~~our employees’ behavior and feedback ~~of our employees~~.

Attraction and Retention of Talent

We are committed to attracting and retaining high-performing employees through our diverse talent base and evaluating and promoting throughout our organization based on skills and performance. We seek the best candidates without regard to factors such as race, religion, color, national origin, age, sex, gender, sexual orientation, gender identity, disability, marital status, veteran status, genetic information, socioeconomic background or any other basis that would be in violation of any applicable federal, state, local or international law. We are committed to diversity and inclusion throughout our workforce, and believe that employing people with different backgrounds, experiences and perspectives makes Helix a stronger company. In ~~2024~~2025, our worldwide workforce represented 40 different nationalities. We track tenure and voluntary employee turnover. Weand ~~then~~ use this data to inform our human capital management strategy. As of December 31, ~~2024~~2025, our global voluntary annual turnover rate was 1413%. Further, our Board defines diversity expansively and has determined that it is desirable to have diverse viewpoints, professional experiences, backgrounds and skills on our Board, with the principal qualification of a director being the ability to act effectively on behalf of Company shareholders. Our Board has remained diverse following a long-standing refreshment process. Relevant information regarding our talent attraction and retention can be found in ~~our most recent Corporate Sustainability Report, a copy of which is available on~~ the ~~Investor~~Talent ~~Relations~~Management section of our ~~website~~Corporate Sustainability Platform available at www.helixesg.com/sustainability/people-communities#talent-management.

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Human Rights, Anti-Slavery and Anti-Human Trafficking

We are committed to respecting and protecting human rights everywhere we operate and expect similar standards of suppliers, vendors and partners, including requiring periodic assessments and audits to confirm there is no modern slavery, or human trafficking or underage employees in our supply chains or in any part of our business. Our workplace policies and procedures demonstrate our commitment to acting ethically and with integrity in ~~all~~ our business relationships, and to implementing and enforcing effective systems and controls to prevent slavery and human trafficking from taking place anywhere in our supply chains. We provide periodic Anti-Human Trafficking training for employees to further arm our workforce with the tools to identify and prevent human trafficking. Our Modern Slavery Statement is available on our website, located at www.helixesg.com/modern-slavery-statement and our Statement on Human Rights, as approved by the Board of Directors is available on our website at www.helixesg.com/about-helix/our-company/ethics-and-compliance.

GOVERNMENT REGULATION

Overview

We provide services primarily in the ~~U.S.~~ Gulf ~~Coast~~of America (deepwater and shelf), ~~U.S. East Coast,~~ Brazil, North Sea, ~~Asia~~West ~~Pacific~~Africa and ~~West~~Asia ~~Africa~~Pacific regions, and as such we are subject to numerous laws and regulations, including international treaties, flag state requirements, environmental laws and regulations, requirements for obtaining operating and navigation licenses, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our vessels and other assets operate or are registered, all of which can significantly affect the ownership and operation of our vessels and other assets. We operate mature offshore oil and gas wells, some of which are producing and which ultimately we plan to decommission. Being an owner and operator of wells subjects us to additional regulatory oversight from the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”).

International Conventions

Our vessels are subject to applicable international maritime convention requirements, which include, but are not limited to, the International Convention for the Prevention of Pollution from Ships (“MARPOL”), the International Convention on Civil Liability for Oil Pollution Damage of 1969, the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), the International Convention for the Safety of Life at Sea of 1974 (“SOLAS”), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”), the Code for the Construction and Equipment of Mobile Offshore Drilling Units (the “MODU Code”), and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments (the “BWM Convention”). These regimes are applicable in most countries where we operate; however, the vessel’s flag state and the country where we operate may impose additional requirements, including as described below. In addition, these conventions impose liability for certain environmental discharges, including strict liability in some cases.

U.S. Overview

In the U.S., we are subject to the jurisdiction of the U.S. Coast Guard (the “Coast Guard”), the U.S. Environmental Protection Agency (the “EPA”) as well as state environmental protection agencies for those jurisdictions in which we operate, three divisions of the U.S. Department of the Interior (BOEM, BSEE and the Office of Natural Resources Revenue), and the U.S. Customs and Border Protection (the “CBP”), as well as classification societies such as the American Bureau of Shipping (the “ABS”). We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of employee health and safety for our land-based operations.

International Overview

We provide services globally and accordingly can be subject to local laws and regulations wherever we operate. Those laws and regulations generally govern environmental, labor, health and safety and other matters. The regulatory regimes of the U.K. and Brazil are of particular importance given the locations of our current operations. The U.K. Continental Shelf in the North Sea is regulated by the North Sea Transition Authority (the “NSTA”) in accordance with the Petroleum Act 1998. The NSTA controls the Petroleum Operations Notices with which we comply for various well intervention and subsea construction projects, as required. The NSTA also regulates the environmental requirements for our operations in the North Sea. We are subject to the Oil Pollution Prevention and Control Regulations 2005. In the North Sea, international regulations govern working hours and the working environment, as well as standards for diving procedures, equipment and diver health.

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International Overview

Our operations in Brazil are predominantly regulated by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels, the federal government agency responsible for the regulation of the oil sector. Additional regulatory oversight is provided, among others, by the Brazilian Institute of the Environment and Renewable Natural Resources, which oversees Brazilian environmental legislation, implements the National Environmental Policy and exercises control and supervision of the use of natural resources, the Brazilian Health Regulatory Agency, which regulates products and services subject to health regulations, the Ministry of Labor, which regulates a variety of subjects related to employment and other work permitting matters, and the Brazilian Navy, which regulates maritime operations.

Operating Certification

Each of our vessels is subject to regulatory requirements of the country in which the vessel is registered, also known as the flag state. In addition, the country in which a vessel is operating may have its own requirements with respect to safety and environmental protections. These requirements must be satisfied in order for the vessel to operate. Flag state requirements are largely established by international treaties such as MARPOL, SOLAS, the ISM Code and the MODU Code, and in some instances, specific requirements of the flag state. These include engineering, safety, safe manning and other requirements related to the maritime industry. Each of our vessels is subject to a “class” status with a classification society, with respect to whether the vessel has been built and maintained in accordance with the rules of the classification society and complies with applicable flag state rules and international conventions. Our vessels generally undergo a class survey once every five years. In the U.S., the Coast Guard sets safety standards and is authorized to investigate marine incidents, recommend safety standards, and inspect vessels at will. We are also bound by manning requirements implemented by the Coast Guard for operations on the U.S. Outer Continental Shelf (“OCS”).

Local Content Requirements and Cabotage Rules

We are subject to local content requirements with respect to vessels, equipment and crews utilized in certain of our operations. Governments in some countries, notably in Australia, Brazil and in the West Africa region, establish and enforce such requirements along with other aspects of the energy industries in their respective countries.

A number of jurisdictions where we operate require that certain work may only be performed by vessels built and/or registered in that jurisdiction. In some instances, an exemption may be available, or we may be subject to an additional tax to use a non-local vessel. In the U.S., we are subject to the ~~Coastwise~~Merchant ~~Merchandise~~Marine ~~Statute~~Act of 1920 (commonly ~~known~~referred to as the “Jones Act”), which generally provides that only vessels built in the U.S., owned at least 75% by U.S. citizens, and crewed by U.S. citizen seafarers may transport merchandise between points in the U.S. The Jones Act has been applied to offshore oil and gas and wind farm work in the U.S. through interpretations by the CBP.

~~BOEM~~Offshore ~~and~~Energy ~~BSEE~~Regulation

Our business is affected by laws and regulations as well as changing tax laws and policies relating to the offshore energy industry in general. The operation of oil and gas properties located on the OCS is regulated primarily by BOEM and BSEE. Among other requirements, BOEM may require lessees of OCS properties to post bonds or provide other adequate financial assurance in connection with the P&A of wells located offshore and the removal of production facilities. ~~Following the Deepwater Horizon incident in April 2010, BSEE implemented enhanced standards for companies engaged in the development of offshore oil and gas wells.~~ As an owner and operator of wells located on the OCS, we maintain a BSEE-approved Oil Spill Response Plan. BSEE also oversees requirements relating to well control equipment utilized during intervention and decommissioning operations. As a provider of well control equipment, we are subject to these regulations for operation, maintenance and surface and subsea testing of our equipment during intervention and decommissioning operations.

Other Regulatory Impact

Additional proposals and proceedings before various international, federal and state regulatory agencies and courts could affect the energy industry, including curtailing production and demand for fossil fuels. We cannot predict when or whether any such proposals may become effective, or how they will be interpreted or enforced.

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Other Regulatory Impact

ENVIRONMENTAL REGULATION

Overview

Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce these laws that are often complex, costly to comply with, and carry substantial administrative, civil and possibly criminal penalties for compliance failure. Under these laws and regulations, we may be liable for remediation or removal costs, damages, civil, criminal and administrative penalties and other costs associated with releases of hazardous materials (including oil) into the environment, and that liability may be imposed on us even if the acts that resulted in the releases were in compliance with all applicable laws at the time those acts were performed. Some of the environmental laws and regulations applicable to our business operations are discussed below, but this discussion does not cover all environmental laws and regulations that govern or otherwise affect our operations.

MARPOL

The U.S. is one of approximately 175 member countries party to the International Maritime Organization (“IMO”), an agency of the United Nations responsible for developing measures to improve the safety and security of international shipping and to prevent marine pollution from ships. The IMO negotiated MARPOL, which imposes on the shipping industry environmental standards relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage, and air emissions.

OPA

The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on offshore facility owners or operators in the U.S., and the lessee or permittee of the U.S. area in which an offshore facility is located, as well as owners and operators of vessels. Any of these entities or persons can be “responsible parties” which are strictly liable for removal costs and damages arising from facility and vessel oil spills or threatened spills. Failure to comply with OPA may result in the assessment of civil, administrative and criminal penalties. In addition, OPA requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from those vessels. A number of foreign jurisdictions also require us to present satisfactory evidence of financial responsibility. We address these requirements through appropriate insurance coverage.

Water Pollution

For operations in the U.S., the Clean Water Act imposes controls on the discharge of pollutants into the navigable waters of the U.S. and imposes potential liability for the costs of remediating releases of petroleum and other substances. Permits may be obtained to discharge certain types of pollutants into state and federal waters. The EPA issues Vessel General Permits (“VGPs”) covering discharges incidental to normal vessel operations, including ballast water, and implements various training, inspection, monitoring, recordkeeping and reporting requirements, as well as corrective actions upon identification of each deficiency. Additionally, certain state regulations and VGPs prohibit the discharge of produced waters and sand, drilling fluids, drill cuttings and certain other substances related to the exploration for, and production of, oil and natural gas into certain coastal and offshore waters. Many states have laws analogous to the Clean Water Act and also require remediation of releases of hazardous substances in state waters. Internationally, the BWM Convention covers mandatory ballast water exchange requirements.

Air Pollution and Emissions

A variety of regulatory developments, proposals and requirements and legislative initiatives focused on restricting the emissions of carbon dioxide, methane and other greenhouse gases apply to the jurisdictions in which we operate. Annex VI of MARPOL addresses air emissions, including emissions of sulfur and nitrous oxide, and requires the use of low sulfur fuels worldwide in both auxiliary and main propulsion diesel engines on vessels. The IMO designates the waters off North America as an Emission Control Area, mandating that vessels operating in the U.S. use fuel with a sulfur content no greater than 0.1%. Directives designed to reduce the emission of nitrogen oxides and sulfur oxides have been issued, and can impact both the fuel and engines that may be used onboard vessels.

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Air Pollution and Emissions

A variety of regulatory requirements, proposals and legislative initiatives focused on restricting the emissions of carbon dioxide, methane and other greenhouse gases apply to the jurisdictions in which we operate. Annex VI of MARPOL addresses air emissions, including emissions of sulfur and nitrous oxide, and requires the use of low sulfur fuels worldwide in both auxiliary and main propulsion diesel engines on vessels. Directives designed to reduce the emission of nitrogen oxides and sulfur oxides have been issued, and can impact both the fuel and engines that may be used onboard vessels.

CERCLA

The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) requires the remediation of releases of hazardous substances into the environment in the U.S. and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including owners and operators of contaminated sites where the release occurred and those companies that transport, dispose of or arrange for the disposal of, hazardous substances released at the sites.

OCSLA

The Outer Continental Shelf Lands Act, as amended (“OCSLA”), provides the U.S. government with broad authority to impose environmental protection requirements applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations can result in substantial civil and criminal penalties, as well as potential court injunctions that could curtail operations and cancel leases.

Current Compliance and Potential Impact

We believe we are in compliance in all material respects with applicable environmental laws and regulations. We maintain a robust operational compliance program, and we maintain and update our programs to meet or exceed applicable regulatory requirements. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon our capital expenditures, earnings or competitive position. However, changes in environmental laws and regulations, changes in the ways such laws and regulations are interpreted or enforced, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and accordingly there can be no assurance that we will not incur significant environmental compliance costs or liabilities in the future.

See Item 1A. Risk Factors for further information related to governmental and regulatory requirements affecting our business.

INSURANCE MATTERS

Our businesses involve a high degree of operational risk. Hazards such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions and operational hazards such as rigging failures, human error, or accidents are inherent in marine operations. These hazards can cause marine and subsea operational equipment failures resulting in personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and the suspension of operations. Damages arising from such occurrences may result in claims that could be significant.

As discussed below, we maintain insurance policies to cover some of our risk of loss associated with our business. We maintain ~~the~~amounts ~~amount~~ of insurance we believe is prudent based on ~~our~~ estimated loss potential. However, not all of our business activities can be insured at the levels we desire because of either limited market availability or unfavorable economics.

Our current insurance programs generally cover a 12-month period beginning July 1 each year.

We maintain Hull and Increased Value insurance, which provides coverage for physical damage up to an agreed amount for each vessel. We also carry Protection and Indemnity insurance, which covers liabilities arising from the operation of vessels, and General Liability insurance, which covers liabilities arising from general operations. Onshore employees are covered by Workers’ Compensation, and offshore employees and marine crews are covered by a Maritime Employers Liability (“MEL”) insurance policy, which covers Jones Act exposures. We maintain Operator Extra Expense coverage that provides certain coverage per each loss occurrence for a well control issue on oil and gas properties where we are the operator. In addition to these liability policies, we currently carry various layers of Umbrella Liability in excess of primary limits as well as OPA insurance for our offshore oil and gas properties.

We customarily have agreements with our customers and vendors in which each contracting party is responsible for its respective personnel. Under these agreements we are typically indemnified against third-party claims related to the injury or death of our customers’ or vendors’ personnel, and vice versa. With respect to well work contracted to us, the customer is typically contractually responsible for pollution emanating from the well. We separately maintain additional coverage designed to cover us under certain circumstances against any such third-party claims associated with well control events.

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We ~~receive~~customarily ~~Workers’~~have ~~Compensation,~~agreements ~~MEL~~with ~~and~~our ~~other~~customers ~~insurance~~and ~~claims~~vendors in ~~the~~which ~~normal~~each ~~course~~contracting ofparty ~~business.~~is Weresponsible ~~analyze each claim~~ for its ~~validity,~~respective ~~potential~~personnel. ~~exposure~~Under ~~and~~these ~~estimated~~agreements ~~ultimate~~we ~~liability. Our services~~ are ~~provided~~typically inindemnified ~~hazardous~~against ~~environments~~third-party ~~where~~claims ~~events~~related ~~involving~~to ~~catastrophic~~the ~~damage~~injury or ~~loss~~death of ~~life~~our ~~could~~customers’ ~~occur~~or vendors’ personnel, and ~~claims~~vice ~~arising~~versa. ~~from~~With ~~such~~respect anto ~~event~~well ~~may~~work ~~result~~contracted into ~~our~~us, ~~being~~the ~~named~~customer asis atypically contractually responsible ~~party. We acquire insurance protection that we believe is adequate~~ for ~~our~~pollution ~~business~~emanating ~~operations,~~from ~~although there can be no assurance that~~ the ~~amount~~well. ofWe ~~insurance~~separately wemaintain ~~carry~~additional iscoverage ~~sufficient~~designed to ~~protect~~cover us ~~fully~~under incertain ~~all~~circumstances ~~events~~against toany ~~which we may be liable or that~~ such ~~insurance~~third-party ~~will~~claims ~~continue~~associated towith bewell ~~available~~control ~~at current levels of cost or coverage~~events.

We also are often required by customers to enter into surety bond arrangements or to post standby letters of credit in favor of the customer. Such surety bond arrangements and letters of credit are designed to protect customers against our failure to perform obligations under customer contracts. The terms of such surety bond arrangements or standby letters of credit vary but are generally consistent with industry practice for such agreements.

We receive Workers’ Compensation, MEL and other insurance claims in the normal course of business. We analyze each claim for its validity, potential exposure and estimated ultimate liability. Our services are provided in hazardous environments where events involving catastrophic damage or loss of life could occur, and claims arising from such an event may result in our being named as a responsible party. We maintain insurance protection that we believe is adequate for our business operations.

WEBSITE AND OTHER AVAILABLE INFORMATION

We maintain a website on the Internet with the address of www.helixesg.com. Copies of this Annual Report for the year ended December 31, ~~2024~~2025, previous and subsequent copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, and any amendments thereto, are or will be available free of charge at our website as soon as reasonably practicable after they are filed with, or furnished to, the SEC. In addition, the Investor Relations section of our website contains copies of our Code of Business Conduct and Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers and our Corporate Sustainability Report. We make our website content available for informational purposes only. Information contained on our website is not part of this report and should not be relied upon for investment purposes. Please note that prior to March 6, 2006, the name of the Company was Cal Dive International, Inc. We satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Business Conduct and Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers and any waiver from any provision of those codes by posting that information in the Investor Relations section of our website at www.helixesg.com.

The SEC maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.

We satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Business Conduct and Ethics and our Code of Ethics for Chief Executive Officer and Senior Financial Officers and any waiver from any provision of those codes by posting that information in the Investor Relations section of our website at www.helixesg.com.

CERTAIN DEFINITIONS

Defined below are certain terms helpful to understanding our business that are located throughout this Annual Report:

Artificial Intelligence (AI): An engineered system that analyzes large data sets to independently generate content, predictions, or decisions intended to achieve specific objectives and influence operations.

Bureau of Ocean Energy Management (BOEM): BOEM is responsible for managing environmentally and economically responsible development of U.S. offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies.

Bureau of Safety and Environmental Enforcement (BSEE): BSEE is responsible for safety and environmental oversight of U.S. offshore oil and gas operations, including permitting and inspections of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs.

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Coiled tubing (CT) system: A continuous length of steel tubing (CT), typically between 1” and 3.25” in diameter, wound onto a large reel together with an injector head, control console, power supply and well control stack. The CT is run inside a well’s production tubing primarily for debris cleanout, pumping fluids or fishing operations though there are numerous other applications.

Decommissioning: The process of plugging and abandoning oil and gas wells and removing all associated infrastructure (pipelines, platforms, etc.). This is the final stage of oil and gas operations and typically occurs when all of the associated wells have reached the end of their useful production lives.

Deepwater: Water depths exceeding 1,000 feet.

Dynamic Positioning (DP): Computer directed thruster systems that use satellite-based positioning and other positioning technologies to provide the proper counteraction to wind, current and wave forces enabling a vessel to maintain its position without the use of anchors.

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DP2: Two DP systems on a single vessel providing the redundancy that allows the vessel to maintain position even in the absence of one DP system.

DP3: DP control system comprising a triple-redundant controller unit and three identical operator stations. The system is designed to withstand fire or flood in any one compartment. Loss of position should not occur from any single failure.

Dive support vessel (DSV): A vessel used as a floating base for commercial diving projects, with the basic requirements to keep station accurately and reliably throughout the diving operation.

Heavy lift derrick barge: A vessel with a crane capacity to lift large, heavy objects, primarily used for installation or removal of large offshore structures. Lifting capacities typically range from 500 to over 2,000 tons, compared to construction vessels which generally have less than 250 ton lifting capacity.

Intervention Riser System (IRS): A subsea system that establishes a direct connection from a well intervention vessel, through a rigid riser, to a conventional or horizontal subsea tree in depths up to 10,000 feet. An IRS can be utilized for wireline intervention, production logging, CT operations, well stimulation, and full P&A operations, and provides well control in order to safely access the well bore for these activities.

Intervention system: A subsea system that establishes a direct connection from a well intervention vessel to a subsea well in order to provide well control to safely access the well bore for well intervention activities. Intervention systems include Intervention Riser Systems (IRSs), Subsea Intervention Lubricators (SILs) and the Riserless Open-water Abandonment Module (ROAM).

I-plough trencher: A pre-lay plough spread with the capability to perform boulder clearance, pre-cut trenching and backfill services once the cable, umbilical or pipeline has been laid.

IROV boulder grab: A subsea grab tool with the capability to perform boulder clearance and debris removal.

Liftboat: A self-propelled offshore vessel with moveable legs capable of elevating its hull above the surface of the sea to create a stable working platform as opposed to a floating vessel. These vessels are equipped with living quarters, open deck space and at least one crane for lifting operations.

Offshore support vessel (OSV): A specially designed vessel for the logistical servicing of offshore platforms and subsea installations.

Plug and Abandonment (P&A): P&A operations usually consist of placing several cement plugs in the well bore to isolate the reservoir and other fluid-bearing formations when a well reaches the end of its lifetime.

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P&A system: A set of surface equipment, typically consisting of wireline, pumps, cement blenders and tanks, that is used for placement of mechanical and/or cement plugs in the well bore to P&A a well.

QHSE: Quality, Health, Safety and Environmental programs designed to protect the environment, safeguard employee health and avoid injuries.

Riserless Open-water Abandonment Module (ROAM): A subsea system designed to act as a barrier to the environment during upper abandonment operations and during production tubing removal in open water, when run as a complement to an IRS. ROAM provides the ability to capture contaminants or gas within the system and circulate them back to the safe handling systems on board the vessel, such that no well contaminants are released into the environment.

Remotely Operated Vehicle (ROV): A robotic vehicle used to complement, support and increase the efficiency of diving and subsea operations and for tasks beyond the capability of manned diving operations. ROV also includes ROVDrill, a seabed-based geotechnical investigation system deployed with an ROV system capable of taking cores from the seafloor in water depths up to 6,500 feet.

15Riserless Open-water Abandonment Module (ROAM): A subsea system designed to act as a barrier to the environment during upper abandonment operations and during production tubing removal in open water, when run as a complement to an IRS. ROAM provides the ability to capture contaminants or gas within the system and circulate them back to the safe handling systems on board the vessel, such that no well contaminants are released into the environment.

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Saturation diving: Divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site, generally required for work in water depths between 200 and 1,000 feet.

Shallow water: Generally, water depths less than 1,000 feet, including the ~~U.S.~~ Gulf ~~Coast~~of America shelf.

Site clearance: Activities utilizing ROVs for the safe removal of obstructions, such as boulders, unexploded ordnance (UXOs) and debris, that would inhibit the construction of an offshore wind farm.

Spot vessels: Vessels not owned or under term charters but contracted on a short-term basis typically to perform specific projects.

Subsea Intervention Lubricator (SIL): A riserless subsea system designed to provide access to the well bore while providing well control safety for activities that do not require a riser conduit. A SIL can be utilized for wireline, logging, light perforating, zone isolation, plug setting and removal, and decommissioning, and it facilitates access to subsea wells from a vessel to provide safe, efficient and cost effective riserless well intervention and abandonment solutions.

Trencher or trencher system: A subsea robotics system capable of providing post-lay trenching, inspection, burial and maintenance of submarine cables, flowlines and umbilicals in water depths of 30 to 7,200 feet across a range of seabed and environmental conditions.

Well intervention services: Activities related to well maintenance and production management and enhancement services. Our well intervention operations include the utilization of slickline and electric line services, pumping services, specialized tooling and CT services.

Item 1A. Risk Factors

Shareholders should carefully consider the following risk factors in addition to the other information contained herein. We operate globally in challenging and highly competitive markets and thus our business is subject to a variety of risks. The risks and uncertainties described below are not the only ones facing Helix. We are subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that, as of the date of this Annual Report, we believe are not as significant as the risks described below. You should be aware that the occurrence of the events described in these risk factors and elsewhere in this Annual Report could have a material adverse effect on our business, financial position, results of operations and cash flows.

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MARKET AND INDUSTRY RISKS

Our business is adversely affected by low oil and natural gas prices, which occur in a cyclical oil and gas market that continues to experience volatility.

Our services are substantially affected by the condition of the oil and gas market, and in particular, the willingness of our oil and gas ~~companies~~customers to make capital and other expenditures for offshore exploration, development, drilling and production operations. Although our services are used for other operations during the entire life cycle of a well, when industry conditions are unfavorable, oil and gas companies typically reduce their budgets for expenditures on all types of operations and defer certain activities to the extent possible.

The levels of both capital and operating expenditures largely depend on the prevailing view of future oil and natural gas prices, which is influenced by numerous factors, including:

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worldwide economic activity and general economic and business conditions, including the interest rate environment and cost of capital as well as access to capital and capital markets;

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the global supply and demand for oil and natural gas;

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

●

actions taken by the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”);

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laws, regulations and policies directly related to the industries in which we provide services, including regulations on decommissioning obligations, restrictions on oil and gas leases, and their interpretation and enforcement;

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

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

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the level of excess production capacity;

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

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the environmental and social sustainability of the oil and gas sector and the perception thereof, including within the investing community;

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the sale and expiration dates of offshore leases globally;

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

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

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potential acceleration of the development of alternative fuels;

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

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weather conditions and natural disasters, including with respect to marine operations;

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the occurrence or threat of an epidemic or pandemic disease and any related governmental response;

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environmental and other governmental regulations; and

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tax laws, regulations and policies.

A period of low levels of activity by offshore oil and gas operators may adversely affect demand for our services, the utilization and/or rates we can achieve for our assets and services, and the outlook for our industry in general, all of which could lead to lower utilization of available vessels or similar assets and correspondingly downward pressure on the rates we can charge for our services. Given that the oil and gas business is adversely affected by low oil prices, such conditions would negatively impact oil and gas companies’ willingness and ability to make capital and other expenditures. Additionally, our customers, in reaction to negative market conditions, may seek to negotiate contracts at lower rates, both during and at the expiration of the term of our contracts, to cancel earlier work and shift it to later periods, to cancel their contracts with us even if cancellation involves their paying a cancellation fee, or to delay or refuse payment for our services. The extent of the impact of these conditions on our results of operations and cash flows depends on the strength of our industry environment and the demand for our services.

Our business and financial performance are subject to risks related to global economic conditions, geopolitical developments and international conflict.

We serve customers in many countries around the world and accordingly our business and operations are subject to the effects of global economic conditions, geopolitical developments and international conflicts. Geopolitical and international instability could lead to sanctions, tariffs, trade wars, embargoes and regional unrest, and related governmental actions could affect the global economy, our customers and our business. In addition, shifting geopolitical conditions could affect U.S. or foreign policies and priorities which could adversely impact our customers and our business. For example, in 2022, the U.K. enacted the Energy (Oil and Gas) Profits Levy of 2022 imposing a windfall tax on profits for oil and gas companies operating in the U.K. and U.K Continental Shelf, which legislation could further adversely affect the operation and capital spending of our customers in the North Sea. In January 2025, a Presidential Memorandum was issued in the U.S. temporarily withdrawing wind energy leasing in the U.S. Outer Continental Shelf (“2025 Wind Energy Ban”) which could affect projects in the offshore wind industry.

We continue to actively monitor ongoing and potential military hostilities globally including in Ukraine, Israel, the Red Sea and the Middle East, as well as applicable laws, sanctions and trade control restrictions resulting therefrom. Any sanctions measures and increased governmental oversight and enforcement activities could adversely affect the global economy and supply chains as well as the oil and gas sector generally. The extent to which our operations and financial results may be affected by any such hostilities will depend on various factors, including the extent and duration of the conflicts and their related effects on operating and capital spending by our customers.

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Our business and financial performance are subject to risks related to global economic conditions, geopolitical developments and international conflict.

We serve customers in many countries around the world and accordingly our business and operations are subject to the effects of global economic conditions, geopolitical developments and international conflicts. Geopolitical and international instability could lead to sanctions, tariffs, trade wars, embargoes and regional unrest, and related governmental actions could affect the global economy, our customers and our business. In addition, shifting geopolitical conditions could affect U.S. or foreign policies and priorities which could adversely impact our customers and our business. For example, in 2022, the U.K. enacted the Energy (Oil and Gas) Profits Levy of 2022 (“Energy Profits Levy”) imposing a windfall tax on profits for oil and gas companies operating in the U.K. and U.K Continental Shelf. In November 2024, the U.K. increased the rate of the Energy Profits Levy on oil and gas companies to 38% and extended the period to which the Energy Profits Levy applies until March 31, 2030. The Energy Profits Levy has and could further adversely affect the operation and capital spending of our customers in the North Sea. In January 2025, a Presidential Memorandum was issued in the U.S. temporarily withdrawing wind energy leasing in the U.S. Outer Continental Shelf (“2025 Wind Energy Ban”) and the Department of the Interior has since announced a separate pause on large-scale offshore wind projects. Due to ongoing judicial proceedings there is continued uncertainty on projects in the offshore wind industry including our operations on the U.S. East Coast.

We continue to actively monitor ongoing and potential military hostilities globally including in Ukraine, Israel, Iran, South America, the Red Sea and the Middle East, as well as applicable laws, sanctions and trade control restrictions resulting therefrom. Any sanctions measures and increased governmental oversight and enforcement activities could adversely affect the global economy and supply chains as well as the oil and gas sector generally. The extent to which our operations and financial results may be affected by any such hostilities will depend on various factors, including the extent and duration of the conflicts and their related effects on operating and capital spending by our customers.

Our renewables business may be adversely affected by industry-specific economic, regulatory and market factors.

Our services to the renewable energy sector and offshore wind farm developments consist primarily of subsea cable trenching and burial as well as seabed clearance and preparation services provided by our Robotics segment. 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, and expansion of offshore renewable energy projects to deeper water and other regions. The offshore renewable energy sector also has country-specific regulations, restrictions, incentives, subsidies and tax credits, that if revised negatively, can affect our customers’ needs for our services. Stagnant or declining economic conditions, which may slow global electricity demand, can negatively affect developer spending towards renewable energy projects. Finally, the pace of innovation and evolution in the offshore wind market can affect our ability to continue offering services to this segment.

We are subject to the effects of changing prices.

Inflation rates have been relatively low and stable over the previous three decades; however, inflation rates rose significantly between 2021 and 2024 due in part to supply chain disruptions and the effects of the ~~COVID-19~~global health pandemic and more recently relating to political and economic turmoil resulting from the proliferation of tariffs and escalation of global trade tensions. Although inflation rates have stabilized at a moderate level, future economic shocks, such as those due to tariffs and trade wars, could increase inflation levels going forward. We bear the costs of operating and maintaining our assets, including labor and material costs as well as ~~recertification~~certification and dry dock costs. Although we may be able to reduce some of our exposure to price increases through the rates we charge, competitive market pressures may affect our ability to pass along price adjustments, which may result in reductions in our operating margins and cash flows in the future.

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BUSINESS AND OPERATIONAL RISKS

Our backlog may not be ultimately realized for various reasons, our contracts may be terminated early, and our call-off work may be terminated earlier than expected.

As of December 31, ~~2024~~2025, backlog for our services supported by written agreements or contracts totaled $1.43 billion, of which $~~681~~694 million is expected to be performed in ~~2025~~2026.

We may not be able to perform under our contracts for various reasons giving our customers certain contractual rights under their contracts with us, which ultimately could include termination of a contract. In addition, our customers may seek to cancel, terminate, suspend or renegotiate our contracts, or our projects in Helix Alliance subject to call-off orders may be terminated earlier than expected, in the event of our customers’ diminished demand for our services due to global or industry conditions. Some of these contracts provide for no cancellation fee or a cancellation fee that is substantially less than the expected rates from the contracts. In addition, some of our customers could experience liquidity issues or could otherwise be unable or unwilling to perform under a contract, in which case a customer may repudiate or seek to cancel or renegotiate the contract. The repudiation, early cancellation, termination or renegotiation of our contracts by our customers, or the termination or reduction of call-off work, could have a material adverse effect on our financial position, results of operations and cash flows. Furthermore, we may incur capital costs, we may charter vessels for the purpose of performing these contracts, and/or we may forgo or not seek other contracting opportunities in light of these contracts.

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A large portion of our current backlog is concentrated in a small number of long-term contracts that we may fail to renew or replace.

Although historically our service contracts were of relatively short duration, over the past few years we performed a number of long-term contracts. We currently have contracts with ~~five~~six customers that represent approximately 9082% of our total backlog as of December 31, ~~2024~~2025. Any cancellation, termination or breach of those contracts would have a larger impact on our operating results and financial condition than of our shorter-term contracts. Furthermore, our ability to extend, renew or replace our long-term contracts when they expire or obtain new contracts as alternatives, and the terms of any such contracts, will continue to depend on various factors, including market conditions and the specific needs of our customers. Given the historically cyclical nature of the oil and gas market, as we have experienced, we may not be able to extend, renew or replace such contracts or we may be required to extend, renew or replace expiring contracts or obtain new contracts at rates that are below our existing contract rates, or that have other terms that are less favorable to us than our existing contracts. Failure to extend, renew or replace expiring contracts or secure new contracts at comparable rates and with favorable terms could have a material adverse effect on our financial position, results of operations and cash flows.

Our operations involve numerous risks, which could result in our inability or failure to perform operationally under our contracts and result in reduced revenues, contractual penalties and/or contract termination.

Our equipment and services are very technical and the offshore environment poses significant challenges. Performing the work we do pursuant to the terms of our contracts can be difficult for various reasons, including equipment failure or reduced performance, human error, third-party failure or other fault, design flaws, weather, water currents or other physical conditions. Operating in new locations may also present incremental complications. Any of these factors could lead to performance concerns as well as disputes with our customers. The nature of offshore operations requires our offshore crew members as well as our customers and vendors to regularly travel to and from the vessels. The occurrence or threat of an epidemic or pandemic may impede our ability to execute such crewing or crew changes, which could lead to vessel downtime or suspension of operations, which may be beyond our control. Failure to perform in accordance with contract specifications can result in reduced rates (or zero rates), customer disputes, contractual penalties, and ultimately, termination in the event of sustained non-performance. As a large portion of our revenues are concentrated with a relatively small number of contracts, any reduced revenues and/or contract termination due to our inability or failure to perform operationally could have a material adverse effect on our financial position, results of operations and cash flows.

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Our customers, suppliers and other counterparties may be unable to perform their obligations.

Industry uncertainty and domestic and global economic conditions, including the financial condition of our customers, suppliers, lenders, insurers and other financial institutions generally, could jeopardize the ability of such parties to perform their obligations to us, including obligations to pay amounts owed to us and to deliver goods and/or services to us in a timely manner. In the event one or more of our customers and/or suppliers is adversely affected by a global health emergency ~~similar to the COVID-19 pandemic~~, our business with them may be affected. We may face an increased risk of customers deferring work, declining to commit to new work, asserting claims of force majeure and/or terminating contracts, or our customers’, subcontractors’ or partners’ inability to make payments or remain solvent. We may also face supply chain issues such as loss of access to spares and equipment, which could cause operational delays and loss of revenue.

Although we assess the creditworthiness of our counterparties, a variety of conditions and factors could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts. In particular, our Robotics and Helix Alliance businesses tend to do business with smaller customers that may not be capitalized or insured to the same extent as larger operators and that may be more exposed to financial loss in an uncertain economic environment. In addition, we may offer favorable payment or other contractual terms to customers in order to secure contracts. These circumstances may lead to collection issues that could impact our financial results and liquidity and lead to losses.

The inability of our customers, suppliers and other counterparties to perform under our various contracts, credit agreements and insurance policies may materially adversely affect our business, financial position, results of operations and cash flows.

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We may own assets with costs that cannot be recouped if the assets are not under contract, and time chartering vessels requires us to make payments regardless of utilization of and revenue generation from those vessels.

We own vessels, systems and other equipment for which there are costs, including maintenance, manning, insurance and depreciation. We may also construct assets without first obtaining service contracts covering the cost of those assets. Our failure to secure contracts for vessels or other assets could materially adversely affect our financial position, results of operations and cash flows.

Further, we charter our robotics support vessels under time charter agreements. We also have entered into long-term charter agreements for the ~~Siem~~Sea Helix 1 and Siem Helix 2 vessels. Should our contracts with customers be canceled, terminated or breached and/or if we do not secure work for the chartered vessels, we are still required to make charter payments. Making those payments absent revenue generation could have a material adverse effect on our financial position, results of operations and cash flows.

Asset upgrade, modification, refurbishment, repair, dry dock, vessel acquisition, fleet replacement and construction projects, and customer contractual acceptance of vessels, systems and other equipment, are subject to risks, including delays, cost overruns, loss of revenue, significant capital cost, and failure to commence or maintain contracts.

We incur significant upgrade, modification, refurbishment, repair and dry dock expenditures on our fleet from time to time. We also construct or make capital improvements to other assets. While some of these capital projects are planned, some are unplanned. Additionally, as assets age, they are more likely to be subject to higher maintenance and repair activities. These projects are subject to the many risks, including delay and cost overruns, inherent in any large capital project. We may also need to construct or acquire new vessels to maintain our current fleet size and the age of our fleet and the cost of constructing or adding a new vessel to our fleet can be substantial.

Actual capital expenditures could materially exceed our estimated or planned capital expenditures. Moreover, assets undergoing upgrades, modifications, refurbishments, repairs or dry docks may not earn revenue during the period they are out of service. Any significant period of such unplanned activity for our assets could have a material adverse effect on our financial position, results of operations and cash flows.

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In addition, delays in the delivery of vessels and other assets being constructed or undergoing upgrades, modifications, refurbishments, repairs, or dry docks may result in delay in customer acceptance and/or contract commencement, resulting in a loss of revenue and cash flow to us, and may cause our customers to seek to terminate or shorten the terms of their contracts with us and/or seek damages under applicable contract terms. In the event of termination or modification of a contract due to late delivery, we may not be able to secure a replacement contract on favorable terms, if at all, which could have a material adverse effect on our business, financial position, results of operations and cash flows.

We may not be able to compete successfully against current and future competitors.

The industries in which we operate are highly competitive. An oversupply of offshore drilling rigs coupled with a significant slowdown in industry activities results in increased competition from drilling rigs as well as substantially lower rates on work that is being performed. Several of our competitors are larger and have greater financial and other resources to better withstand a prolonged period of difficult industry conditions. In order to compete for customers, these larger competitors may undercut us by reducing rates to levels we are unable to withstand. Further, certain other companies may seek to compete with us by hiring vessels of opportunity from which to deploy modular systems and/or be willing to take on additional risks. With respect to our Helix Alliance business there may be lower barriers to entry into a market that historically has been serviced at least in part by smaller companies. If other companies relocate or acquire assets for operations in the regions in which we operate, levels of competition may increase further and our business could be adversely affected.

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Our North Sea and Helix Alliance businesses typically decline in the winter, and weather can adversely affect our operations.

Marine operations conducted in the North Sea and the ~~U.S.~~ Gulf ~~Coast~~of America shelf are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest North Sea vessel utilization rates during the summer and fall when weather conditions are more favorable for offshore operations, and we typically have experienced our lowest North Sea utilization rates in the first quarter. Helix Alliance experiences a slower winter season in its diving and certain vessel operations. As is common in our industry, where we do have utilization in these seasonal markets, we may bear the risk of delays caused by adverse weather conditions. Our results in any one quarter are not necessarily indicative of annual results or continuing trends.

Certain areas in which we operate experience unfavorable weather conditions including hurricanes and extreme storms on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the ~~U.S.~~ Gulf ~~Coast~~of America and the North Sea are susceptible to damage and/or total loss by these weather conditions. Damage caused by high winds and turbulent seas could potentially cause us to adjust service operations or curtail operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these weather conditions, we may experience disruptions in our operations if our personnel is adversely impacted, or because customers may adjust their activities due to damage to their assets, platforms, pipelines and other related facilities.

The operation of marine vessels is risky, and we do not have insurance coverage for all risks.

Vessel-based offshore services involve a high degree of operational risk. Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. Damage arising from such occurrences may result in assertions of our liability. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful liability claim for which we are not fully insured could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, we can provide no assurance that we will be able to maintain adequate insurance in the future at rates that we consider reasonable. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. For example, insurance carriers require broad exclusions for losses due to war risk and terrorist acts, and limitations for wind storm damage. The current insurance on our assets is in amounts approximating replacement value. In the event of property loss due to a catastrophe, mechanical failure, collision or other event, insurance may not cover a substantial loss of revenue, increased costs and other liabilities, and therefore the loss of any of our assets, or damage asserted to have been caused by our assets, could have a material adverse effect on us.

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Our oil and gas operations involve a high degree of operational, contractual and financial risk, particularly risk of personal injury, damage, loss of equipment and environmental incidents.

Engaging in oil and gas production and transportation operations subjects us to certain risks inherent in the ownership and operation of oil and gas wells, including but not limited to uncontrolled flows of oil, gas, brine or well fluids into the environment; blowouts; cratering; pipeline or other facility ruptures; mechanical difficulties or other equipment malfunction; fires, explosions or other physical damage; hurricanes, storms and other natural disasters and weather conditions; and pollution and other environmental damage; any of which could result in substantial losses to us. Although we maintain insurance against some of these risks, we cannot insure against all possible losses. Furthermore, such operations necessarily involve some degree of contractual counterparty risk, including for the transportation, marketing and sale of such production, and to the extent we have partners in any of the properties we own or operate. As a result, any damage or loss not covered by our insurance could have a material adverse effect on our financial condition, results of operations and cash flows.

Our customers may be unable or unwilling to indemnify us.

Consistent with standard industry practice, we typically seek to obtain contractual indemnification from our customers whereby they agree to protect and indemnify us for liabilities resulting from various hazards associated with offshore operations. We can provide no assurance, however, that we will obtain such contractual indemnification or that our customers will be willing or financially able to meet their indemnification obligations.

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Our operations outside of the U.S. subject us to additional risks.

Our operations outside of the U.S. are subject to risks inherent in foreign operations, including:

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the loss of revenue, property and equipment from expropriation, nationalization, war, insurrection, acts of terrorism and other political risks;

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increases in taxes and governmental royalties;

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laws and regulations affecting our operations, including with respect to customs, assessments and procedures, and similar laws and regulations that may affect our ability to move our assets and/or personnel in and out of foreign jurisdictions;

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renegotiation or abrogation of contracts with governmental and quasi-governmental entities;

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changes in laws and policies governing operations of foreign-based companies;

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currency exchange restrictions and exchange rate fluctuations;

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global economic cycles;

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restrictions or quotas on production and commodity sales;

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limited market access;

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trade and labor unions as well as local content requirements; and

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other uncertainties arising out of foreign government sovereignty over our international operations.

Certain countries have in place or are in the process of developing complex laws for foreign companies doing business in these countries. Some of these laws are difficult to interpret, making compliance uncertain, and others increase the cost of doing business, which may make it difficult for us in some cases to be competitive. The combination of such laws with the local requirements have further increased the challenges of doing business in these countries. In addition, laws and policies of the U.S. affecting foreign trade, taxation and other commercial activity may adversely affect our international operations.

Failure to protect our intellectual property or other technology may adversely affect our business.

Our industry is highly technical. We utilize and rely on a variety of advanced assets and other tools, such as our vessels, DP systems, intervention systems, ROVs and trenchers, to provide customers with services designed to meet the technological challenges of their subsea activities worldwide. In some instances we hold intellectual property (“IP”) rights related to our business. We rely significantly on proprietary technology, processes and other information that are not subject to IP protection, as well as IP licensed from third parties. We employ confidentiality agreements to protect our IP and other proprietary information, and we have management systems in place designed to protect our legal and contractual rights. We may be subject to, among other things, theft or other misappropriation of our IP and other proprietary information, challenges to the validity or enforceability of our or our licensors’ IP rights, and breaches of confidentiality obligations. These risks are heightened by the global nature of our business, as effective protections may be limited in certain jurisdictions. Although we endeavor to identify and protect our IP and other confidential or proprietary information as appropriate, there can be no assurance that these measures will succeed. Such a failure could result in an interruption in our operations, increased competition, unplanned capital expenditures, and exposure to claims. Any such failure could have a material adverse effect on our business, competitive position, financial position, results of operations and cash flows.

Climate change might adversely impact our business operations and/or our supply chain.

Scientific consensus shows that carbon dioxide and other greenhouse gases in the atmosphere have caused and will in the future cause changes in weather patterns around the globe. Climatologists predict these changes will result in the increased frequency of extreme weather events and natural disasters which could disrupt our business operations or those of our customers or suppliers. In addition, concern about climate change and greenhouse gases may result in new or additional legal, legislative, and/or regulatory requirements designed to reduce or mitigate the effects of climate change on the environment. Any such new requirements could increase our operating costs and impede our ability to provide services to our customers.

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~~The~~may ~~actual~~be orlimited ~~perceived~~in ~~lack~~certain ofjurisdictions. ~~sustainability~~Although ofwe ~~the~~endeavor ~~oil~~to identify and ~~gas~~protect ~~sector,~~our IP and other confidential or ~~our~~proprietary ~~failure~~information toas ~~adequately~~appropriate, ~~implement~~there ~~and~~can ~~communicate~~be ~~initiatives~~no assurance that ~~demonstrate~~these measures will succeed. Such a failure could result in an interruption in our ~~own~~operations, ~~sustainability~~increased competition, ~~may~~unplanned ~~adversely~~capital ~~affect~~expenditures, and exposure to claims. Any such failure could have a material adverse effect on our business, competitive position, financial position, results of operations and cash flows.

~~Sustainability~~Climate ~~initiatives~~change ~~remain~~might ~~important~~adversely factors in assessing a company’s outlook, as investors look to identify factors that they believe inform a company’s ability to create long-term value. The nature of the oil and gas sector in which we predominantly operate may impact ~~the~~our ~~sustainability~~business ~~sentiment~~operations ~~of investors, lenders, customers, other industry participants~~ and individuals, to the extent the global markets value green energy and environmental conservation. Further, we may not succeed in implementing or communicating a sustainability message that is well understood or received. Alternatively, stakeholder sentiment may view sustainability initiatives as shifting attention away from shareholder value-oriented and profit-focused efforts, which could lead to a negative perception. As a result we may experience diminished reputation or sentiment, reduced access to capital markets and/or ~~increased~~our ~~cost~~supply ~~of capital, an inability to attract and retain talent, and loss of customers or vendors~~chain.

The actual or perceived lack of sustainability of the oil and gas sector, our failure to adequately implement and communicate initiatives that demonstrate our own sustainability or our failure to adapt our sustainability efforts to evolving industry demand, may adversely affect our business.

Sustainability initiatives remain important factors in assessing a company’s outlook, as investors look to identify factors that they believe inform a company’s ability to create long-term value. The nature of the oil and gas sector in which we predominantly operate may impact the sustainability sentiment of investors, lenders, customers, other industry participants and individuals, to the extent the global markets value green energy and environmental conservation. Further, we may not succeed in implementing or communicating a sustainability message that is well understood or received.

Alternatively, recent developments indicate a potential slowdown and shift in the direction and pace of the adoption of renewable energy technologies and the reversal of climate change-related regulations. We may adequately message our sustainability, but stakeholder sentiment may view sustainability initiatives as shifting attention away from shareholder value-oriented and profit-focused efforts, which could lead to a negative perception. As a result we may experience diminished reputation or sentiment, reduced access to capital markets and/or increased cost of capital, an inability to attract and retain talent, and loss of customers, employees or vendors.

FINANCIAL AND LIQUIDITY RISKS

Our indebtedness and the terms of our indebtedness could impair our financial condition and our ability to fulfill our debt obligations or otherwise limit our business and financial activities.

As of December 31, ~~2024~~2025, we had consolidated indebtedness with a remaining principal amount of $~~315~~314.26 million. The level of indebtedness may have an adverse effect on our future operations, including:

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limiting our ability to refinance maturing debt or to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements;

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increasing our vulnerability to a general economic downturn, competition and industry conditions, which could place us at a disadvantage compared to our competitors that are less leveraged;

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increasing our exposure to potential rising interest rates for any portion of our borrowings that may be at variable interest rates or at risk to be refinanced at rising rates;

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reducing the availability of our cash flows to fund our working capital requirements, capital expenditures, acquisitions, investments and other general corporate requirements for that portion of our cash flows that may be needed to service debt obligations;

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limiting our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

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limiting our ability to expand our business through capital expenditures or pursuit of acquisition opportunities due to negative covenants in credit facilities that place limitations on the types and amounts of investments that we may make;

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limiting our ability to use, or post security for, bonds or similar instruments required under the laws of certain jurisdictions with respect to, among other things, the temporary importation of vessels, systems and other equipment and the decommissioning of offshore oil and gas properties; and

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limiting our ability to sell or pledge assets or use proceeds from certain asset sales for purposes other than debt repayment.

A prolonged period of weak economic or industry conditions and other events beyond our control may make it difficult to comply with our covenants and other restrictions in agreements governing our debt. If we fail to comply with these covenants and other restrictions, it could lead to reduced liquidity, an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral. These conditions and events may limit our access to the credit markets if we need to replace our existing debt, which could lead to increased costs and less favorable terms, including shorter repayment schedules and higher fees and interest rates.

Because we have certain debt and other obligations, a prolonged period of low demand or rates for our services could lead to a material adverse effect on our liquidity.

A prolonged period of difficult industry conditions, the failure of our customers to expend funds on our services or a longer period of lower rates for our services, coupled with certain fixed obligations that we have related to debt repayment, long-term vessel time charter contracts and certain other commitments related to ongoing operational activities, could lead to a material adverse effect on our liquidity and financial position.

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Lack of access to the financial markets could negatively impact our ability to operate our business.

Access to financing may be limited and uncertain, especially in times of economic weakness, or declining sentiment towards industries we service or our business model. If capital and credit markets are limited, we may be unable to refinance or we may incur increased costs and obtain less favorable terms associated with refinancing of our maturing debt. Also, we may incur increased costs and obtain less favorable terms associated with any additional financing that we may require for future operations. Limited access to the financial markets could adversely impact our ability to take advantage of business opportunities or react to changing economic and business conditions. Additionally, if capital and credit markets are limited, this could potentially result in our customers curtailing their capital and operating expenditure programs, which could result in a decrease in demand for our assets and a reduction in revenues and/or utilization. Certain of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access financial markets as needed to fund their operations. Likewise, our other counterparties may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Continued lower levels of economic activity and weakness in the financial markets could also adversely affect our ability to implement our strategic objectives.

A decline in the offshore energy services market could result in impairment charges.

Prolonged periods of low utilization or low rates for our services could result in the recognition of impairment charges for our assets if future cash flow estimates, based on information available to us at the time, indicate that their carrying value may not be recoverable.

Our international operations are exposed to currency devaluation and fluctuation risk.

Because we are a global company, our international operations are exposed to foreign currency exchange rate risks on all contracts denominated in foreign currencies. For some of our international contracts, a portion of the revenue and local expenses is incurred in local currencies and we may be at risk of changes in the exchange rates between the U.S. dollar and such currencies. We may receive payments in a currency that is not easily traded and may be illiquid, unable to be hedged, or subject to exchange controls that limit the currency’s ability to be converted into a more liquid currency, and we may be at risk of devaluation until such time as the currency may be able to be converted or spent.

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The reporting currency for our consolidated financial statements is the U.S. dollar. Certain of our assets, liabilities, revenues and expenses are denominated in other countries’ currencies. Those assets, liabilities, revenues and expenses are translated into U.S. dollars at the applicable exchange rates to prepare our consolidated financial statements. Therefore, changes in exchange rates between the U.S. dollar and those other currencies affect the value of those items as reflected in our consolidated financial statements, even if their value remains unchanged in their original currency.

LEGAL AND REGULATORY COMPLIANCE RISKS

Government regulations, including those specific to deepwater offshore drilling, may make our business operations more difficult or costly, or limit our services.

Our business is affected by changes in public policy and by federal, state, local and international laws and regulations relating to the offshore oil and gas and renewables operations. Such operations are affected by tax, environmental, safety, labor, cabotage and other laws, by changes in those laws, application or interpretation of existing laws, and changes in related administrative regulations or enforcement priorities. Government authorities, including BOEM and BSEE, may also continue to issue further regulations regarding deepwater offshore drilling. It is also possible that these laws and regulations in the future may add significantly to our capital and operating costs or those of our customers or otherwise directly or indirectly affect our operations.

~~The~~Risks ~~National~~of ~~Defense~~substantial ~~Authorization~~costs ~~Act~~and ~~for~~liabilities ~~fiscal~~related ~~year~~to ~~2021~~environmental compliance issues are inherent in our operations. Our operations are subject to extensive federal, ~~among~~state, ~~other~~local ~~things~~and international laws and regulations relating to the generation, ~~extends~~storage, ~~federal~~handling, ~~law~~emission, transportation and discharge of materials into the environment. Permits are required for the operations of various facilities, including vessels, and those permits are subject to revocation, modification and renewal. Governmental authorities have the ~~Jones~~power ~~Act~~to enforce compliance with their regulations, and violations are subject to Ufines, injunctions or both.S In some cases, those governmental requirements can impose liability for the cost of cleanup on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with applicable requirements when performed. ~~offshore~~It ~~wind~~is ~~farm~~possible ~~projects~~that other developments, ~~making~~such itas ~~more~~stricter ~~difficult~~environmental laws and/ regulations, or ~~costly~~claims for damages to ~~provide~~property ~~for~~or Upersons resulting from our operations, could result in substantial costs and liabilities.S. ~~renewables~~Our ~~customers~~insurance policies and the ~~services~~contractual ~~that~~indemnity protections we ~~currently~~seek ~~provide~~to ~~for~~obtain ~~renewables~~from ~~customers~~our counterparties, assuming they are obtained, may not be sufficient or effective to protect us under all circumstances or against all risk involving compliance with environmental laws and regulations. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon our capital expenditures, earnings or competitive position. However, changes in environmental laws and regulations, changes in the ~~North~~ways ~~Sea~~such laws and ~~Asia~~regulations ~~Pacific.~~are ~~The~~interpreted ~~2025~~or ~~Wind~~enforced, ~~Energy~~or ~~Ban~~claims ~~restricts~~for ~~customers~~damages ~~from~~to ~~developing~~persons, ~~new~~property, ~~wind~~natural ~~farms~~resources onor the ~~U.S.~~environment, ~~Outer~~could ~~Continental~~result ~~Shelf~~in substantial costs and liabilities, and accordingly there can be no assurance that we will not incur significant environmental compliance costs or liabilities in the future.

24As a multi-national organization, we are subject to taxation in multiple jurisdictions. The Organization for Economic Co-operation and Development, the European Union and individual taxing jurisdictions are focused on tax base erosion and profit shifting as well as minimum tax directives (including Pillar Two). These initiatives and directives continue to evolve along with country specific legislation. We anticipate increased disclosure and reporting to facilitate compliance with these directives. Future changes may have adverse effects on us, including increased administrative and compliance costs.

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Risks of substantial costs and liabilities related to environmental compliance issues are inherent in our operations. Our operations are subject to extensive federal, state, local and international laws and regulations relating to the generation, storage, handling, emission, transportation and discharge of materials into the environment. Permits are required for the operations of various facilities, including vessels, and those permits are subject to revocation, modification and renewal. Governmental authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In some cases, those governmental requirements can impose liability for the cost of cleanup on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with applicable requirements when performed. It is possible that other developments, such as stricter environmental laws and regulations, or claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities. Our insurance policies and the contractual indemnity protections we seek to obtain from our counterparties, assuming they are obtained, may not be sufficient or effective to protect us under all circumstances or against all risk involving compliance with environmental laws and regulations.

As a multi-national organization, we are subject to taxation in multiple jurisdictions. The Organization for Economic Co-operation and Development, the European Union and individual taxing jurisdictions are focused on tax base erosion and profit shifting as well as minimum tax directives (including Pillar Two). These initiatives and directives continue to evolve with country specific implementation legislation forthcoming. We anticipate increased disclosure and reporting to facilitate compliance with these directives. As the impact of proposed and future Pillar Two legislation cannot yet be determined, future changes may have adverse effects on us, including increased administrative and compliance costs.

We cannot predict with any certainty the substance or effect of any new or additional regulations in the U.S. or in other areas around the world. If the U.S. or other countries where our customers operate enact stricter restrictions on offshore operations, and this results in decreased demand for or profitability of our services, our business, financial position, results of operations and cash flows could be materially adversely affected.

Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions or if these provisions were modified or repealed.

We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the U.S. We own vessels registered under the U.S. flag whose operations in the U.S. Gulf Coast may constitute coastwise trade. In order to operate vessels in the Jones Act trade and to be qualified to document vessels for coastwise trade, we must maintain U.S. citizen status for Jones Act purposes. We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or more of our common stock. We monitor our ownership for compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on our results of operations as we may be prohibited from operating certain of our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be subject to fines or forfeiture of certain our vessels. There have been attempts to repeal or amend restrictions contained in the Jones Act, and such attempts are expected to continue in the future. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.

Failure to comply with anti-bribery laws could have a material adverse impact on our business.

The U.S. Foreign Corrupt Practices Act and similar anti-bribery laws in other jurisdictions, including the United Kingdom Bribery Act 2010 and Brazil’s Clean Company Act, generally prohibit companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or retaining business. We operate in many parts of the world that have experienced corruption to some degree. We have a robust ethics and compliance program that is designed to deter or detect violations of applicable laws and regulations through the application of our anti-corruption policies and procedures, Code of Business Conduct and Ethics, training, internal controls, investigation and remediation activities, and other measures. However, our ethics and compliance program may not be fully effective in preventing all employees, contractors or intermediaries from violating or circumventing our compliance requirements or applicable laws and regulations. Failure to comply with anti-bribery laws could subject us to civil and criminal penalties, and such failure, and in some instances even the mere allegation of such a failure, could create termination or other rights in connection with our existing contracts, negatively impact our ability to obtain future work, or lead to other sanctions, all of which could have a material adverse effect on our business, financial position, results of operations and cash flows, and cause reputational damage. We could also face fines, sanctions and other penalties from

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~~authorities,~~Our ~~including prohibition of our participating in or curtailment of~~ business ~~operations~~would inbe ~~certain~~adversely ~~jurisdictions~~affected ~~and~~if ~~the seizure of vessels or other assets. Further,~~ we ~~may~~failed ~~have~~to ~~competitors~~comply ~~who~~with ~~are not subject to~~ the ~~same~~Jones ~~laws,~~Act ~~which~~foreign ~~may~~ownership ~~provide~~provisions ~~them~~or ~~with~~if athese ~~competitive~~provisions ~~advantage~~were ~~over~~modified ~~us in securing business~~ or ~~gaining other preferential treatment~~repealed.

We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the U.S. We own vessels registered under the U.S. flag whose operations in the Gulf of America may constitute coastwise trade. In order to operate vessels in the Jones Act trade and to be qualified to document vessels for coastwise trade, we must maintain U.S. citizen status for Jones Act purposes, and we could cease being a U.S. citizen if certain events were to occur. The consequences of our failure to comply with the Jones Act provisions on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on our results of operations as we may be prohibited from operating certain of our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be subject to fines or forfeiture of certain our vessels. There have been attempts to repeal or amend restrictions contained in the Jones Act, and such attempts are expected to continue in the future. Our business could be adversely affected if the Jones Act were to be modified or repealed so as to permit foreign competition that is not subject to the same U.S. government imposed burdens.

Failure to comply with anti-bribery laws could have a material adverse impact on our business.

GENERAL RISKS

We may execute a strategic transaction that may not achieve intended results, could increase our net debt or the number of our shares outstanding, or result in a change of control.

We have executed acquisitions and divestitures in the past, and in the future we may evaluate and potentially enter into additional strategic transactions. Any such transaction could be material to our business, could occur at any time and could take any number of forms, including, for example, an acquisition, merger, joint venture, strategic alliance, equity investment, divestiture or an asset sale.

The success of any transaction may depend on, in part, our ability to integrate an acquired business and realize the financial growth or synergies expected from the transaction. Any such transaction may not be successful, may not be accretive to shareholders or may not achieve expected benefits within an expected timeframe. Acquired businesses may also have unanticipated liabilities, contingencies or negative tax consequences. In addition, acquisitions are accompanied by the risk that the obligations of an acquired business may not be adequately reflected in the historical financial statements of that company and the risk that those historical financial statements may be based on assumptions which are incorrect or inconsistent with our assumptions or approach to accounting policies. Any of these material obligations, unanticipated liabilities or incorrect or inconsistent assumptions could have a material adverse effect on our growth strategy, business, financial condition, prospects and results of operations. Furthermore, evaluating potential transactions and integrating completed transactions could be time-consuming, involve significant transaction related expenses, create unexpected costs, involve difficulties assimilating the operations and personnel of an acquired business, make evaluating our business and future financial prospects difficult and may divert the attention of our management from other operating matters.

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Any such transaction may require additional financing that could result in an increase in the number of our outstanding shares or the aggregate amount of our debt, and the number of shares of our common stock or the aggregate principal amount of our debt that we may issue may be significant. Certain transactions may not be permitted under our existing asset-based credit facility or other debt instruments, requiring either waivers, amendments, or terminating such facility. Furthermore, a strategic transaction may result in a change in control of our company or otherwise materially and adversely affect our business.

The loss of the services of one or more of our key employees, or our failure to attract and retain other highly qualified personnel and other skilled workers in the future, could disrupt our operations and adversely affect our financial results.

Our success depends on the active participation of our key employees. Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, including in connection with industry downturn and a decline in sentiment towards fossil fuels. ~~Our success depends on the active participation of our key employees.~~ The loss of our key people could adversely affect our operations. The delivery of our services also requires personnel with specialized skills, qualifications and experience. The demand for skilled workers can be high and the supply may be limited. A significant increase in the wages paid, or benefits offered, by competing employers could result in a reduction of our skilled labor force, increases to our cost structures, or both. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled, qualified and experienced workers~~, and we may have competition for personnel with the requisite skill set~~.

Cybersecurity breaches or business system disruptions may adversely affect our business.

We rely on our ~~information~~IT ~~technology~~ infrastructure and management information systems to operate and record almost every aspect of our business. This may include confidential or personal information belonging to us, our employees, customers, suppliers, or others. Similar to other companies, our systems and networks, and those of third parties with whom we do business, could be subject to cybersecurity breaches caused by, among other things, illegal hacking and cybercriminals, insider threats, ~~computer viruses~~terrorism, ~~phishing,~~nation-state ~~malware~~actors, ~~ransomware~~competitors, orhostile ~~acts of vandalism or terrorism~~media, or ~~acts~~hardware ~~perpetrated~~and bysoftware ~~criminals or nation-state actors~~vulnerabilities. Furthermore, we may also experience increased cybersecurity risk as some of our onshore personnel may periodically work remotely.

26In addition to our own systems and networks, we use third-party service providers to process certain data or information on our behalf. Due to applicable laws and regulations, we may be held responsible for cybersecurity incidents attributed to our service providers to the extent it relates to information we share with them. Although we seek to require that these service providers implement and maintain reasonable security measures, we cannot control third parties and cannot guarantee that a security breach will not occur in their systems or networks. Despite our efforts to continually refine our procedures, educate our employees, and implement tools and security measures to protect against such cybersecurity risks, there can be no assurance that these measures will prevent unauthorized access or detect every type of attempt or attack. Our potential future upgrades, refinements, tools and measures may not be completely effective or result in the anticipated improvements, if at all, and may cause disruptions in our business operations.

In addition, a cyberattack or security breach could go undetected for an extended period of time, and the resulting investigation of an incident could take time to complete. During that period, we may not necessarily know the impact to our systems or networks, costs and actions required to fully remediate and our initial remediation efforts may not be successful, and the errors or actions could be repeated before they are fully contained and remediated. A breach or failure of our systems or networks, critical third-party systems on which we rely, or those of our customers or vendors, could result in an interruption in our operations, disruption to certain systems that are used to operate our vessels or other assets, unplanned capital expenditures, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer, employee or third party data, theft or misappropriation of funds, violation of privacy or other laws, and exposure to regulatory enforcement investigations, litigation or indemnity claims. There could also be increased costs to detect, prevent, respond to, or recover from cybersecurity incidents, along with diversion of attention from management. Any such breach, or our delay or failure to make adequate or timely disclosures to the public, regulatory or law enforcement agencies or affected individuals following such an event, could have a material adverse effect on our business, reputation, financial position, results of operations and cash flows, and cause reputational damage.

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InThe ~~addition~~emergence toof ~~our~~artificial ~~own~~intelligence ~~systems~~(“AI”) ~~and~~technologies ~~networks, we use third-party service providers to process certain data or information on our behalf. Due to applicable laws and regulations, we~~ may beexpose ~~held~~us ~~responsible for cybersecurity incidents attributed~~ to ~~our~~risks ~~service providers to the extent it relates to information we share with them. Although we seek to require~~ that ~~these~~could ~~service~~adversely ~~providers~~affect ~~implement~~our ~~and maintain reasonable security measures, we cannot control third parties and cannot guarantee that a security breach will not occur in their systems or networks~~business.

~~Despite~~We ~~our~~may ~~efforts to continually refine our procedures~~use, ~~educate our employees,~~ and ~~implement~~may ~~tools~~increasingly ~~and~~rely ~~security measures to protect against such cybersecurity risks~~on, ~~there~~AI ~~can~~technologies bein novarious ~~assurance~~aspects ~~that these measures will prevent unauthorized access or detect every type~~ of ~~attempt~~our ~~or attack~~business. ~~Our~~The ~~potential~~use ~~future~~of ~~upgrades,~~AI ~~refinements,~~presents ~~tools~~risks ~~and~~that ~~measures~~could ~~may~~adversely ~~not~~affect ~~be completely effective or result in the anticipated improvements, if at all, and may cause disruptions in~~ our business, ~~operations.~~results Inof ~~addition~~operations, afinancial ~~cyberattack~~condition or ~~security~~reputation. ~~breach~~AI ~~could~~systems gomay ~~undetected~~produce ~~for an extended period of time~~inaccurate, ~~and~~incomplete ~~the~~or ~~ensuing~~biased ~~investigation of the incident would take time to complete. During that period~~outputs, we may ~~not~~be ~~necessarily~~dependent ~~know~~on the ~~impact~~quality toand ~~our~~availability ~~systems~~of orunderlying ~~networks~~data, ~~costs~~ and ~~actions required to fully remediate and our initial remediation efforts~~ may ~~not~~ be ~~successful,~~difficult ~~and~~to ~~the~~monitor ~~errors~~ or ~~actions could be repeated before they are fully contained and remediated~~explain. AIn ~~breach~~addition, ~~or failure of~~ our ~~systems~~use ~~or networks, critical third-party systems on which we rely, or those~~ of ~~our~~AI ~~customers~~may orincrease ~~vendors, could result in an interruption in~~ our ~~operations,~~exposure ~~disruption~~ to ~~certain~~cybersecurity ~~systems that are used to operate our vessels or other assets~~threats, ~~unplanned~~data ~~capital~~privacy ~~expenditures~~concerns, ~~unauthorized~~intellectual ~~publication~~property ~~of our confidential business or proprietary information~~claims, ~~unauthorized~~and ~~release~~reliance ofon ~~customer, employee or~~ third -party ~~data,~~vendors. ~~theft~~The orregulatory ~~misappropriation~~and oflegal ~~funds,~~framework ~~violation~~governing ofAI ~~privacy~~is orrapidly ~~other laws~~evolving, and ~~exposure~~changes toin ~~litigation~~laws, orregulations ~~indemnity claims including resulting from customer-imposed cybersecurity controls~~ or ~~other~~enforcement ~~related~~practices ~~contractual obligations. There~~ could ~~also~~increase becompliance ~~increased~~ costs ~~to detect, prevent, respond,~~ or ~~recover~~restrict ~~from cybersecurity incidents. Any such breach, or~~ our ~~delay~~ability ~~or failure~~ to ~~make~~use ~~adequate~~AI. orOur ~~timely~~failure ~~disclosures~~ to ~~the public~~identify, ~~regulatory~~effectively ordevelop, ~~law~~implement, ~~enforcement~~govern ~~agencies~~ or ~~affected~~control ~~individuals~~the ~~following~~use ~~such~~of anAI ~~event,~~ could ~~have~~significantly aand ~~material~~adversely ~~adverse~~impact ~~effect on~~ our business, ~~reputation,~~or ~~financial position, results of~~ operations ~~and cash flows, and cause reputational damage~~.

Our competitors may adopt AI into their service offerings, business processes or operations more quickly or more successfully than us, which could affect our ability to compete effectively.

Increasing legal and regulatory focus on data privacy and security issues could expose us to increased liability and operational changes and costs.

Along with our own data and information in the normal course of our business, we collect and retain certain data that is subject to specific laws and regulations. The compliant ~~processing~~collection ~~of this data domestically~~ and ~~transferring~~processing of this data, ~~across~~both ~~international~~domestically ~~borders~~and internationally, continues to increase in complexity. This data is subject to regulation at various levels of government in many areas of our business and in jurisdictions across the world, and other jurisdictions may in the future ~~issue~~promulgate further data privacy laws and regulations. ~~The U.S. Federal Trade Commission recently adopted rules requiring the reporting of certain data breaches that may apply to our operations and those of our subsidiaries.~~ As the ~~number and complexities of such laws and regulations continue to increase, we will face increasingly complex compliance, monitoring, and control obligations. As the~~ implementation, interpretation, and enforcement of such laws continues to progress and evolve, there may also be developments that amplify such risks. Any failure by us to comply with these laws and regulations, including as a result of a security or privacy breach, or otherwise, could expose us to litigation ~~and~~or enforcement, and could result in significant penalties, fines, and other liabilities.

Certain provisions of our corporate documents, financial arrangements and Minnesota law may discourage a third party from making a takeover proposal.

We are authorized to establish, without any action by our shareholders, the rights and preferences on up to 5,000,000 shares of preferred stock, including dividend, liquidation and voting rights. In addition, our by-laws divide our Board into three classes. We are also subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We have employment and other long-term incentive arrangements with all of our executive officers that could require cash and/or equity payments and covenants in our asset-based credit agreement (the “Amended ABL Facility”) and the indenture governing our Senior Notes due 2029 (the “2029 Notes”) that could put us in breach, in the event of a “change of control.” Any or all of these provisions or factors may discourage a takeover proposal or tender offer not approved by management and our Board and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less in return for their shares than otherwise might be available in the event of a takeover attempt.

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Our ability to repurchase shares through any share repurchase program is subject to certain considerations, including availability of Free Cash Flow, and any repurchases could affect the price of our common stock and increase volatility.

Our Board has in the past authorized and may from time to time in the future authorize share repurchase programs. The timing and amount of such repurchases depend upon several factors. Our ability to successfully effect a share repurchase program requires us to generate consistent Free Cash Flow and have available capital in the years ahead in amounts sufficient to enable us to also continue to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements. We may not have available Free Cash Flow to repurchase shares if we use our available cash to satisfy other priorities such as strategic opportunities and acquisitions, or if our Board determines to change or discontinue the repurchase program. There is no guarantee that we would carry out repurchases in the same manner as they may have been announced. Although share repurchase programs are intended to enhance long-term shareholder value, there is no assurance that it will do so. Any failure to repurchase our common stock after we have announced our intention to do so may negatively impact our stock price and short-term stock price fluctuations could reduce the program’s effectiveness.

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A global health pandemic could disrupt our operations and adversely impact our business and financial results.

A global health emergency ~~similar to the COVID-19 pandemic~~ could lead to worldwide shutdowns and halting of commercial and interpersonal activity, resulting in a precipitous decline in oil prices and reduced operating and capital spending by oil and gas producers that may persist for an extended period of time, undermining the confidence in overall industry viability.

Our onshore and offshore operations could be disrupted, and any protocols implemented may not prove fully successful. We may experience reduced productivity as our onshore personnel work remotely, and any spread to our key management personnel may disrupt our business. Any outbreak on our vessels may impede the vessel’s ability to generate revenue and/or increase the costs to operate the vessel. We may also experience challenges in connection with our offshore crew changes due to health and travel restrictions, or a decline in the available offshore workforce, whether due to the pandemic, considerations related to our protocols, attrition from our industry, or a combination of the foregoing.

Item 1B. Unresolved Staff Comments

None.

Item 1C. Cybersecurity

RISK MANAGEMENT AND STRATEGY

Our cybersecurity program is designed to monitor, detect, prevent and respond to cyber threats. We take a multi-faceted approach to identifying and mitigating information security risks. This includes, ~~but~~among isother ~~not~~things, ~~limited~~regular to penetration tests of our external network, ~~the~~and ~~utilization~~use of third-party scanning tools to monitor our network,; ~~maintenance~~maintaining ofrobust ~~software~~patch ~~and~~management ~~implementing~~protocols ~~applicable updates timely, training employees~~ to ~~recognize~~ensure ~~security~~software ~~risks~~updates ~~and~~are ~~encouraging~~implemented ~~employees~~on toa ~~report~~timely ~~suspicious~~basis; ~~activity.~~comprehensive ~~Annual~~employee ~~cybersecurity~~ awareness ~~training~~programs isdesigned ~~provided~~ to ~~onshore~~facilitate ~~and~~recognition ~~offshore~~of ~~users.~~security ~~The training seeks to demonstrate to users the~~ risks ~~in using technology~~ and ~~how~~encourage toproactive ~~effectively~~reporting ~~defend~~of ~~against~~suspicious ~~cyber threats~~activity.

We assess, identify and manage material risks from cybersecurity threats and vulnerabilities according to our Cybersecurity Incident Response Plan (the “IRP”). The IRP uses the six-stage model of the National Institute of Standards and Technology (“NIST”) Cybersecurity Framework (Preparation, Detection, Containment, Investigation, Remediation, and Recovery) to outline steps for reporting, responding, and mitigating various aspects of a cybersecurity incident. ~~Execution~~The ofCybersecurity ~~the~~Incident ~~IRP’s~~Response ~~incident~~Team ~~response~~coordinates ~~activities~~the ~~are~~execution ~~coordinated~~of byactivities under the ~~Cybersecurity Incident Response Team~~IRP, ~~and~~while communications planning ~~via~~is managed cross-functionally through the Helix Crisis Assistance Team and the Cybersecurity Incident Communication Group. There are also separate processes in place for the effective management of cyber incidents involving our offshore assets and certain regional business units.

28To enhance our cybersecurity posture, we engage a range of external specialists and partners to assist in the identification and management of threats. This includes leveraging a third-party Security Operations Center (“SOC”) for continuous network monitoring, as well as collaborating with managed service providers, financial institutions, and government and law enforcement entities to share threat intelligence and coordinate incident response efforts. In addition, we collaborate with our internal auditors to ensure our processes are documented and followed appropriately.

~~Table~~We have processes in place to identify and mitigate cybersecurity risks associated with our use of ~~Contents~~third-party service providers. Our policy requires that each third-party service provider go through a mandatory IT and Information Security Governance processes review and obtain formal approval from our IT and Information Security Governance groups before it can be used. Notifications and remediation of cyber threats are tracked, reviewed, and archived. Processes implemented and lessons learned involving these third parties are evaluated after each incident to ensure efficiency and replication.

We engage external parties to aid in processing and managing cybersecurity incidents as needed, including utilization of the services and expertise of local law enforcement and government entities, partnering financial institutions, a third-party security operations center (“SOC”), and managed service providers. In addition, we collaborate with our internal auditors to ensure our processes are documented and followed appropriately.

In connection with our external SOC and managed service providers, we have implemented change control measures that allow for the continual oversight and assessment of the services provided and threats identified. Notifications and remediation of cyber threats are tracked, reviewed, and archived. Processes implemented and lessons learned involving these third parties are evaluated after each incident to ensure efficiency and replication.

We face risks from cybersecurity threats that could have a material adverse effect on our business, financial condition, results of operations, cash flows or reputation. We have experienced, and may continue to experience, cyber incidents in the normal course of its business. However, prior cybersecurity incidents have not had a material adverse effect on our business, financial condition, results of operations, or cash flows. See “Risk Factors – General Risks – Cybersecurity breaches or business system disruptions may adversely affect our business.”

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GOVERNANCE

Risks relating to cybersecurity are overseen by the Audit Committee. Certain members of our management, including the Executive Vice President and Chief Financial Officer (the “CFO”), the ~~Chief~~Vice ~~Accounting~~President ~~Officer~~– Finance and ~~Corporate~~Accounting ~~Controller~~and Chief Accounting Officer (the “CAO”) and the Vice President of Internal Audit, report to the Audit Committee regarding cybersecurity risks. IT management presents an annual update of cybersecurity related activities to the Audit Committee. Interim updates are provided to the Audit Committee by the CFO on an as needed basis should an incident warrant immediate notification or escalation.

Within Helix’s IT department, several IT management positions are responsible for assessing and managing cybersecurity risk, including the Chief Information Officer, Director of Information Technology and ~~Manager~~Cybersecurity ~~of Information Technology~~Manager. Each of the IT department’s management personnel has over 20 years of IT and information security experience. The Director of Information Technology and the Cybersecurity Manager ~~of Information Technology~~ positions are tasked with the daily and per incident assessment and management of cybersecurity risks, while the Chief Information Officer is tasked with oversight.

Helix’s IT ~~department~~leadership ~~keeps~~ensures that senior management ~~involved~~is ~~and~~apprised ~~informed~~of significant cybersecurity incidents throughout the ~~entire~~lifecycle ~~process~~ of ~~any~~the ~~cybersecurity~~event ~~incident~~ (from initial ~~monitoring~~detection and discovery through ~~the~~ remediation and restoration,) ~~all~~consistent ~~in accordance~~ with the ~~processes~~escalation ~~outlined~~protocols defined in our IRP. Initial notification regarding a cybersecurity incident may come through our third-party SOC or managed service providers, or from employees reporting internally to our IT helpdesk. Investigations are then performed to determine the appropriate actions per the IRP guidelines. Incidents that warrant further escalation are promptly shared with the CFO and continually updated, as appropriate, until remediation and restoration is achieved.

Helix’s IT department holds regular quarterly meetings with the CFO, CAO, and Vice President of Internal Audit to recap cybersecurity risks and incidents ~~and~~ to determine any actions required as a result.

Item 2. Properties

VESSELS AND OTHER OPERATING ASSETS

As of December 31, ~~2024~~2025, our fleet included 26 owned vessels, eight IRSs, three SILs, the ROAM, 20 P&A systems, six CT systems, 39 ROVs, six trenchers and ~~two~~three IROV boulder grabs. We also had seven vessels under time charter agreements. All of our chartered vessels and 11 of our owned vessels have DP capabilities specifically designed to meet the needs of our customers’ offshore activities. Our Seawell and Well Enhancer vessels also have built-in saturation diving systems.

29Listing of Vessels and Other Assets Related to Operations as of December 31, 2025 (1)

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Listing of Vessels and Other Assets Related to Operations as of December 31, 2024 (1)


		Placed
	Flag	in	Length
	State	Service (2)	(Feet)	DP
Floating Production Unit —
Helix Producer I	Bahamas	4/2009	528	DP2
Well Intervention —
Q4000 (3)	U.S.	4/2002	312	DP3
Seawell (4)	U.K.	7/2002	368	DP2
Well Enhancer (4)	U.K.	10/2009	432	DP3
Q5000	Bahamas	4/2015	358	DP3
Siem Helix 1 (5)	Bahamas	6/2016	521	DP3
Sea Helix 1 (5)	Bahamas	6/2016	521	DP3
Siem Helix 2 (5)	Bahamas	2/2017	521	DP3
Q7000	Bahamas	1/2020	320	DP3
8 IRSs, 3 SILs and the ROAM (6)	—	Various	—	—
Helix Alliance —
EPIC Hedron (heavy lift barge)	Vanuatu	7/2022	400	—
9 liftboats, 6 OSVs, 3 DSVs and 1 crew boat	U.S.	7/2022	Various	DP1 (7)
20 P&A systems and 6 CT systems	—	Various	—	—
Robotics —
39 ROVs, 6 Trenchers and 2 IROV boulder grabs (4), (8)	—	Various	—	—
39 ROVs, 6 Trenchers and 3 IROV boulder grabs (4), (8)	—	Various	—	—
Grand Canyon II (5)	Norway	4/2015	419	DP3
5 chartered robotics support vessels (5)	Various	Various	240 - 419	DP2 or DP3
Grand Canyon III (5)	Norway	5/2017	419	DP3
North Sea Enabler (5)	Barbados	5/2022	316	DP2
Shelia Bordelon (5)	U.S.	2/2022	257	DP2
Glomar Wave (5)	Panama	2/2023	216	DP2

(1) We maintain our vessels in accordance with standards of seaworthiness, safety and health set by governmental regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the Coast Guard. ABS, BV, DNV and Lloyds are classification societies used by vessel owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.30

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(1)

We maintain our vessels in accordance with standards of seaworthiness, safety and health set by governmental regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the U.S. Coast Guard. ABS, BV, DNV and Lloyds are classification societies used by vessel owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.

(2)	Represents the date we placed our owned vessels in service (rather than the date of commissioning) or the date the original charters for our chartered vessels commenced, as applicable.

(3)	Subject to a vessel mortgage securing our MARAD Debt described in Note 7.

(4)	Serves as security for the Amended ABL Facility described in Note 7.

(5) ~~Vessel~~Vessels under a time charter ~~agreement~~agreements.

(6) We own a 50% interest in the ROAM and three of the IRSs. ~~One of the two deepwater IRSs has not yet been placed in service.~~

(7)	DP capabilities are only applicable to five OSVs.

(8) Average age of our Robotics assets is approximately 1213.20 years.

We incur routine dry dock, inspection, maintenance and repair costs pursuant to applicable statutory regulations in order to maintain our vessels in accordance with the rules of the applicable class society. In addition to complying with these requirements, we have our own asset maintenance programs that we believe help us to continue to provide our customers with well-maintained, reliable assets.

FACILITIES

Our corporate headquarters are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas 77043. Except for ~~one~~two owned ~~property~~properties related to Helix Alliance, we currently lease all of our facilities, which are primarily located in Texas, Louisiana, Scotland, Singapore and Brazil.

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Item 3. Legal Proceedings

The information required to be set forth under this heading is incorporated by reference from Note 16 to our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.

Item 4. Mine Safety Disclosures

Not applicable.

Information about our Executive Officers

Our executive officers are as follows:

Name	Age	Position
Owen Kratz	7071	President, Chief Executive Officer and Director
Erik Staffeldt	5354	Executive Vice President and Chief Financial Officer
Scott A. Sparks	5152	Executive Vice President and Chief Operating Officer
Kenneth E. Neikirk	4950	Executive Vice President, General Counsel and Corporate Secretary

Owen Kratz is President and Chief Executive Officer of Helix. He was named Executive Chairman in October 2006 and served in that capacity until February 2008 when he resumed the position of President and Chief Executive Officer. He served as Helix’s Chief Executive Officer from April 1997 until October 2006. Mr. Kratz served as President from 1993 until February 1999, and has served as a Director since 1990 (including as Chairman of our Board from May 1998 to July 2017). He served as Chief Operating Officer from 1990 through 1997. Mr. Kratz joined Cal Dive International, Inc. (now known as Helix) in 1984 and held various offshore positions, including saturation diving supervisor, and management responsibility for client relations, marketing and estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine construction company operating in the Bay of Campeche. Prior to 1982, he was a superintendent for Santa Fe and various international diving companies, and a diver in the North Sea. From February 2006 to December 2011, Mr. Kratz was a member of the Board of Directors of Cal Dive International, Inc., a once publicly traded company, which was formerly a subsidiary of Helix. Mr. Kratz has a Bachelor of Science degree from State University of New York.

Erik Staffeldt is Executive Vice President and Chief Financial Officer of Helix. Prior thereto he was Senior Vice President and Chief Financial Officer beginning in June 2017 until February 2019. Mr. Staffeldt oversees Helix’s finance, treasury, accounting, tax, information technology and corporate planning functions. Since joining Helix in July 2009 as Assistant Corporate Controller, Mr. Staffeldt has served as Director — Corporate Accounting from August 2011 until March 2013, Director of Finance from March 2013 until February 2014, Finance and Treasury Director from February 2014 until July 2015, and Vice President — Finance and Accounting from July 2015 until June 2017. Mr. Staffeldt was also designated as Helix’s “principal accounting officer” for purposes of the Securities Act, the Exchange Act and the rules and regulations promulgated thereunder in July 2015 until December 2021. Mr. Staffeldt served in various financial and accounting capacities prior to joining Helix and has over 29 years of experience in the energy industry. Mr. Staffeldt is a graduate of the University of Notre Dame with a BBA in Accounting and Loyola University in New Orleans with an MBA, and is a Certified Public Accountant.

Scott A. (“Scotty”) Sparks is Executive Vice President and Chief Operating Officer of Helix, having joined Helix in 2001. He served as Executive Vice President — Operations of Helix from May 2015 until February 2016. From October 2012 until May 2015, he was Vice President — Commercial and Strategic Development of Helix. He has also served in various positions within Helix Robotics Solutions, Inc. (formerly known as Canyon Offshore, Inc.), including as Senior Vice President from 2007 to September 2012. Mr. Sparks has over 35 years of experience in the subsea industry, including as Operations Manager and Vessel Superintendent at Global Marine Systems and BT Marine Systems.

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~~Kenneth~~Owen E.Kratz ~~(“Ken”)~~is ~~Neikirk~~President isand Chief Executive ~~Vice~~Officer ~~President,~~of ~~General~~Helix. ~~Counsel~~He was named Executive Chairman in October 2006 and ~~Corporate~~served ~~Secretary~~in that capacity until February 2008 when he resumed the position of ~~Helix~~President and Chief Executive Officer. On December 17, 2025, Mr. ~~Neikirk~~Kratz ~~has~~informed ~~over~~the ~~24 years~~Board of ~~experience~~his ~~practicing~~intention ~~law~~to inretire ~~the~~and ~~corporate~~serve as President and ~~energy~~CEO ~~sectors,~~until ~~and~~the Board has ~~been~~appointed a ~~member~~successor. ofHe served as Helix’s ~~legal~~Chief ~~department~~Executive ~~since~~Officer ~~2007,~~from ~~previously~~April 1997 ~~serving~~until asOctober 2006. ~~Helix’s~~Mr. Kratz ~~Senior~~served ~~Vice~~as President, ~~General~~from ~~Counsel~~1993 until February 1999, and ~~Corporate~~has ~~Secretary~~served ~~from~~as ~~May~~a ~~2019~~Director tosince ~~December~~1990 ~~2022,~~(including ~~and~~as ~~prior~~Chairman toof ~~that~~our asBoard ~~Corporate~~from ~~Counsel,~~May 1998 ~~Compliance~~to ~~Officer~~July 2017). ~~and~~He ~~Assistant~~served ~~Secretary~~as Chief Operating Officer from ~~February 2016~~1990 ~~until~~through ~~April 2019~~1997. Mr. ~~Neikirk~~Kratz ~~oversees~~joined Cal Dive International, Inc. (now known as Helix’s) ~~legal~~in 1984 and held various offshore positions, ~~human~~including ~~resources~~saturation diving supervisor, and ~~contracts~~management ~~and~~responsibility ~~insurance~~for ~~functions~~client relations, marketing and estimating. ~~Prior~~From 1982 to ~~joining~~1983, ~~Helix~~ Mr. ~~Neikirk~~Kratz was inthe ~~private~~owner ~~practice~~of an independent marine construction company operating in ~~New~~the ~~York~~Bay of Campeche. Prior to 1982, he was a superintendent for Santa Fe and ~~Houston~~various international diving companies, and a diver in the North Sea. From February 2006 to December 2011, Mr. ~~Neikirk~~Kratz ~~holds~~was a ~~Bachelor~~member of ~~Arts~~the ~~degree~~Board ~~from~~of ~~Duke~~Directors ~~University~~of ~~and~~Cal Dive International, Inc., a ~~Juris~~once ~~Doctor~~publicly traded company, which was formerly a subsidiary of Helix. Mr. Kratz has a Bachelor of Science degree from ~~the~~State University of ~~Houston~~New ~~Law Center~~York.

Erik Staffeldt is Executive Vice President and Chief Financial Officer of Helix. Prior thereto he was Senior Vice President and Chief Financial Officer beginning in June 2017 until February 2019. Mr. Staffeldt oversees Helix’s finance, treasury, accounting, tax, information technology and corporate planning functions. Since joining Helix in July 2009 as Assistant Corporate Controller, Mr. Staffeldt has served as Director — Corporate Accounting from August 2011 until March 2013, Director of Finance from March 2013 until February 2014, Finance and Treasury Director from February 2014 until July 2015, and Vice President — Finance and Accounting from July 2015 until June 2017. Mr. Staffeldt was also designated as Helix’s “principal accounting officer” for purposes of the Securities Act, the Exchange Act and the rules and regulations promulgated thereunder in July 2015 until December 2021. Mr. Staffeldt served in various financial and accounting capacities prior to joining Helix and has over 30 years of experience in the energy industry. Mr. Staffeldt is a graduate of the University of Notre Dame with a BBA in Accounting and Loyola University in New Orleans with an MBA, and is a Certified Public Accountant.

Scott A. (“Scotty”) Sparks is Executive Vice President and Chief Operating Officer of Helix, having joined Helix in 2001. He served as Executive Vice President — Operations of Helix from May 2015 until February 2016. From October 2012 until May 2015, he was Vice President — Commercial and Strategic Development of Helix. He has also served in various positions within Helix Robotics Solutions, Inc. (formerly known as Canyon Offshore, Inc.), including as Senior Vice President from 2007 to September 2012. Mr. Sparks has over 36 years of experience in the subsea industry, including as Operations Manager and Vessel Superintendent at Global Marine Systems and BT Marine Systems.

Kenneth E. (“Ken”) Neikirk is Executive Vice President, General Counsel and Corporate Secretary of Helix. Mr. Neikirk has over 25 years of experience practicing law in the corporate and energy sectors, and has been a member of Helix’s legal department since 2007, previously serving as Helix’s Senior Vice President, General Counsel and Corporate Secretary from May 2019 to December 2022, and prior to that as Corporate Counsel, Compliance Officer and Assistant Secretary from February 2016 until April 2019. Mr. Neikirk oversees Helix’s legal, human resources, and contracts and insurance functions. Prior to joining Helix Mr. Neikirk was in private practice in New York and Houston. Mr. Neikirk holds a Bachelor of Arts degree from Duke University and a Juris Doctor from the University of Houston Law Center.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” On February 19 17, ~~2025~~2026, the closing sale price of our common stock on the NYSE was $8.1739 per share. As of February 19 17, ~~2025~~2026, there were ~~261~~263 registered shareholders and approximately 8377,~~800~~380 beneficial shareholders of our common stock.

We have not declared or paid cash dividends on our common stock in the past nor do we intend to pay cash dividends in the foreseeable future. In addition, our financing arrangements may place certain limitations on the payment of cash dividends on our common stock. We currently intend to reinvest any retained earnings, if any, for the future operation and growth of our business, to repay maturing debt that is not refinanced, or to use for potential acquisition opportunities or share repurchases. Our Board will review this matter on a regular basis in light of our earnings, financial position and market opportunities. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations “— Liquidity and Capital Resources” of this Annual Report.

Shareholder Return Performance Graph

The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2019 to the cumulative total shareholder return for (i) the stocks of 500 large-cap corporations maintained by Standard & Poor’s (“S&P 500”), assuming the reinvestment of dividends; (ii) the Philadelphia Oil Service Sector index (the “OSX”), a price-weighted index of leading oil service companies, assuming the reinvestment of dividends; and (iii) a peer group selected by us as of January 2024 (the “2024 Performance Peer Group”) including the following companies: Archrock, Inc., ChampionX Corporation, Core Laboratories N.V., DMC Global Inc., DNOW Inc., Expro Group Holdings N.V., Forum Energy Technologies, Inc., Helmerich & Payne, Inc., Innovex International, Inc. (formerly Dril-Quip, Inc.), Nine Energy Service, Inc., NPK International Inc. (formerly Newpark Resources, Inc.), Oceaneering International, Inc., Oil States International, Inc., Precision Drilling Corporation, ProPetro Holding Corp., RPC, Inc., Select Water Solutions, Inc., TETRA Technologies, Inc. and Tidewater Inc. The returns of each member of the 2024 Performance Peer Group have been weighted according to each individual company’s equity market capitalization as of December 31, 2024 and have been adjusted for the reinvestment of any dividends. We believe that in 2024 the members of the 2024 Performance Peer Group provided services and products more comparable to us than those companies included in the OSX. The graph assumes $100 was invested on December 31, 2019 in our common stock at the closing price on that date price and on December 31, 2019 in the three indices presented. We paid no cash dividends during the period presented. The cumulative total percentage returns for the period presented are as follows: our stock — (3.2)%; the 2024 Performance Peer Group — 1.5%; the OSX — 1.7%; and S&P 500 — 97.0%. These results are not necessarily indicative of future performance.

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We have not declared or paid cash dividends on our common stock in the past nor do we intend to pay cash dividends in the foreseeable future. In addition, our financing arrangements may place certain limitations on the payment of cash dividends on our common stock. We currently intend to reinvest any retained earnings, if any, for the future operation and growth of our business, to repay maturing debt that is not refinanced, or to use for potential acquisition opportunities or share repurchases. Our Board will review this matter on a regular basis in light of our earnings and financial forecasts, financial position and market opportunities. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations “— Liquidity and Capital Resources” of this Annual Report.

Shareholder Return Performance Graph

The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2020 to the cumulative total shareholder return for (i) the stocks of 500 large-cap corporations maintained by Standard & Poor’s (“S&P 500”), assuming the reinvestment of dividends; (ii) the Philadelphia Oil Service Sector index (the “OSX”), a price-weighted index of leading oil service companies, assuming the reinvestment of dividends; and (iii) a peer group selected by us as of January 2025 (the “2025 Performance Peer Group”) including the following companies: Archrock, Inc., Core Laboratories N.V., Expro Group Holdings N.V., Forum Energy Technologies, Inc., Helmerich & Payne, Inc., Nabors Industries Ltd., NPK International Inc. (formerly Newpark Resources, Inc.), Noble Corporation plc, NOV Inc., Oceaneering International, Inc., Oil States International, Inc., Patterson-UTI Energy, Inc., Precision Drilling Corporation, ProPetro Holding Corp., RPC, Inc., Select Water Solutions, Inc., TETRA Technologies, Inc., Tidewater Inc., Tranocean Ltd. and Weatherford International plc. The returns of each member of the 2025 Performance Peer Group have been weighted according to each individual company’s equity market capitalization as of December 31, 2025 and have been adjusted for the reinvestment of any dividends. We believe that in 2025 the members of the 2025 Performance Peer Group provided services and products more comparable to us than those companies included in the OSX. The graph assumes $100 was invested on December 31, 2020 in our common stock at the closing price on that date price and on December 31, 2020 in the three indices presented. We paid no cash dividends during the period presented. The cumulative total percentage returns for the period presented are as follows: our stock — 49.3%; the 2025 Performance Peer Group — 71.2%; the OSX — 81.7%; and S&P 500 — 96.2%. These results are not necessarily indicative of future performance.

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Comparison of Five Year Cumulative Total Return among Helix, S&P 500,

OSX and Peer Group


	As of December 31,
	~~2019~~2020		~~2020~~2021		~~2021~~2022		~~2022~~2023		~~2023~~2024		~~2024~~2025
Helix	$	100.0	$	4374.63	$	32175.47	$	76244.68	$	~~106~~221.89	$	96149.83
2024 Performance Peer Group Index	$	100.0	$	59.0	$	67.2	$	101.3	$	102.9	$	101.5
2025 Performance Peer Group Index	$	100.0	$	121.0	$	197.8	$	208.4	$	174.0	$	171.2
Oil Service Index	$	100.0	$	57.9	$	69.9	$	112.9	$	115.1	$	101.7
OSX	$	100.0	$	120.7	$	195.0	$	198.7	$	175.6	$	181.7
S&P 500	$	100.0	$	~~118~~128.47	$	~~152~~105.4	$	~~124~~133.81	$	~~157~~166.64	$	~~197~~196.02

Source: Bloomberg.

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 (12)
Period	purchased (21)	per share		or programs (12)	(in thousands)
October 1 to October 31, 2024	—	$	—	—	$	177,823
October 1 to October 31, 2025	—	$	—	—	$	128,380
November 1 to November 30, 2024	583,057		10.69	583,057		171,590
November 1 to November 30, 2025	—		—	—		128,380
December 1 to December 31, 2024	1,368,422		9.80	1,346,651		158,392
December 1 to December 31, 2025	19,048		7.25	—		128,380
	119,~~951,479~~048	$	107.0725	~~1,929,708~~—

(1) OnIncludes February 20, 2023, we announced that our Board authorized a new share repurchase program (the “2023 Repurchase Program”) under which we are authorized to repurchase up to $200 million issued and outstanding shares offorfeited ~~our~~in ~~common~~satisfaction ~~stock (Note 10). The 2023 Repurchase Program has no set expiration date. Concurrent with the authorization~~ of ~~the~~tax ~~2023~~obligations ~~Repurchase~~upon ~~Program,~~vesting ~~our Board revoked the prior authorization to repurchase shares~~ of ~~our~~share-based ~~common~~awards ~~stock in an amount equal to any equity granted to our employees, officers and directors~~ under our ~~share~~existing long-~~based~~term ~~compensation~~incentive plans.

33(2) On February 20, 2023, we announced that our Board authorized a share repurchase program (the “2023 Repurchase Program”) under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock (Note 10). The 2023 Repurchase Program has no set expiration date. Concurrent with the authorization of the 2023 Repurchase Program, our Board revoked the prior authorization to repurchase shares of our common stock in an amount equal to any equity granted to our employees, officers and directors under our share-based compensation plans.

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(2) Includes shares repurchased in open-market transactions pursuant to the 2023 Repurchase Program and shares forfeited in satisfaction of tax obligations upon vesting of share-based awards under our existing long-term incentive plans.

Item 6. [Reserved]

Not applicable.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. Risk Factors and located earlier in this Annual Report.

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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. We operate through our four business segments: Well Intervention, Robotics, Shallow Water Abandonment and Production Facilities. 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.

~~Industry~~We ~~Influences~~maximize production of existing oil and ~~Market~~gas ~~Environment~~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 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 rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our well intervention assets and services.

~~Demand~~Once ~~for our services is primarily influenced by the condition~~ end-of-life ~~the~~ oil and gas ~~and~~wells ~~the~~have ~~renewable~~depleted ~~energy~~their ~~markets and~~production, inwe ~~particular,~~P&A ~~the~~and ~~level~~decommission ofwells ~~spending~~and ofinfrastructure ~~offshore~~in ~~energy~~our ~~companies~~Well onIntervention ~~operational~~and ~~activities~~Shallow ~~and~~Water ~~capital~~Abandonment ~~projects~~segments. ~~The~~We ~~performance~~believe ofthat our ~~business~~well isintervention ~~largely~~vessels ~~affected~~have bya ~~the~~competitive ~~prevailing~~advantage ~~market~~in ~~prices~~performing ~~for~~these ~~oil~~services ~~and~~more ~~natural~~efficiently ~~gas~~than rigs, ~~which~~and ~~are~~with ~~impacted~~our bysuite ~~domestic~~of ~~and~~shallow ~~global~~water ~~economic~~assets ~~conditions, hydrocarbon production~~ and ~~capacity~~capabilities, ~~geopolitical~~we ~~issues,~~are ~~weather,~~the ~~global~~only ~~health,~~provider ~~and~~capable ~~various~~of ~~other~~providing ~~factors.~~all ~~Demand~~facets ~~for~~of decommissioning isservices ~~affected~~in bythe ~~commodity~~Gulf ~~prices~~of asAmerica ~~well as governmental regulations and political forces globally~~shelf.

~~Oil~~We ~~prices~~support ~~continue~~renewable toenergy beprimarily ~~volatile~~in ~~but~~our ~~have~~Robotics ~~generally~~segment ~~remained~~through ~~robust~~our ~~during~~services ~~2024.~~in ~~Global~~offshore ~~demand~~wind ~~for~~farm ~~oil~~developments, ~~continues~~including tosubsea ~~experience~~cable ~~growth~~trenching ~~albeit at slower rates,~~ and ~~although~~burial weas ~~believe~~well ~~the~~as ~~current~~seabed ~~oil~~clearance and ~~gas~~preparation ~~pricing~~services. ~~warrants~~Demand ~~continued~~for ~~customer~~our ~~spending~~services ~~for~~in the ~~industry,~~renewable ~~higher~~energy ~~levels~~market ofis ~~economic~~affected ~~and~~by ~~industry~~various ~~uncertainty~~factors, ~~may~~including ~~temper~~the ~~such~~level ~~customer~~of ~~spending.~~offshore ~~Factors~~wind ~~that~~farm ~~could~~projects, ~~threaten~~ the ~~current~~pace ~~commodity~~of ~~price~~industry ~~environment~~shift ~~persist,~~towards ~~including~~renewable ~~regional~~energy ~~conflicts~~sources, ~~governmental~~global ~~regulations,~~electricity ~~geopolitical instability and uncertainty~~demand, ~~unrest~~technological inadvancements ~~the~~that ~~Middle~~increase ~~East, OPEC+ decisions,~~ the ~~global~~generation ~~economy~~ and/or reduce the ~~demand~~cost ~~for~~of ~~oil~~renewable ~~and gas in China in particular~~energy, ~~various~~expansion ~~governmental and customer sustainability initiatives and continued shifting~~ of ~~resource~~offshore ~~allocation to~~ renewable energy. Weprojects ~~expect~~to ~~these~~deeper ~~factors~~water ~~will~~and ~~continue~~other toregions, ~~contribute~~and togovernment ~~commodity~~subsidies ~~price~~for ~~volatility~~renewable ~~with~~energy ~~the~~projects ~~potential~~and/or toother ~~temper~~governmental ~~customer~~regulations ~~spending~~supporting ~~for~~or ~~oil~~restricting ~~and~~renewable ~~gas~~energy ~~projects~~developments.

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~~Market ~~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.~~Environment

34Commodity prices dropped 20% during 2025 and have been volatile throughout the year. The current energy market remains uncertain following the ongoing escalation of tariffs and geopolitical tensions globally and their impact on the global economy and energy demands. The offshore oil and gas market continues to evaluate governmental regulations and changes thereto, including the ongoing effects of the U.K. government’s Energy Profits Levy, geopolitical instability and uncertainty, regional conflicts and tensions, unrest in the Middle East, Ukraine and Venezuela, and customer spending declines following mergers in the U.K. North Sea. These factors have shifted spending decisions of our customers into 2026 and prolonged a supply and demand imbalance for offshore vessels, which has negatively impacted activity levels and rates in regions in which we operate.

~~Table~~The ofinternational ~~Contents~~wind market continues to be robust, with continued activity and sanctioned work primarily in Europe and Asia Pacific. U.S. wind farm activity has decreased and remains uncertain 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.

In the current market environment, we continue to see oil and gas companies invest in long-cycle offshore exploration projects in addition to maintain and/or increase production from their existing reserves. As production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we expect oil and gas companies to continue to focus on optimizing production of their existing subsea wells in addition to their exploration activities.

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 U.S. Gulf Coast shelf. The demand for P&A services should grow over the mid- to long-term as the subsea tree base expands, as government regulations continue to place stronger emphasis on decommissioning aged wells worldwide (including subsea trees as well as mature dry tree wells in the shallow waters of the U.S. Gulf Coast), as customers look to reduce their decommissioning obligations and as customers shift resources to renewable energy.

We support the energy transition to renewable energy primarily in our Robotics segment through our services in offshore wind farm developments, primarily 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, for instance, the 2025 Wind Energy Ban. We expect growth in our renewables services as the global energy market continues offshore renewable energy developments.

Business Activity Summary

During ~~2024~~2025, ~~our operating results improved significantly as~~ we ~~continued~~experienced todeclined ~~execute~~activity onlevels ~~our energy transition strategy with significant improvements~~ in ~~utilization~~the ~~and~~North ~~rates~~Sea ~~in our Well Intervention~~ and ~~Robotics~~Gulf ~~segments.~~of ~~During~~America ~~2024,~~with welower ~~also~~customer ~~executed~~spending ~~significant~~due ~~new~~to ~~contracts on~~ the ~~strength~~uncertain ~~of the~~ market ~~and~~environment. ~~the~~However, ~~demand~~we ~~for~~were ~~our~~able ~~services.~~to ~~These~~maintain ~~contracts added~~ significant backlog ~~and~~that will provide strong utilization for our vessels and equipment over multiple years. Notable new contracts executed in 2025 include:

● ~~Six~~Four-~~month~~year ~~contract~~trenching agreement with ~~options~~NKT ~~on the Q4000~~ in ~~Nigeria, which commenced in~~ the ~~fourth~~North ~~quarter 2024~~Sea;

● ~~Trident~~Renewables ~~extension~~trenching atcontract ~~improved~~with ~~rates~~Seaway on7 ~~the~~for ~~Siem~~estimated ~~Helix~~300 1days ~~for~~in ~~one~~the ~~year~~North ~~through 2025~~Sea;

● ~~New three~~Three-year ~~contracts~~framework agreement with ~~Petrobras~~ExxonMobil onfor ~~the~~well ~~Siem~~decommissioning ~~Helix~~work 1in ~~and~~ the ~~Siem~~Gulf ~~Helix~~of 2America ~~at improved rates~~shelf;

● Two-year contract with Shell in the U.S. Gulf Coast on the Q5000 for a minimum of 175 days per year;

● Extension of the agreement for the HP I for one year until at least June 1, 2026; and

● Extension of our contract with Shell in Brazil on the Q7000 to a minimum of 400 days.

During 2024, we extended the charters on the Siem Helix 1, the Siem Helix 2, the Grand Canyon II and the Shelia Bordelon. We also entered in or extended various facility leases across all regions.

We completed the redemption of the Convertible Senior Notes due 2026 (the “2026 Notes”) during the first quarter 2024. In August 2024, we extended the maturity of the Amended ABL Facility to August 2029 and increased the letter of credit basket size in order to facilitate increased bonding needs on the Q4000 Nigeria campaign and various windfarm projects. We maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, investing in targeted acquisitions that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

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~~Backlog~~● Well Intervention contract in the Gulf of America for a minimum of 150 days over a three-year period;

~~Our~~● ~~backlog~~Multi-year isriserless ~~represented~~P&A bycontract ~~signed contracts. As of December 31, 2024, our consolidated backlog totaled $1.4 billion, of which $681 million is expected to be performed~~ in ~~2025. As of December 31, 2024, our various contracts with Shell and ExxonMobil globally, our contracts with Trident Energy and Petrobras in Brazil, our contracts with Talos in~~ the ~~U.S.~~North ~~Gulf~~Sea ~~Coast~~on ~~represented~~up ~~approximately~~to ~~90%~~34 ofsubsea our total backlog. As of December 31, 2023, our consolidated backlog totaled $850 million. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtractedwells; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

●

Extension of the agreement with HWCG for the HFRS through March 31, 2027; and

●

Extension of the agreement for the HP I for one year until at least June 1, 2027.

During 2025, we executed and/or extended various leases including the charters on the Trym, the North Sea Enabler, and the Patriot, which was delivered to us in January 2026.

We continue to maintain our capital allocation policy of maintaining low levels of Net Debt, maintaining our existing assets, opportunistically targeting markets that complement and further our strategy, and using Free Cash Flow to return cash to shareholders through share repurchases (See “Results of Operations — Non-GAAP Financial Measures” below for definitions of Net Debt and Free Cash Flow).

Outlook

InOur ~~2025,~~2026 weperformance ~~expect~~should tobe ~~continue~~supported by our ~~strong~~existing ~~performance~~backlog, ~~supported~~of bywhich $694 million is for contracts over the next 12 months, as well as expected new contracting inand ~~2024~~the atmaterialization ~~improved~~of ~~rates~~work that ~~increased~~had ~~backlog~~been ~~and~~deferred ~~driven~~from by2025. ~~increasing~~We expect to see continued strong market demand for our ~~decommissioning~~Robotics services, ~~internationally~~in particular our trenching and ~~continued~~site ~~growth~~preparation inofferings. ~~the~~We ~~offshore~~anticipate ~~renewables~~an ~~trenching~~ongoing challenged market. Wefor ~~expect~~certain ~~the~~of ~~demand~~our assets not under long-term contracts, namely in spot markets for ~~shallow~~our ~~water~~Well ~~decommissioning~~Intervention ~~services~~segment, specifically in the ~~U.S.~~North ~~Gulf~~Sea ~~Coast~~and toon ~~improve~~the asQ4000 ~~oil~~ and ~~gas~~the ~~properties~~Q7000, ~~revert~~and toin ~~former~~our ~~owners~~Shallow ~~due~~Water toAbandonment ~~bankruptcies~~segment, ~~who~~during ~~are~~which ~~expected~~time towe ~~address~~expect ~~their~~a ~~decommissioning~~soft ~~obligations~~rate environment and uncertain utilization of those vessels and systems.

Beyond 2026, we anticipate increasing energy consumption will continue to place demand for our services in both the oil and gas and renewable energy sectors. We believe these needs will continue to increase customer operating expenditure budgets and demand for our production enhancement offerings and decommissioning services internationally, which should grow over the mid- to long-term as the subsea tree base expands and as customers discharge their decommissioning obligations. We expect long-term growth in our renewables services as the global demand for energy increases and the international energy market continues offshore renewable energy developments. We expect the demand for shallow water decommissioning services in the Gulf of America to also improve over time as former owners address their decommissioning obligations related to oil and gas properties that have reverted to them following bankruptcies.

Backlog

Our backlog is represented by signed contracts. As of December 31, 2025, our consolidated backlog totaled $1.3 billion, of which $694 million is expected to be performed in 2026. As of December 31, 2025, our various contracts with Shell and Subsea 7 globally, our contracts with Petrobras in Brazil, our contracts with Talos in the Gulf of America, and our new multi-year agreements with NKT and CNR in the North Sea collectively represented approximately 82% of our total backlog. As of December 31, 2024, our consolidated backlog totaled $1.4 billion. 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.

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RESULTS OF OPERATIONS

Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under U.S. generally accepted accounting principles (“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, ~~gains and losses on equity investments,~~ 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, long-lived asset impairment losses, 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) ~~for~~ current expected credit losses, if any. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from 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 consolidated financial statements unless otherwise noted.

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Net income (loss)	$	5530,~~637~~827	$	~~(10~~55,~~838)~~637	$	(8710,~~784~~838)
Adjustments:
Income tax provision		2611,~~427~~653		1826,~~352~~427		1218,~~603~~352
Net interest expense		22,~~629~~777		1722,~~338~~629		1817,~~950~~338
Other expense, net		31,~~922~~390		3,~~590~~922		233,~~330~~590
Depreciation and amortization		~~173~~187,~~292~~382		~~164~~173,~~116~~292		~~142~~164,~~686~~116
Gain on equity investment		—		—		(8,262)
EBITDA		254,029		281,907		192,558
EBITDA		281,907		192,558		101,523
Adjustments:
Adjustments:
(Gain) loss on disposition of assets, net		—		479		(367)
(Gain) loss on disposition of assets, net		479		(367)		—
Long-lived asset impairment		18,064		—		—
Acquisition and integration costs		—		~~540~~—		~~2,664~~540
Change in fair value of contingent consideration		—		~~42,246~~—		1642,~~054~~246
General provision (release) for current expected credit losses		(161)		1,149		781
General provision for (release of) current expected credit losses		(136)		(161)		1,149
Losses related to convertible senior notes		~~20,922~~—		3720,~~277~~922		—37,277
Adjusted EBITDA	$	~~303~~271,~~147~~957	$	~~273~~303,~~403~~147	$	~~121~~273,~~022~~403

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Cash flows from operating activities	$	~~186~~136,~~028~~749	$	~~152~~186,~~457~~028	$	51152,~~108~~457
Less: Capital expenditures, net of proceeds from asset sales and insurance recoveries		(2216,~~840~~342)		(1822,~~659~~840)		(3318,~~504~~659)
Free Cash Flow	$	~~163~~120,~~188~~407	$	~~133~~163,~~798~~188	$	17133,~~604~~798

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


	December 31,
	~~2024~~2025		~~2023~~2024
Long-term debt including current maturities	$	~~315~~307,~~157~~995	$	~~361~~315,~~722~~157
Less: Cash and cash equivalents		(~~368~~445,~~030~~196)		(~~332~~368,~~191~~030)
Net Debt	$	(52137,~~873~~201)	$	29(52,~~531~~873)

37Comparison of Years Ended December 31, 2025 and 2024

~~Table~~We ofhave ~~Contents~~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 consolidated financial statements. The following table details various financial and operational highlights for the periods presented (dollars in thousands):

Comparison of Years Ended December 31, 2024 and 2023

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 consolidated financial statements, including our consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):


	Year Ended December 31,						Increase/(Decrease)
	~~2024~~2025			~~2023~~2024			Amount		Percent
Net revenues —
Well Intervention	$	~~829~~729,~~862~~371		$	~~707~~829,~~718~~862		$	~~122~~(100,~~144~~491)	17(12)	%
Robotics		~~297~~323,~~678~~353			~~257~~297,~~875~~678			3925,~~803~~675	159	%
Shallow Water Abandonment		~~186~~199,~~979~~633			~~274~~186,~~954~~979			~~(87~~12,~~975)~~654	~~(32)~~7	%
Production Facilities		8872,~~709~~693			8788,~~885~~709			~~824~~(16,016)	1(18)	%
Intercompany eliminations		(4433,~~668~~576)			(3844,~~704~~668)			(511,~~964)~~092
	$	1,~~358~~291,~~560~~474		$	1,~~289~~358,~~728~~560		$	68(67,~~832~~086)	(5)	%

Gross profit (loss) —
Well Intervention	$	~~110~~40,~~612~~594		$	47110,~~164~~612		$	63(70,~~448~~018)	~~135~~(63)	%
Robotics		8881,~~287~~781			6088,~~618~~287			27(6,~~669~~506)	46(7)	%
Shallow Water Abandonment		~~(777)~~17,932			~~71,261~~(777)			~~(72~~18,~~038)~~709	~~(101)~~2,408	%
Production Facilities		2321,~~766~~147			23,~~494~~766			~~272~~(2,619)	1(11)	%
Corporate, eliminations and other		(2,~~324~~316)			(2,~~181~~324)			~~(143)~~8
	$	~~219~~159,~~564~~138		$	~~200~~219,~~356~~564		$	19(60,~~208~~426)	10(28)	%

Gross margin —
Well Intervention		136	%		713	%
Robotics		3025	%		2430	%
Shallow Water Abandonment		~~(0)~~9	%		26(0)	%
Production Facilities		2729	%		27	%
Total company		1612	%		16	%

Number of vessels, Robotics assets or Shallow Water Abandonment systems (1) / Utilization (2)
Well Intervention vessels		7 / 9072	%		7 / 8890	%
Robotics assets (3)		4748 / 6959	%		4647 / 6269	%
Chartered Robotics vessels		67 / 9288	%		6 / 9692	%
Shallow Water Abandonment vessels (4)		20 / 6053	%		20 / 7460	%
Shallow Water Abandonment systems (5)		26 / 2428	%		26 / 7024	%

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(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.

(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(excluding ~~the~~vessel ~~applicable~~charter ~~period.~~off-hire ~~Utilization~~days) ~~rates of chartered Robotics vessels~~ in ~~2024~~the ~~and~~applicable ~~2023 included 371 and 310 spot vessel days, respectively, at near full utilization~~period.

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

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

(5)	Consists of P&A and CT systems.

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Intercompany segment amounts are derived primarily from equipment and services provided to other business segments. Intercompany segment revenues are as follows (in thousands):


	Year Ended December 31,				Increase/
	~~2024~~2025		~~2023~~2024		(Decrease)
Well Intervention	$	~~6,390~~—	$	36,~~353~~390	$	3(6,~~037~~390)
Robotics		3833,~~039~~512		3538,~~263~~039		2(4,~~776~~527)
Shallow Water Abandonment		~~239~~64		88239		~~151~~(175)
	$	4433,~~668~~576	$	3844,~~704~~668	$	5(11,~~964~~092)

~~Net~~The ~~Revenues.~~following ~~Our~~table ~~consolidated~~sets ~~net~~forth ~~revenues~~significant ~~increased~~financial bystatement 5%items inbelow ~~2024~~the asgross ~~compared~~profit to(loss) ~~2023,~~line ~~reflecting higher revenues~~ (in ~~our Well Intervention, Robotics and Production Facilities business segments, offset in part by lower revenues in our Shallow Water Abandonment segment.~~ thousands):

Our Well Intervention revenues increased by 17% in 2024 as compared to 2023, primarily reflecting higher overall utilization and rates. Utilization increased on the Q4000 and the Q5000 during 2024 as both vessels underwent their regulatory dry docks in 2023. The Q7000 had higher utilization and higher integrated project rates during 2024 as compared to 2023. The Seawell‘s contract in the western Mediterranean, which completed in June 2024, has provided higher rates and utilization during 2024 as compared to 2023. The Well Enhancer in the North Sea had lower utilization as compared to the prior year as the vessel underwent a scheduled dry dock during the first quarter 2024 and both vessels saw a fourth quarter seasonal slowdown in 2024 whereas the vessels were nearly fully utilized in 2023. Our North Sea revenues also included a contract cancellation fee of approximately $14 million related to work that had been scheduled for 2025. The Siem Helix 1 had higher revenues during 2024 as compared to 2023 due to Trident contract extensions with higher rates. The Siem Helix 2 had lower utilization during 2024 as the vessel commenced its unpaid vessel acceptance period at the end of December 2024 on its new contract with Petrobras.

Our Robotics revenues increased by 15% in 2024 as compared to 2023, primarily reflecting higher chartered vessel days and trenching and ROV activities. Chartered vessel activity increased to 1,901 days during 2024 as compared to 1,699 days during 2023, although chartered vessel days in 2024 included approximately 64 days of standby utilization at reduced rates. Overall ROV and trencher utilization increased to 69% in 2024 from 62% during 2023 and included 835 days of integrated vessel trenching in 2024 as compared to 807 days in 2023.


		Year Ended December 31,
		2025			2024
Long-lived asset impairment		$	18,064		$	—
Selling, general and administrative expenses			75,939			91,650
Net interest expense			22,777			22,629
Losses related to convertible senior notes			—			20,922
Other expenses, net			1,390			3,922
Income tax provision			11,653			26,427

Our Shallow Water Abandonment revenues in 2024 decreased by 32% in 2024 as compared to 2023. The decrease in revenues was due to lower activity levels and an overall softer U.S. Gulf Coast shelf market in 2024, resulting in lower vessel and system utilization during 2024 as compared to 2023. Overall vessel utilization was 60% during 2024 as compared to 74% during 2023. P&A systems and CT systems achieved 2,281 days of utilization, or 24%, during 2024 as compared to 5,748 days of utilization, or 70%, during 2023.

Net Revenues. Our ~~Production~~consolidated ~~Facilities~~net revenues ~~increased~~decreased ~~slightly~~by 5% in ~~2024~~2025 as compared to ~~2023~~2024, ~~primarily~~ reflecting ~~higher oil and gas production and~~ lower ~~number~~revenues ~~of shut-~~in ~~days on~~ our ~~owned~~Well ~~oil~~Intervention and ~~gas~~Production ~~wells~~Facilities business segments, offset in part by ~~lower~~higher ~~rates~~revenues ~~on the HFRS, which were reduced~~ in ~~the~~our ~~second~~Robotics ~~half~~and ~~2024~~Shallow ~~when~~Water ~~the~~Abandonment ~~Q4000 left the U~~segments.~~S. Gulf Coast to execute the Nigeria project.~~

~~Gross Profit (Loss).~~ Our ~~consolidated~~Well ~~2024~~Intervention ~~gross~~revenues ~~profit~~decreased ~~increased~~ by ~~$19.2 million~~12% in 2025 as compared to ~~2023~~2024, primarily reflecting ~~increased~~overall ~~profits~~lower ~~from~~utilization, ~~our~~offset ~~Well~~in ~~Intervention~~part by higher rates during 2025. Utilization declined primarily due to the stacking of the Seawell in the North Sea during the entirety of 2025 whereas the vessel had 86% utilization during 2024. Utilization also declined as the Q4000, ~~Robotics~~the Q5000 and ~~Production~~the ~~Facilities~~Q7000 ~~business~~collectively ~~segments~~underwent 131 docking days during 2025 as compared to 10 days on the Sea Helix 1 during 2024. Additionally, revenues in 2024 included $14 million of contract cancellation fees related to work that had been planned for 2025. Revenue decreases were offset in part by ~~losses~~higher ~~from~~rates ~~our~~on ~~Shallow~~the ~~Water~~Well ~~Abandonment~~Enhancer, ~~segment~~and in Brazil in 2025.

Our ~~Well~~Robotics ~~Intervention~~revenues ~~gross profit~~ increased by ~~$63.4 million~~9% in ~~2024~~2025 as compared to ~~2023~~2024, primarily reflecting ~~higher~~increased ~~segment~~trenching ~~revenues~~on third party vessels and ~~increased~~higher ~~activity~~project ~~levels~~rates on our vessel activities, offset in part by lower overall vessel and ~~included~~ROV autilization ~~contract~~during ~~cancellation~~2025. ~~fee~~Robotics generated 483 days of ~~approximately~~trenching ~~$14~~on ~~million~~third-party vessels during 2025 as compared to 167 days during 2024. However, vessel utilization decreased to 1,808 days (including 75 spot vessel days at full utilization) during 2025 as compared to 1,901 days (including 371 spot vessel days at full utilization) during 2024. Included in vessel days are integrated vessel trenching days, which decreased to 635 days in 2025 as compared to 835 days in 2024, and site clearance vessel days, which increased to 503 days as compared to 325 days in 2024. Overall ROV utilization decreased to 59% during 2025 as compared to 69% during 2024.

Our Robotics gross profit increased by $27.7 million in 2024 as compared to 2023, primarily reflecting higher revenues and higher profit margin projects during 2024.

Our Shallow Water Abandonment gross loss was $0.8 million in 2024 as compared to a gross profit of $71.3 million in 2023, primarily reflecting lower segment revenues without a commensurate cost reduction.

Our Production Facilities gross profit increased slightly in 2024 as compared to 2023, primarily reflecting higher segment revenues.

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~~Change~~Our Shallow Water Abandonment revenues increased by 7% in ~~Fair~~2025 ~~Value~~as ofcompared ~~Contingent~~to ~~Consideration~~2024. The ~~change~~increase in ~~fair~~revenues ~~value~~was ofprimarily ~~contingent~~due ~~consideration~~to ~~reflects~~higher anutilization ~~improvement~~on inour ~~Helix~~systems ~~Alliance’s~~and ~~results~~on ~~during~~the ~~2023.~~Epic WeHedron ~~entered~~heavy ~~into~~lift anbarge. ~~agreement~~P&A systems and ~~set~~CT ~~the~~systems ~~final~~achieved ~~earnout~~2,686 days of utilization, or 28%, during ~~the~~2025 ~~fourth~~as ~~quarter~~compared ~~2023~~to 2,281 ~~which~~days ~~was~~of ~~paid~~utilization, onor ~~April 3~~24%, during 2024. Utilization on the Epic Hedron heavy lift barge was 58% during 2025 as compared to 44% during 2024. Vessel utilization (~~Note 3~~excluding heavy lift) declined to 53% during 2025 as compared to 61% during 2024.

~~Selling,~~Our ~~General~~Production ~~and~~Facilities ~~Administrative~~revenues ~~Expenses.~~decreased ~~Our~~by ~~selling~~18% in 2025 as compared to 2024, ~~general~~primarily reflecting lower oil and ~~administrative~~gas ~~expenses~~production ~~were~~volumes ~~$91.7 million~~with inthe ~~2024~~Thunder asHawk ~~compared~~field tobeing ~~$94.4 million~~shut in ~~2023,~~during ~~primarily~~2025 ~~reflecting~~after ahaving ~~net~~had ~~decrease~~approximately inseven ~~compensation~~months ~~related~~of ~~costs~~production ~~offset~~in ~~partially~~2024. byThe anDroshky ~~increase~~field had lower production in ~~other~~2025 ~~facilities~~as compared to 2024 and ~~professional~~realized ~~fees~~oil inprices ~~2024~~were lower by 12% year over year.

~~Net~~Gross ~~Interest~~Profit ~~Expense~~(Loss). Our ~~net~~consolidated ~~interest~~2025 ~~expense~~gross ~~totaled~~profit decreased by $2260.64 million ~~in 2024~~ as compared to ~~$17.3 million in 2023~~2024, primarily reflecting ~~higher~~reduced ~~debt~~profitability ~~levels~~from ~~and rates on~~ our ~~$300~~Well ~~million~~Intervention, ~~Senior~~Robotics ~~Notes~~and ~~due~~Production ~~2029~~Facilities ~~(the~~business ~~“2029 Notes”) in 2024 as compared to our 2026 Notes in 2023~~segments, offset in part by ~~higher~~increased ~~interest~~profitability ~~income~~from on our ~~invested~~Shallow ~~cash~~Water ~~(Note 7)~~Abandonment segment.

~~Losses~~Our ~~Related~~Well toIntervention ~~Convertible~~gross ~~Senior~~profit ~~Notes~~decreased by $70.0 million ~~The~~in ~~losses~~2025 ~~during~~as compared to 2024, ~~and~~primarily ~~2023~~reflecting ~~were~~lower ~~primarily~~overall ~~associated~~revenues, ~~with~~offset in part by lower vessel costs on the ~~retirement~~Seawell ofdue ~~our~~to ~~2026~~the ~~Notes~~vessel ~~(Note 7)~~being warm-stacked in 2025 and higher cost deferrals related to the dockings during 2025.

~~Other~~Our ~~Expense,~~Robotics ~~Net.~~gross ~~Net~~profit ~~other~~decreased ~~expense~~by ~~was~~ $36.95 million in ~~2024~~2025 as compared to ~~$3.6 million in 2023. Net other expense during~~ 2024, primarily ~~reflects~~reflecting alower ~~$2.4~~margins ~~million~~on ~~increase~~certain inprojects ~~the value of incentive credits granted to the seller of P&A equipment acquired in 2023 (Note 4) and foreign currency losses~~ due to the ~~weakening~~mix of ~~the British pound and Brazilian real in 2024. Net other expense during 2023 primarily reflects foreign currency losses related to the devaluation of the Nigerian naira on our naira cash holdings~~contracting, offset in part by ~~foreign~~higher ~~currency~~revenues ~~gains~~during ~~due to the strengthening of the British pound in 2023~~2025.

~~Income~~Our ~~Tax~~Shallow ~~Provision.~~Water ~~Income~~Abandonment ~~tax~~gross ~~provision~~profit was $2617.4 9 million ~~for~~in ~~2024~~2025 as compared to ~~$18.4 million~~a ~~for~~gross ~~2023.~~loss ~~The~~of ~~effective~~$0.8 ~~tax~~million ~~rates~~in ~~for~~ 2024 ~~and 2023 were 32.2% and 244.2%~~, ~~respectively. These variances were~~ primarily ~~attributable~~reflecting tohigher ~~the~~overall ~~increase~~revenues inand ~~income before taxes as well as the earnings mix between our~~ higher ~~and~~margin ~~lower~~contracting ~~tax~~during ~~rate jurisdictions~~2025.

~~Comparison~~Our ~~of Years~~Production ~~Ended~~Facilities ~~December 31~~gross profit decreased by $2.6 million in 2025 as compared to 2024, ~~2023~~primarily ~~and~~due ~~2022~~to lower revenues, offset in part by lower workover costs on the Thunder Hawk field during 2025.

~~Various~~Long-Lived ~~financial~~Asset ~~and~~Impairment. ~~operational~~The ~~highlights~~$18.1 ~~for~~million ~~the~~non-cash ~~years~~impairment ~~ended~~loss ~~December 31,~~in ~~2023~~2025 ~~and~~was ~~2022~~attributable ~~were~~to ~~previously~~the ~~presented~~impairment inof ~~our~~the ~~2023~~remaining ~~Annual~~net ~~Report~~book onvalue ~~Form~~of the Thunder Hawk field (Note ~~10-K~~5).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $75.9 million in 2025 as compared to $91.7 million in 2024, primarily reflecting decreases in employee compensation-related costs during 2025.

Net Interest Expense. Our net interest expense totaled $22.8 million in 2025 as compared to $22.6 million in 2024, primarily reflecting lower interest income on our invested cash (Note 7).

Losses Related to Convertible Senior Notes. The losses during 2024 were associated with the redemption of our Convertible Senior Notes due 2026 (the “2026 Notes”) (Note 7).

Other Expense, Net. Net other expense was $1.4 million in 2025 as compared to $3.9 million in 2024, primarily reflecting a $2.4 million charge in 2024 associated with the increase in the value of incentive credits issued to the seller of P&A equipment acquired in 2023.

Income Tax Provision. Income tax provision was $11.7 million for 2025 as compared to $26.4 million for 2024. The effective tax rate for 2025 was impacted by certain discrete items, additional foreign tax credit benefits and the jurisdictional mix of earnings. The effective rate for 2024 was impacted by the non-deductibility of certain losses associated with the 2026 Notes Redemptions, which was characterized as a discrete event.

Comparison of Years Ended December 31, 2024 and 2023

Various financial and operational highlights for the years ended December 31, 2024 and 2023 were previously presented in our 2024 Annual Report on Form 10-K.

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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):


	December 31,
	~~2024~~2025		~~2023~~2024
Net working capital	$	~~405~~525,~~266~~314	$	~~249~~405,~~223~~266
Long-term debt (excluding current maturities)		~~305~~298,~~971~~351		~~313~~305,~~430~~971
Liquidity		~~429~~553,~~586~~550		~~431~~429,~~471~~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. ~~Net working capital at December 31, 2023 included $85.0 million of Alliance earnout consideration that was paid in cash on April 3, 2024.~~

Long-Term Debt

Long-term debt in the table above, presented net of unamortized debt discount and debt issuance costs, includes ~~our MARAD Debt,~~ the ~~2026~~2029 Notes and the ~~2029~~MARAD ~~Notes~~Debt, ~~and~~excluding ~~excludes~~ current maturities of $9.26 million and $489.32 million, respectively, at December 31, ~~2024~~2025 and ~~2023~~2024. For information relating to our long-term debt, see Note 7 to our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.

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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 December 31, ~~2024~~2025 included $~~368~~445.02 million of cash and cash equivalents and $66110.69 million of available borrowing capacity under the Amended ABL Facility (Note 7) and excluded $52.05 million of pledged cash. Our liquidity at December 31, ~~2023~~2024 included $~~332~~368.20 million of cash and cash equivalents and $9966.36 million of available borrowing capacity under the Amended ABL Facility. ~~The~~and ~~reduction~~excluded in$5.0 ~~availability~~million ~~on the facility at December 31,2024 was attributable to higher letter~~ of ~~credit~~pledged ~~usage in order to support the Nigeria project on the Q4000~~cash.

~~In the current market environment, we expect strong ongoing operating performance and cash flows.~~ 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. ~~Although~~We ~~we expect lower levels of availability on the Amended ABL Facility while the Q4000 performs work in Nigeria due to fewer eligible receivables and higher letter of credit usage, we~~ currently do not anticipate borrowing under the Amended ABL Facility ~~and~~except ~~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 consolidated statements of cash flows (in thousands):


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Cash provided by (used in):
Operating activities	$	~~186~~136,~~028~~749	$	~~152~~186,~~457~~028	$	51152,~~108~~457
Investing activities		(2216,~~840~~342)		(1822,~~659~~840)		(~~138~~18,~~289~~659)
Financing activities		(~~125~~45,~~310~~059)		25(125,~~109~~310)		~~(44~~25,~~844)~~109

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Operating Activities

~~The~~Cash ~~increase~~flows inprovided ~~our~~by operating ~~cash~~activities ~~flows~~ for ~~2024~~2025 decreased as compared to ~~2023~~2024 ~~primarily~~despite ~~reflects~~the ~~higher~~absence ~~operating~~of ~~income~~an earnout payment, primarily reflecting lower earnings, higher regulatory ~~recertification~~certification costs ~~for~~on our vessels and systems and net working capital ~~inflows. Operating cash~~ outflows ~~during 2024 included net interest expense and taxes paid of $25~~.4 ~~million~~Our ~~and~~operating ~~$14.1 million, respectively. Operating~~ cash outflows during 2024 ~~also~~ included $58.3 million of the $85.0 million earnout payment on April 3, 2024,. ~~representing~~Regulatory ~~the~~certification ~~amount~~costs, inwhich ~~the~~are ~~excess~~considered part of ~~the~~our ~~$26.7~~capital ~~million~~spending ~~initial~~program ~~fair~~but ~~value~~are ofclassified ~~earnout~~in ~~consideration~~operating atcash ~~the~~flows, ~~Alliance~~were ~~acquisition date~~$52.0 ~~Regulatory~~million ~~recertification~~in ~~spend~~2025 oncompared ~~our vessels and systems amounted~~ to $35.4 million ~~and~~in ~~$62~~2024.~~5 million, respectively, during the comparable year over year periods.~~

Investing Activities

Cash flows used in investing activities for ~~2024~~2025 ~~increased~~decreased as compared to ~~2023~~2024 primarily due to ~~higher~~lower capital expenditures ~~with~~in ~~increased~~our ~~activity~~Well inIntervention ~~our~~and Robotics ~~segment~~segments.

Financing Activities

Net cash outflows from financing activities for 2025 primarily reflect the repurchases of $30.2 million in our common stock under the 2023 Repurchase Program and related excise tax payments, principal repayment of $9.2 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 2024 primarily reflect cash outflows of $60.7 million related to the 2026 Notes, $26.7 million of the $85.0 million earnout payment, the principal repayment of $8.7 million related to the MARAD Debt and $29.6 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.

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Net cash inflows from financing activities for 2023 primarily reflect net proceeds of $292.0 million from the issuance of $300.0 million 2029 Notes and of $15.6 million from the proportionate settlement of the 2026 Capped Calls, offset in part by cash outflows of $230.7 million related to the repurchase of the 2026 Notes, $30.4 million related to the maturity of the Convertible Senior Notes due 2023, the principal repayment of $8.3 million related to the MARAD Debt and $12.0 million in repurchases of our common stock under the 2023 Repurchase Program.

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~~operating ~~and~~lease ~~equipment~~obligations and ~~operating~~property ~~lease~~and ~~obligations~~equipment, as of December 31, ~~2024~~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~~terms. Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory ~~recertification~~certification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of December 31, ~~2024~~2025.


	Total		Short-Term		Long-Term
MARAD debt	$	2314,~~831~~645	$	9,~~186~~644	$	145,~~645~~001
2029 Notes		300,000		—		300,000
Interest related to debt		~~124~~95,~~627~~369		3130,~~038~~282		9365,~~589~~087
Property and equipment		136,~~842~~519		136,~~842~~519		—
Operating leases (1)		~~870~~788,~~984~~314		~~154~~164,~~324~~733		~~716~~623,~~660~~581
Total cash obligations	$	1,~~333~~204,~~284~~847	$	~~208~~211,~~390~~178	$	1993,~~124,894~~669

(1) Operating leases include vessel charters and facility and equipment leases, including commitments related to leases executed but not yet commenced. At December 31, ~~2024~~2025, our commitment related to long-term vessel charters that have commenced totaled approximately $~~835~~724.59 million, of which $~~434~~366.39 million was related to the non-lease (services) components that are not included in operating lease liabilities in the consolidated balance sheet as of December 31, ~~2024~~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 15). Those obligations, which are presented on a discounted basis on the 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 December 31, 2024, 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 certification 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.

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Other material cash requirements

Other material cash requirements include the following:

Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 15). Those obligations, which are presented on a discounted basis on the consolidated balance sheets, approximate $80.9 million (undiscounted) for Thunder Hawk field oil and gas properties and $37.1 million (undiscounted) for Droshky field oil and gas properties as of December 31, 2025. We are entitled to receive $30.0 million (undiscounted) from Marathon Oil Corporation as certain decommissioning obligations associated with Droshky field oil and gas properties are fulfilled.

Regulatory certification and dry dock. Our vessels and systems are subject to certain regulatory certification requirements that must be satisfied in order for the vessels and systems to operate. Certification 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. Although not currently expected to be utilized, we also have availability under the Amended ABL Facility and access to capital markets.

CRITICAL ACCOUNTING ESTIMATES AND POLICIES

Our discussion and analysis of our financial condition and results of operations, as reflected in the consolidated financial statements and related footnotes included in Item 8. Financial Statements and Supplementary Data of this Annual Report, 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. We believe that the most critical accounting estimates are described below. See Note 2 to our consolidated financial statements for a detailed discussion on the application of our accounting policies.

Property and Equipment

We review our property and equipment for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We evaluate impairment indicators considering the nature of the asset or asset group, the future economic benefits of the asset or asset group, historical and estimated future profitability measures, and other external market conditions or factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and comparing those cash flows to the asset’s carrying value. If the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. The expected future cash flows used for the assessment of recoverability are based on judgmental assessments of operating costs, project margins and capital project spending, considering information available at the date of review. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.

The review of property and equipment for impairment indicators, the projection of future cash flows of property and equipment, and the estimated fair value of any property and equipment that may be deemed unrecoverable involve significant judgment and estimation by our management. Changes to those judgments and estimations could require us to recognize impairment charges in the future.

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New Accounting Standards

For discussion on the potential impact of new accounting standards issued but not yet adopted, see Note 2 to our consolidated financial statements.

Item 7A. 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.

43Assets 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 consolidated balance sheets. At December 31, 2025, approximately 57% of our net assets were impacted by changes in foreign currencies (primarily the British pound) in relation to the U.S. dollar. For the years ended December 31, 2025, 2024 and 2023, we recorded foreign currency translation gains (losses) of $63.1 million, $(17.6) million and $22.3 million, respectively, 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.

~~Table~~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 consolidated statements of ~~Contents~~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 year ended December 31, 2025, we recorded net foreign currency losses of $1.7 million, primarily related to our international subsidiaries’ foreign currency positions. For the year ended December 31, 2024, we recorded foreign currency transaction losses of $1.5 million, primarily related to U.S. dollar denominated debt in our U.K. and Brazil entities. For the year ended December 31, 2023, we recorded foreign currency transaction losses of $4.4 million, primarily reflecting foreign currency losses of $15.7 million related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains related to U.S. dollar denominated intercompany debt in our U.K. entities.

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 consolidated balance sheets. At December 31, 2024, approximately 54% of our net assets were impacted by changes in foreign currencies (primarily the British pound) in relation to the U.S. dollar. For the years ended December 31, 2024, 2023 and 2022, we recorded foreign currency translation gains (losses) of $(17.6) million, $22.3 million and $(49.2) million, respectively, 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 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 years ended December 31, 2024, we recorded foreign currency transaction losses of $1.5 million, primarily related to U.S. dollar denominated intercompany debt in our U.K. and Brazil entities. For the year ended December 31, 2023, we recorded foreign currency transaction losses of $4.4 million, primarily reflecting foreign currency losses of $15.7 million related to the devaluation of the Nigerian naira on our naira cash holdings, offset in part by foreign currency gains related to U.S. dollar denominated intercompany debt in our U.K. entities. For the years ended December 31, 2022, we recorded foreign currency transaction losses of $23.4 million, primarily related to U.S. dollar denominated intercompany debt 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 for a list of factors affecting oil and ~~natural~~ gas prices.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

Helix Energy Solutions Group, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group, Inc. and subsidiaries (the Company) as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, ~~2024~~2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, ~~2024~~2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 26, ~~2025~~2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing separate opinions on the critical audit matter or on the accounts or disclosures to which it relates.

Evaluation of property and equipment impairment triggering events

As discussed in Note 2 to the consolidated financial statements, the Company evaluates property and equipment for impairment at least quarterly or whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable, or triggering events. The Company performs this evaluation considering the future economic benefits of the asset or asset groups, historical and estimated future profitability measures, and other factors that may be present, such as extended periods of idle time or the inability to contract the Company’s equipment at economical rates. The carrying value of property and equipment as of December 31, ~~2024~~2025 was $1~~,438~~.4 ~~million~~billion.

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We identified the evaluation of property and equipment impairment triggering events as a critical audit matter. Sustained decreases in commodity prices and uncertainty regarding spending trends by customers in the industry may lead to periods of low utilization and low day rates for those assets or asset groups not under a long-term contract, and the evaluation of the impact of these factors required a higher degree of subjective auditor judgment.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the evaluation of property and equipment for impairment. This included controls related to the Company’s process to identify and evaluate triggering events that indicate that the carrying value of an asset or asset group may not be recoverable, including the consideration of forecasted to actual results and market conditions in determination of a triggering event. We evaluated the Company’s identification of triggering events, including consideration of future expected revenues from executed contracts. We compared data used by the Company against analyst and industry reports. We compared the Company’s historical forecasts to actual results by asset group to assess the Company’s ability to accurately forecast.

/s/ KPMG LLP

We have served as the Company’s auditor since 2016.

Houston, Texas

February 26, ~~2025~~2026

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders

Helix Energy Solutions Group, Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Helix Energy Solutions Group, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, ~~2024~~2025, and the related notes (collectively, the consolidated financial statements), and our report dated February 26, ~~2025~~2026 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Houston, Texas

February 26, ~~2025~~2026

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)


	December 31,		~~December 31,~~
	~~2024~~2025		~~2023~~2024
ASSETS
Current assets:
Cash and cash equivalents	$	~~368~~445,~~030~~196	$	~~332~~368,~~191~~030
Accounts receivable, net of allowance for credit losses of $3,682 and $3,407, respectively		258,630		280,427
Accounts receivable, net of allowance for credit losses of $3,529 and $3,682, respectively		303,939		258,630
Other current assets		8375,~~022~~857		8583,~~223~~022
Total current assets		~~709~~824,~~682~~992		~~697~~709,~~841~~682
Property and equipment		3,~~068~~156,~~755~~606		3,~~078~~068,~~571~~755
Less accumulated depreciation		(1,~~630~~794,~~902~~112)		(1,~~505~~630,~~722~~902)
Property and equipment, net		1,~~437~~362,~~853~~494		1,~~572~~437,~~849~~853
Operating lease right-of-use assets		~~329~~302,649		~~169~~329,~~233~~649
Deferred recertification and dry dock costs, net		71,718		71,290
Deferred certification and dry dock costs, net		74,351		71,718
Other assets, net		4851,~~178~~418		4448,~~823~~178
Total assets	$	2,~~597~~615,~~080~~904	$	2,~~556~~597,~~036~~080

LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	~~144~~134,~~793~~287	$	~~134~~144,~~552~~793
Accrued liabilities		9094,~~455~~951		~~203~~90,~~112~~455
Current maturities of long-term debt		9,~~186~~644		489,~~292~~186
Current operating lease liabilities		5960,~~982~~796		6259,~~662~~982
Total current liabilities		~~304~~299,~~416~~678		~~448~~304,~~618~~416
Long-term debt		~~305~~298,~~971~~351		~~313~~305,~~430~~971
Operating lease liabilities		~~285~~260,~~984~~959		~~116~~285,~~185~~984
Deferred tax liabilities		~~113~~105,~~973~~571		~~110~~113,~~555~~973
Other non-current liabilities		6671,~~971~~433		66,~~248~~971
Total liabilities		1,~~077~~035,~~315~~992		1,~~055~~077,~~036~~315
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 150,243 and 152,291 shares issued, respectively		1,252,253		1,271,565
Common stock, no par, 240,000 shares authorized, 147,186 and 150,243 shares issued, respectively		1,218,494		1,252,253
Retained earnings		~~368~~398,~~087~~914		~~312~~368,~~450~~087
Accumulated other comprehensive loss		(~~100~~37,~~575~~496)		(83100,~~015~~575)
Total shareholders’ equity		1,~~519~~579,~~765~~912		1,~~501~~519,~~000~~765
Total liabilities and shareholders’ equity	$	2,~~597~~615,~~080~~904	$	2,~~556~~597,~~036~~080

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Net revenues	$	1,~~358~~291,~~560~~474	$	1,~~289~~358,~~728~~560	$	~~873~~1,~~100~~289,728
Cost of sales		1,~~138~~132,~~996~~336		1,~~089~~138,~~372~~996		~~822~~1,~~484~~089,372
Gross profit		~~219~~159,~~564~~138		~~200~~219,~~356~~564		50200,~~616~~356
Gain (loss) on disposition of assets, net		~~(479)~~—		~~367~~(479)		—367
Acquisition and integration costs		—		(540)		(2,664)
Long-lived asset impairment		(18,064)		—		—
Change in fair value of contingent consideration		—		(42,246)		(16,054)
Acquisition and integration costs		—		—		(540)
Selling, general and administrative expenses		(91,650)		(94,427)		(76,753)
Change in fair value of contingent consideration		—		—		(42,246)
Income (loss) from operations		127,435		63,510		(44,855)
Selling, general and administrative expenses		(75,939)		(91,650)		(94,427)
Equity in earnings of investment		—		—		8,262
Income from operations		65,135		127,435		63,510
Net interest expense		(22,~~629~~777)		(1722,~~338~~629)		(1817,~~950~~338)
Losses related to convertible senior notes		~~(20,922)~~—		(3720,~~277~~922)		—(37,277)
Other expense, net		(31,~~922~~390)		(3,~~590~~922)		(233,~~330~~590)
Royalty income and other		21,~~102~~512		2,~~209~~102		32,~~692~~209
Income (loss) before income taxes		82,064		7,514		(75,181)
Income before income taxes		42,480		82,064		7,514
Income tax provision		2611,~~427~~653		1826,~~352~~427		1218,~~603~~352
Net income (loss)	$	5530,~~637~~827	$	~~(10~~55,~~838)~~637	$	(8710,~~784~~838)

Earnings (loss) per share of common stock:
Basic	$	0.3721	$	(0.~~07)~~37	$	(0.5807)
Diluted	$	0.3621	$	(0.~~07)~~36	$	(0.5807)

Weighted average common shares outstanding:
Basic		~~151~~148,~~989~~349		~~150~~151,~~917~~989		~~151~~150,~~276~~917
Diluted		~~154~~148,~~699~~454		~~150~~154,~~917~~699		~~151~~150,~~276~~917

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Net income (loss)	$	5530,~~637~~827	$	~~(10~~55,~~838)~~637	$	(8710,~~784~~838)
Other comprehensive income (loss) - foreign currency translation gain (loss), net of tax		~~(17~~63,~~560)~~079		22(17,~~304~~560)		~~(49~~22,~~237)~~304
Comprehensive income (loss)	$	38,077	$	11,466	$	(137,021)
Comprehensive income	$	93,906	$	38,077	$	11,466

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in thousands)


						Accumulated
						Other		Total
	Common Stock			Retained		Comprehensive		Shareholders’
	Shares	Amount		Earnings		Loss		Equity
Balance, December 31, 2021	151,124	$	1,292,479	$	411,072	$	(56,082)	$	1,647,469
Net loss	—		—		(87,784)		—		(87,784)
Foreign currency translation adjustments	—		—		—		(49,237)		(49,237)
Activity in company stock plans, net and other	811		(991)		—		—		(991)
Share-based compensation	—		7,252		—		—		7,252
Balance, December 31, 2022	151,935	$	1,298,740	$	323,288	$	(105,319)	$	1,516,709
Net loss	—		—		(10,838)		—		(10,838)
Foreign currency translation adjustments	—		—		—		22,304		22,304
Repurchase of convertible senior notes	1,500		(35,469)		—		—		(35,469)
Termination of capped calls	—		14,225		—		—		14,225
Repurchases of common stock	(1,584)		(11,988)		—		—		(11,988)
Activity in company stock plans, net and other	440		(92)		—		—		(92)
Share-based compensation	—		6,149		—		—		6,149
Balance, December 31, 2023	152,291	$	1,271,565	$	312,450	$	(83,015)	$	1,501,000
Net income	—		—		55,637		—		55,637
Foreign currency translation adjustments	—		—		—		(17,560)		(17,560)
Settlement of convertible debt conversion	—		(84)		—		—		(84)
Termination of capped calls	—		4,381		—		—		4,381
Repurchases of common stock	(2,867)		(29,821)		—		—		(29,821)
Activity in company stock plans, net and other	819		(468)		—		—		(468)
Share-based compensation	—		6,680		—		—		6,680
Balance, December 31, 2024	150,243	$	1,252,253	$	368,087	$	(100,575)	$	1,519,765
Net income	—		—		30,827		—		30,827
Foreign currency translation adjustments	—		—		—		63,079		63,079
Repurchases of common stock	(4,643)		(30,164)		—		—		(30,164)
Activity in company stock plans, net and other	1,586		(5,047)		—		—		(5,047)
Share-based compensation	—		6,086		—		—		6,086
Reclassification of fair value of modified liability awards	—		(4,634)		—		—		(4,634)
Balance, December 31, 2025	147,186	$	1,218,494	$	398,914	$	(37,496)	$	1,579,912

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Cash flows from operating activities:
Net income (loss)	$	5530,~~637~~827	$	~~(10~~55,~~838)~~637	$	(8710,~~784~~838)
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		137,202		138,423		128,725
Depreciation and amortization, excluding amortization of deferred certification and dry dock costs		134,538		137,202		138,423
Amortization of deferred recertification and dry dock costs		36,090		25,693		13,961
Amortization of deferred certification and dry dock costs		52,844		36,090		25,693
Deferred recertification and dry dock costs		(35,387)		(62,522)		(35,072)
Long-lived asset impairment		18,064		—		—
Payment of earnout consideration		(58,300)		—		—
Deferred certification and dry dock costs		(51,996)		(35,387)		(62,522)
Change in fair value of contingent consideration		—		42,246		16,054
Payment of earnout consideration		—		(58,300)		—
Amortization of debt discount		218		17		—
Change in fair value of contingent consideration		—		—		42,246
Amortization of debt issuance costs		2,132		2,485		2,334
Amortization of debt discount		240		218		17
Share-based compensation		7,266		6,510		7,451
Amortization of debt issuance costs		2,063		2,132		2,485
Deferred income taxes		10,606		11,532		4,386
Share-based compensation		6,568		7,266		6,510
Equity in earnings of investment		—		—		(8,262)
Deferred income taxes		(8,067)		10,606		11,532
(Gain) loss on disposition of assets, net		~~479~~—		~~(367)~~479		—(367)
Losses related to convertible senior notes		~~20,922~~—		3720,~~277~~922		—37,277
Unrealized foreign currency loss		623		8,310		21,596
Unrealized foreign currency losses		374		623		8,310
Changes in operating assets and liabilities:
Accounts receivable, net		13(37,~~736~~514)		~~(64~~13,~~520)~~736		(2964,~~865~~520)
Other current assets		116,~~139~~600		~~(22~~1,~~597)~~139		7(22,~~593~~597)
Income tax receivable, net of income tax payable		1(9,~~919~~512)		~~(418)~~1,919		(49418)
Accounts payable and accrued liabilities		(918,~~159~~433)		31(9,~~996~~159)		931,~~807~~996
Other, net		~~905~~153		~~9,230~~905		~~233~~9,230
Net cash provided by operating activities		~~186~~136,~~028~~749		~~152~~186,~~457~~028		51152,~~108~~457

Cash flows from investing activities:
Alliance acquisition, net of cash acquired		—		—		(112,625)
Capital expenditures		(16,342)		(23,303)		(19,588)
Capital expenditures		(23,303)		(19,588)		(33,504)
Proceeds from sale of assets		—		100		365
Distribution from equity investment, net		—		—		7,840
Proceeds from insurance recoveries		—		363		564
Proceeds from sale of assets		100		365		—
Net cash used in investing activities		(16,342)		(22,840)		(18,659)
Proceeds from insurance recoveries		363		564		—
Net cash used in investing activities		(22,840)		(18,659)		(138,289)

Cash flows from financing activities:
Proceeds from senior notes, net of discount		—		~~298,578~~—		—298,578
Payments related to convertible senior notes		~~(60,720)~~—		(~~261~~60,~~147~~720)		(35261,~~000~~147)
Repayment of MARAD Debt		(89,~~749~~186)		(8,~~333~~749)		(78,~~937~~333)
Proceeds from settlement of capped calls		~~4,381~~—		154,~~591~~381		—15,591
Debt issuance costs		~~(1,530)~~—		(61,~~817~~530)		(~~580~~6,817)
Repurchases of common stock		(2930,~~620~~214)		(1129,~~988~~620)		—(11,988)
Payments related to tax withholding for share-based compensation		(47,~~231~~404)		(14,~~757~~231)		(1,~~902~~757)
Proceeds from issuance of ESPP shares		1,~~859~~745		~~982~~1,859		~~575~~982
Payment of earnout consideration		~~(26,700)~~—		—(26,700)		—
Net cash provided by (used in) financing activities		(~~125~~45,~~310~~059)		25(125,~~109~~310)		~~(44~~25,~~844)~~109

Effect of exchange rate changes on cash and cash equivalents		(21,~~039)~~818		(152,~~827~~039)		(515,~~991~~827)
Net increase (decrease) in cash and cash equivalents		35,839		143,080		(138,016)
Net increase in cash and cash equivalents		77,166		35,839		143,080
Cash and cash equivalents:
Balance, beginning of year		~~332~~368,~~191~~030		~~189~~332,~~111~~191		~~327~~189,~~127~~111
Balance, end of year	$	~~368~~445,~~030~~196	$	~~332~~368,~~191~~030	$	~~189~~332,~~111~~191

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

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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization

Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix Energy Solutions Group, Inc. and its subsidiaries (“Helix” or the “Company”). 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. We provide a range of services to the oil and gas and renewable energy markets primarily in the ~~U.S.~~ Gulf ~~Coast~~of America (deepwater and shelf), ~~U.S. East Coast,~~ Brazil, North Sea, ~~Asia~~West ~~Pacific~~Africa and ~~West~~Asia ~~Africa~~Pacific regions. Our North Sea operations and our ~~U.S.~~ Gulf ~~Coast~~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 Operations

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 Sea Helix 1 (formerly 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~~to ~~from~~additional aenergy ~~carbon-based economy~~sources. 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.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the ~~U.S.~~ Gulf ~~Coast~~of America shelf, including offshore oilfield decommissioning and ‎reclamation, ~~dry tree~~ well plug and abandonment (“P&A”) services, subsea infrastructure flushing and abandonments (or removals), platform decommissioning and structure removals, subsea site clearance, project management, engineered solutions, intervention, ~~maintenance~~IRM, ~~repair,~~ heavy lift and commercial diving services. In addition to its end-of-life decommissioning services, our Shallow Water Abandonment segment offers services to support the full life cycle of offshore upstream and midstream industries, including oil and gas production through well intervention, coiled tubing (“CT”) and pumping, installations and construction, and IRM. Our Shallow Water Abandonment segment includes Helix Alliance that was acquired in July 2022 (Note 3), 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, plug and abandonment (‘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 ~~U.S.~~ Gulf ~~Coast~~of America.

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Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of our majority-owned subsidiaries. All material intercompany accounts and transactions have been eliminated.

Basis of Presentation

Our consolidated financial statements have been prepared in U.S. dollars in conformity with accounting principles generally accepted in the U.S. (“GAAP”). 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. We have made all adjustments that we believe are necessary for a fair presentation of our consolidated financial statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results may differ from those estimates.

Cash and Cash Equivalents

Cash and cash equivalents are highly liquid financial instruments with original maturities of three months or less. They are carried at cost plus accrued interest, which approximates fair value. Cash includes amounts pledged toward our asset-based credit agreement (Note 7) unless our ability to withdraw those amounts is restricted.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable are stated at the historical carrying amount, net of write-offs and allowance for credit losses. We perform ongoing credit evaluations of our customers and provide allowances for expected 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. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 18).

Business Combinations

Business combinations are accounted for using the acquisition method of accounting in accordance with Accounting Standards Codification (“ASC”) Topic 805, Business Combinations. The purchase price consideration is allocated to the assets acquired and liabilities assumed based upon estimates of their fair values as of the acquisition date. Fair values of the assets acquired and liabilities assumed are measured in accordance with ASC Topic 820, Fair Value Measurement, using income approach, cost approach and other applicable valuation techniques. The fair value of property, plant and equipment acquired from the acquisition was estimated primarily by applying the cost approach. The key assumptions of the cost approach include replacement cost new, physical deterioration, functional and economic obsolescence and economic useful life. The fair value of intangible assets acquired from the acquisition was estimated primarily by applying the income approach. The key assumptions of the income approach include revenue projections, royalty rates and economic useful life. For certain other assets and liabilities, those fair values are consistent with historical carrying values.

The purchase price allocation is subject to revision to reflect new information obtained about facts and circumstances that existed at the acquisition date. The purchase price consideration, as well as the estimated fair values of the assets acquired and liabilities assumed, is finalized as soon as practicable, but no later than one year from the closing of the acquisition.

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Contingent consideration payable in cash is initially measured at fair value and included as part of the purchase price and subsequently measured at fair value at the end of each reporting period with changes in value reported in “Change in fair value of contingent consideration” in the consolidated statements of operations until the liability is no longer contingent. Cash paid for the contingent consideration in an amount equaling to its initial fair value at the acquisition date is reported in financing cash flows and any amounts paid in excess of the initial fair value are reported in operating cash flows.

Acquisition and integration costs consist of legal and professional fees as well as costs incurred to integrate the acquiree’s operations and systems and to align its financial processes and procedures with those of Helix. Those costs are expensed as incurred and are presented separately from “Selling, general and administrative expenses” in the consolidated statements of operations.

Property and Equipment

Property and equipment (including oil and gas properties) acquired separately from a business combination is recorded initially at cost and subsequently depreciated on a straight-line basis over its estimated useful life. The cost of improvements is capitalized whereas the cost of repairs and maintenance is expensed as incurred.

Assets used in operations are assessed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable because such carrying amount may exceed the asset’s or asset group’s expected undiscounted cash flows. If the carrying amount of the asset or asset group is not recoverable and is greater than its fair value, an impairment charge is recorded. The amount of the impairment recorded is calculated as the difference between the carrying amount of the asset or asset group and its estimated fair value. Individual assets are evaluated for impairment at the lowest level where there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

Equity Investment

We have a 20% ownership interest in Independence Hub, LLC (“Independence Hub”), which is included in our Production Facilities segment. We account for our ownership interest in Independence Hub using the equity method of accounting. In May 2022, we received a net cash distribution of $7.8 million from the sale of the “Independence Hub” platform owned by Independence Hub. Our remaining investment in Independence Hub is insignificant.

Leases

Leases with a term greater than one year are recognized in the consolidated balance sheet as lease liabilities and right-of-use (“ROU”) assets. We have not recognized in the consolidated balance sheet leases with an initial term of one year or less. Lease liabilities and their corresponding ROU assets are recorded at the commencement date based on the present value of lease payments over the expected lease term. The lease term may include the option to extend or terminate the lease when it is reasonably certain that we will exercise the option. We use our incremental borrowing rate, which would be the rate incurred to borrow on a collateralized basis over a similar term in a similar economic environment, to calculate the present value of lease payments. ROU assets are adjusted for any initial direct costs paid or incentives received.

We separate our long-term vessel charters between their lease components and non-lease services. We estimate the lease component using the residual approach by estimating the non-lease services, which primarily include crew, repair and maintenance, and regulatory certification costs. For all other leases, we have not separated the lease components and non-lease services.

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

Deferred Certification and Dry Dock Costs

Our vessels and systems are required by regulation to be periodically recertified. Certification costs for a vessel are typically incurred while the vessel is in regulatory docking. We defer and amortize certification costs, including vessel dry dock costs, over the period that the certification applies, which generally ranges from 24 to 60 months. Major replacements and improvements that extend the economic useful life or functional operating capability of a vessel or system are capitalized and depreciated over the asset’s remaining economic useful life. Routine repairs and maintenance costs are expensed as incurred.

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Deferred Recertification and Dry Dock Costs

Our vessels and systems are required by regulation to be periodically recertified. Recertification costs for a vessel are typically incurred while the vessel is in regulatory docking. We defer and amortize recertification costs, including vessel dry dock costs, over the period that the certification applies, which generally ranges from 24 to 60 months. A recertification process, including vessel dry dock, typically lasts between one to three months for our vessels, a period during which a vessel or system is idle and generally not available to earn revenue. Major replacements and improvements that extend the economic useful life or functional operating capability of a vessel or system are capitalized and depreciated over the asset’s remaining economic useful life. Routine repairs and maintenance costs are expensed as incurred.

Revenue Recognition

Revenue from Contracts with Customers

We generate revenue in our Well Intervention segment by supplying vessels, personnel and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the duration of the intervention services. We may also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs and trenchers to provide subsea trenching and burial of pipelines and cables as well as seabed clearance for the oil and gas and the renewable energy markets and to provide offshore construction, well intervention support and IRM services to oil and gas companies. We also provide integrated robotic services by supplying vessels that deploy ROVs and trenchers. We generate revenue in our Production Facilities segment by supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties. We generate revenue in our Shallow Water Abandonment segment by providing decommissioning and intervention services with P&A and CT systems and personnel; by providing marine access to offshore facilities with liftboats, OSVs and the crew boat in order to perform decommissioning, intervention, diving and other work scopes; and by providing diving and platform decommissioning services with the heavy lift barge, DSVs and personnel.

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 generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments during which we provide our services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration received under a contract is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer. We generally consider integrated offerings to be a single performance obligation due to the interdependencies of the offerings.

The total transaction price for a contract is determined by estimating both fixed and unconstrained variable consideration expected to be earned over the term of the contract and excludes certain amounts that have been disputed by our customers. We generally do not provide significant financing or extended payment terms to our customers and do not adjust contract consideration for the time value of money. Estimated variable consideration, if any, is considered to be constrained and therefore is not included in the transaction price until it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.

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Dayrate Contracts. Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g., operating rate, standby rate, and repair rate). Invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.

Dayrate contracts also may contain fees charged to the customer for mobilizing and/or demobilizing equipment and personnel. Mobilization and demobilization are considered contract fulfillment activities, and related fees (subject to any constraint on estimates of variable consideration) are allocated to the single performance obligation and recognized ratably over the term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer.

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We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable as the amounts received are generally subject to uncertainty. Accordingly, these revenues are constrained and not recognized until the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.

A dayrate contract modification involving an extension of the contract by adding days of services is generally accounted for prospectively as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.

Lump Sum Contracts. Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.

We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue on a cumulative catch-up basis.

Income from Oil and Gas Production

Income from oil and gas production is recognized according to monthly oil and gas production volumes from the oil and gas properties that we own, and is included in revenues from our Production Facilities segment.

Income from Royalty Interests

Income from royalty interests is recognized according to our share of monthly oil and gas production volumes and is included in “Royalty income and other” in the consolidated statements of operations.

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Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) amounts billed to or advance payments received from customers, including upfront mobilization fees allocated to a single performance obligation and recognized ratably over the contract term and/or (ii) amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.

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Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract.

Income Taxes

Deferred income taxes are based on the differences between financial reporting and tax bases of assets and liabilities. We utilize the liability method of computing deferred income taxes. The liability method is based on the amount of current and future taxes payable using tax rates and laws in effect at the balance sheet date. Income taxes have been provided based upon the tax laws and rates in the countries in which operations are conducted and income is earned. A valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized.

We operate in multiple tax jurisdictions and our tax returns are subject to review and examination by local taxing authorities. We provide for uncertain tax positions and related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by local taxing authorities. AtInterest ~~December 31,~~and ~~2024,~~penalties weare ~~believe~~not wereported ~~have~~as ~~appropriately~~a ~~accounted~~component ~~for~~of ~~any~~income ~~unrecognized tax benefits~~taxes.

Share-Based Compensation

Share-based payment awards are classified as either equity or liability awards based on various factors such as award conditions, settlement features, substantive terms and past practices. Shared-based compensation is initially measured at the grant date based on the estimated fair value of an award and subsequently measured depending on their award conditions and classification. Forfeitures are recognized as they occur.

~~Restricted~~Our restricted stock awards are based solely on service conditions and are accounted for as equity awards. Compensation cost for restricted stock is the product of the grant date fair value of each share and the number of shares granted and is recognized over the applicable vesting period on a straight-line basis.

For the portions of our performance share unit (“PSU”) awards with a service and a market condition that are accounted for as equity awards, compensation cost is measured based on the grant date estimated fair value determined using a Monte Carlo simulation model and subsequently recognized over the vesting period on a straight-line basis. For the portions of our PSUs with a service and a performance condition that are accounted for as equity awards, compensation cost is initially measured based on the grant date fair value. Cumulative compensation cost is subsequently adjusted at the end of each reporting period to reflect the current estimation of achieving the performance condition. For equity PSU awards that are subsequently modified, if, at the modification date, it is probable that the original award would have vested, the cumulative compensation cost to be recognized would equal the grant date fair value of the original equity awards plus ~~the~~any incremental fair value of the modified liability awards.

57Our restricted stock unit (“RSU”) awards accounted for as liability awards are measured at their estimated fair value based on the closing share price of our common stock as of each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting.

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Restricted stock unit (“RSU”) awards accounted for as liability awards are measured at their estimated fair value based on the closing share price of our common stock as of each balance sheet date, and subsequent changes in the fair value of the awards are recognized in earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability RSUs equals the actual payout value upon vesting.

Asset Retirement Obligations

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

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Foreign Currency

Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. Results of operations for our non-U.S. dollar subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these non-U.S. dollar subsidiaries are translated into U.S. dollars using the exchange rate in effect at the end of the reporting period, and the resulting translation adjustments are included in other comprehensive income (loss) (“OCI”).

For transactions denominated in a currency other than a subsidiary’s functional currency, the effects of changes in exchange rates are reported in “Other income (expense), net” in the consolidated statements of operations. 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 years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, our foreign currency transaction losses totaled $1.57 million, $41.45 million and $234.4 million, respectively.

Earnings Per Share

We have shares of restricted stock issued and outstanding that are currently unvested. Because holders of shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our unrestricted common stock, we are required to compute earnings per share (“EPS”) under the two-class method in periods in which we have earnings. Under the two-class method, net income for each period is allocated based on the participation rights of both common shareholders and the holders of any participating securities as if earnings for the respective periods had been distributed. For periods in which we have a net loss we do not use the two-class method as holders of our restricted shares are not obligated to share in such losses.

Basic EPS is computed by dividing net income allocated to common shareholders or net loss by the weighted average shares of our common stock outstanding. Diluted EPS is computed in a similar manner after considering the potential dilutive effect of share-based awards and convertible senior notes and taking the more dilutive of the two-class method and the treasury stock method or if-converted method, as applicable. The dilutive effect of share-based awards is computed using the treasury stock method, as applicable, which includes the incremental shares that would be hypothetically vested in excess of the number of shares assumed to be hypothetically repurchased with the assumed proceeds. The effect of convertible senior notes is computed for the periods in which they are outstanding using the if-converted method, if dilutive, which assumes conversion of the convertible senior notes into shares of our common stock at the beginning of the period, giving income recognition for the add-back of related interest expense (net of tax).

Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable energy markets. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices and volatility, which are subject to many external factors. Our customers consist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, renewable energy companies and offshore engineering and construction firms. The percentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) were as follows: 2025 — Shell (18%) and Petrobras (10%); 2024 — Shell (12%) and Talos (12%); and 2023 — Apache (11%) and Shell (10%). The revenue concentrations are reported in our Well Intervention, Production Facilities and Shallow Water Abandonment segments.

As of December 31, 2025, 20% of our labor force was covered by collective bargaining agreements or similar arrangements and 18% of our labor force was covered by those agreements that will expire within one year.

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Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable energy markets. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and natural gas prices and volatility, which are subject to many external factors. Our customers consist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, renewable energy companies and offshore engineering and construction firms. The percentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) were as follows: 2024 — Shell (12%) and Talos (12%); 2023 — Apache (11%) and Shell (10%); and 2022 — Shell (15%). The revenue concentrations are reported in our Well Intervention, Production Facilities and Shallow Water Abandonment segments.

As of December 31, 2024, 19% of our labor force was covered by collective bargaining agreements or similar arrangements and 13% of our labor force was covered by those agreements that will expire within one year.

Fair Value Measurements

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

●

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

●

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

●

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

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

(a)

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

(b)

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

(c)

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

New Accounting Standards

New accounting standards adopted

In ~~November~~December 2023, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2023-0709, “Improvements to ~~Reportable~~Income ~~Segment~~Tax Disclosures,” which requires entities to disclose, on an annual ~~and interim~~ basis, ~~significant~~specific ~~segment~~categories ~~expenses~~in ~~that~~a ~~are~~tabular ~~regularly~~rate ~~provided~~reconciliation tousing ~~the~~both ~~chief~~percentages ~~operating~~and ~~decision~~reporting ~~maker~~currency ~~(the~~amounts ~~“CODM”)~~ and ~~included~~to ~~within~~provide ~~each~~additional ~~reported~~information ~~measure~~for ofreconciling ~~segment~~items ~~profit~~that ormeet ~~loss~~a asquantitative ~~well~~threshold. asThis anASU ~~amount~~also ~~for~~requires ~~other~~that ~~segment~~entities ~~items~~disclose byon ~~reportable~~an ~~segment~~annual ~~and~~basis: a) ~~description~~income oftaxes ~~its~~paid ~~composition.~~(net) ~~ASU~~disaggregated ~~No. 2023-07~~by ~~requires~~federal, ~~all~~state ~~annual~~and ~~disclosures~~foreign ~~about~~taxes; ab) ~~reportable~~income ~~segment’s~~taxes ~~profit~~paid or(net) ~~loss~~by ~~and~~individual ~~assets~~jurisdiction; toc) beincome ~~provided~~(or inloss) ~~interim~~from ~~periods~~continuing asoperations ~~well.~~before ~~Among~~income ~~other~~tax ~~things,~~expense ~~this~~(or ~~ASU~~benefit) ~~also~~between ~~requires~~domestic ~~that~~and aforeign; ~~public entity disclose the title~~ and ~~position~~d) ofincome ~~the~~tax ~~CODM~~expense ~~and~~(or anbenefit) ~~explanation~~from ofcontinuing ~~how~~operations ~~the~~by ~~CODM~~federal, ~~uses~~state ~~the~~and ~~reported~~foreign. ~~measure(s)~~Certain ofprevious ~~segment~~disclosure ~~profit~~requirements oron ~~loss~~unrecognized intax ~~assessing~~benefits ~~segment~~and ~~performance~~cumulative ~~and~~amount ~~deciding~~of ~~how~~temporary todifferences ~~allocate~~are ~~resources~~eliminated. We adopted ASU No. 2023-0709 onprospectively ~~a retrospective basis~~ starting with this Annual Report for the year ended December 31, ~~2024~~2025. The adoption of this ASU had no impact on our earnings or financial condition and did not have a material impact on our consolidated financial statements other than increased ~~segment~~income tax disclosures which are reflected in Note 148.

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New accounting standards issued but not yet effective

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.

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.

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Note 3 — Business Combinations

Alliance Acquisition

We expanded our service capabilities to the ~~U.S.~~ Gulf ~~Coast~~of America shelf market with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022, which we re-branded as Helix Alliance. The aggregate purchase price of the Alliance acquisition was $145.7 million, consisting of $119.0 million of cash on hand and the acquisition-date estimated fair value of $26.7 million related to the post-closing earnout consideration. During the fourth quarter 2023, we finalized the calculation and agreed with the seller in the Alliance transaction on an $85.0 million earnout, which was ~~reported~~paid atin ~~$85~~cash on April 3, 2024.0 ~~million~~For inthe ~~“Accrued~~year ~~liabilities”~~ended inDecember 31, ~~the~~2023, ~~accompanying~~we ~~consolidated~~recorded ~~balance~~$42.2 ~~sheet~~million asfor the change in fair value of ~~December 31~~the earnout consideration, ~~2023~~which ~~and~~is ~~paid~~reported in ~~cash~~the onaccompanying ~~April 3,~~consolidated ~~2024~~statement ~~(Note 4)~~of operations.

The pro forma summary table below presents the results of operations as if the Alliance acquisition had occurred on January 1, 2022 (in thousands). The unaudited pro forma summary includes certain transaction accounting adjustments as necessary and uses estimates and assumptions based on information available at the time. The pro forma summary is provided for illustrative purposes only and does not purport to represent Helix’s actual consolidated results of operations had the acquisition been completed as of the date presented, nor should it be considered indicative of Helix’s future consolidated results of operations.


	Year Ended
	December 31,
	2022
Revenues	$	952,837
Net loss		(79,686)

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Note 4 — Details of Certain Accounts

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


	December 31,
	~~2024~~2025		~~2023~~2024
Prepaids	$	2629,~~780~~345	$	2826,~~352~~780
Income tax receivable		27,~~635~~383		—2,635
Contract assets (Note 11)		1210,~~221~~871		512,~~824~~221
Deferred costs (Note 11)		3118,~~874~~678		3631,~~041~~874
Other		9,~~512~~580		159,~~006~~512
Total other current assets	$	8375,~~022~~857	$	8583,~~223~~022

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


	December 31,
	~~2024~~2025		~~2023~~2024
Prepaid charter (1)	$	12,544	$	12,544
Deferred costs (Note 11)		56,~~348~~910		~~587~~5,348
Other receivable (2)		2427,~~827~~291		2524,~~623~~827
Intangible assets with finite lives, net		3,~~630~~262		43,~~105~~630
Other		1,~~829~~411		1,~~964~~829
Total other assets, net	$	4851,~~178~~418	$	4448,~~823~~178

(1) Represents prepayments to the owner of the ~~Siem~~Sea Helix 1 and the Siem Helix 2, which may be used 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 field oil and gas properties we acquired from Marathon Oil Corporation in 2019.

Accrued liabilities consist of the following (in thousands):


	December 31,
	~~2024~~2025		~~2023~~2024
Accrued payroll and related benefits	$	4945,~~521~~463	$	5949,~~010~~521
Accrued interest		10,~~278~~102		410,~~181~~278
Income tax payable		—		1,938
Deferred revenue (Note 11)		17,115		14,914
Deferred revenue (Note 11)		14,914		32,763
Other		22,271		15,742
Earnout consideration (Note 3)		—		85,000
Total accrued liabilities	$	94,951	$	90,455
Other (1)		15,742		20,220
Total accrued liabilities	$	90,455	$	203,112

(1) During the third quarter 2023, we acquired five P&A systems and other assets for total consideration of $17.6 million including $6.0 million in cash in addition to credits towards future services offered by us. Amount as of December 31, 2023 included $9.0 million of those credits, which were increased by $2.4 million with a charge to “Other expense, net” during 2024 and were fully utilized as of December 31, 2024.

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


	December 31,
	~~2024~~2025		~~2023~~2024
Deferred revenue (Note 11)	$	~~699~~—	$	—699
Asset retirement obligations (Note 15)		6268,~~947~~770		6162,~~356~~947
Other (1)		3,325		4,892
Other		2,663		3,325
Total other non-current liabilities	$	6671,~~971~~433	$	66,~~248~~971

(1) Amount as of December 31, 2023 included $2.6 million of credits offered by us in exchange for the purchase of P&A equipment, which were fully utilized as of December 31, 2024 (see above).

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Note 5 — Property and Equipment

The following is a summary of the gross components of property and equipment (dollars in thousands):


		December 31,
	Estimated Useful Life	~~2024~~2025		~~2023~~2024
Vessels	15 to 30 years	$	2,~~383~~469,~~245~~762	$	2,~~406~~383,~~089~~245
Systems and equipment	5 to 15 years		~~345~~363,~~093~~271		~~337~~345,~~913~~093
ROVs and trenchers	5 to 10 years		~~261~~265,~~417~~483		~~252~~261,~~753~~417
Buildings and other	5 to 39 years		7958,~~000~~090		8179,~~816~~000
Total property and equipment		$	3,~~068~~156,~~755~~606	$	3,~~078~~068,~~571~~755

The Thunder Hawk field under our Production Facilities segment ceased production beginning mid-year 2024 due to a blockage in a well. Multiple attempts to resolve the blockage previously failed and a well workover was completed late February 2026. Given the combination of low oil prices and the increase in estimated costs associated with a workover, we determined that the remaining net book value was not recoverable as of December 31, 2025 and performed an asset impairment assessment review by comparing the fair value of the Thunder Hawk field to its remaining net book value. We estimated the fair value using an income approach by discounting the estimated future cash flows (Level 3 input) as of the trigger date and concluded that the remaining net book value of the Thunder Hawk field was fully impaired. As such, we recorded a long-lived asset impairment charge of $18.1 million for the year ended December 31, 2025.

Note 6 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2034. We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, ~~2024~~2025, the minimum sublease income to be received in the future was minimal.

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Operating lease cost	$	8790,~~569~~737	$	7287,~~775~~569	$	6172,~~067~~775
Variable lease cost		1112,~~113~~543		2111,~~423~~113		2021,~~562~~423
Short-term lease cost		5548,~~879~~318		5455,~~613~~879		2954,~~487~~613
Sublease income		(99117)		(~~1,113~~99)		(1,~~275~~113)
Net lease cost	$	~~154~~151,~~462~~481	$	~~147~~154,~~698~~462	$	~~109~~147,~~841~~698

Maturities of our operating lease liabilities as of December 31, ~~2024~~2025 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	7877,~~442~~129	$	54,~~324~~267	$	8381,~~766~~396
One to two years		6676,~~020~~334		34,~~442~~328		6980,~~462~~662
Two to three years		6165,~~771~~278		34,~~871~~088		6569,~~642~~366
Three to four years		5553,~~933~~006		3,~~368~~869		5956,~~301~~875
Four to five years		5259,~~748~~020		34,~~185~~636		5563,~~933~~656
Over five years		8627,~~257~~237		1511,~~736~~950		~~101~~39,~~993~~187
Total lease payments	$	~~401~~358,~~171~~004	$	3433,~~926~~138	$	~~436~~391,~~097~~142
Less: imputed interest		(8060,~~564~~774)		(98,~~567~~613)		(9069,~~131~~387)
Total operating lease liabilities	$	~~320~~297,~~607~~230	$	2524,~~359~~525	$	~~345~~321,~~966~~755

Current operating lease liabilities	$	5557,~~643~~240	$	43,~~339~~556	$	5960,~~982~~796
Non-current operating lease liabilities		~~264~~239,~~964~~990		2120,~~020~~969		~~285~~260,~~984~~959
Total operating lease liabilities	$	~~320~~297,~~607~~230	$	2524,~~359~~525	$	~~345~~321,~~966~~755

6261

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Maturities of our operating lease liabilities as of December 31, ~~2023~~2024 are as follows (in thousands):


			Facilities and
	Vessels		Equipment		Total
Less than one year	$	6778,~~488~~442	$	65,~~639~~324	$	7483,~~127~~766
One to two years		5566,~~453~~020		3,~~508~~442		5869,~~961~~462
Two to three years		3561,~~200~~771		13,~~289~~871		3665,~~489~~642
Three to four years		2655,~~245~~933		13,~~272~~368		2759,~~517~~301
Four to five years		352,~~040~~748		13,~~244~~185		455,~~284~~933
Over five years		—86,257		115,~~926~~736		1101,~~926~~993
Total lease payments	$	~~187~~401,~~426~~171	$	1534,~~878~~926	$	~~203~~436,~~304~~097
Less: imputed interest		(2280,~~419~~564)		(29,~~038~~567)		(2490,~~457~~131)
Total operating lease liabilities	$	~~165~~320,~~007~~607	$	1325,~~840~~359	$	~~178~~345,~~847~~966

Current operating lease liabilities	$	5655,~~602~~643	$	64,~~060~~339	$	6259,~~662~~982
Non-current operating lease liabilities		~~108~~264,~~405~~964		721,~~780~~020		~~116~~285,~~185~~984
Total operating lease liabilities	$	~~165~~320,~~007~~607	$	1325,~~840~~359	$	~~178~~345,~~847~~966

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


	December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Weighted average remaining lease term	5.90	years	35.19	years	43.01	years
Weighted average discount rate	7.8968	%	87.2089	%	78.8420	%

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Cash paid for operating lease liabilities	$	8088,~~642~~248	$	6880,~~788~~642	$	5868,~~129~~788
Right-of-use assets related to new operating lease obligations (1)		~~220~~37,~~945~~658		26220,~~502~~945		~~144~~26,~~134~~502

(1) Our operating lease additions are primarily related to the charter ~~extensions~~ for the ~~Siem~~Trym ~~Helix~~and 1,charter ~~Siem~~extensions ~~Helix~~for 2,the ~~Grand~~North ~~Canyon~~Sea IIEnabler ~~and Shelia Bordelon vessels~~ during the year ended December 31, ~~2024~~2025, ~~(Note~~the ~~16)~~charter extensions for the Sea Helix 1, the ~~vessel~~Siem ~~charters~~Helix ~~for~~2, the ~~Glomar~~Grand ~~Wave~~Canyon II and ~~North~~the ~~Sea~~Shelia ~~Enabler~~Bordelon ~~vessels~~ during the year ended December 31, ~~2023~~2024, and the ~~charter~~charters ~~extensions~~ for the ~~Siem~~Glomar ~~Helix~~Wave ~~1, Siem Helix 2, Grand Canyon II, Grand Canyon III~~ and ~~Shelia~~the ~~Bordelon~~North ~~vessels~~Sea Enabler during the year ended December 31, ~~2022~~2023.

See Note 16 for additional information on our significant leases including those not yet commenced as of December 31, 2025.

Note 7 — Long-Term Debt

Long-term debt consists of the following (in thousands):


	December 31,
	~~2024~~2025		~~2023~~2024
2026 Notes (fully redeemed March 2024)	$	—	$	40,199
MARAD Debt (matures February 2027)	$	14,645	$	23,831
MARAD Debt (matures February 2027)		23,831		32,580
2029 Notes (mature March 2029)		300,000		300,000
Gross debt		~~323~~314,~~831~~645		~~372~~323,~~779~~831
Unamortized debt discount		(~~1,186~~946)		(1,~~404~~186)
Unamortized debt issuance costs		(75,~~488~~704)		(97,~~653~~488)
Total debt		~~315~~307,~~157~~995		~~361~~315,~~722~~157
Less current maturities (1)		(9,~~186~~644)		(489,~~292~~186)
Long-term debt	$	~~305~~298,~~971~~351	$	~~313~~305,~~430~~971

(1) Current maturities as of December 31, ~~2023~~2025 ~~included the carrying amount of the 2026 Notes that were subject to conversion~~ and~~/or~~ ~~redemption in~~ 2024 ~~(see Note 19 for their fair value). Current maturities as of December 31, 2024 and 2023~~ both included the current portion of the MARAD Debt.

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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 4, 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,~~line ~~which~~that 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 byof 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 December 31, ~~2024~~2025, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity, based on the borrowing base, totaled $66110.69 million, net of $301.05 million of letters of credit issued and includes $2.5 million of cash pledged to the facility.

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

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%. We believe the agreements relating to the bonds and the terms and conditions of our obligations to MARAD in respect of the MARAD Debt were typical for U.S. government-guaranteed ship financing transactions when they were entered into, including customary restrictions on incurring additional liens on the Q4000 and trading restrictions with respect to the vessel as well as working capital requirements.

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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 ~~retire~~redeem ~~the~~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

During December 2023 and the first quarter 2024, we retired the 2026 Notes through various transactions using proceeds from the 2029 Notes as well as the issuance of our common stock.

In December 2023, we entered into privately negotiated agreements with certain holders of the 2026 Notes to repurchase $159.8 million aggregate principal amount of the 2026 Notes (the “2026 Notes Repurchases”) for 1.5 million shares of our common stock and aggregate cash payments of $229.7 million, plus accrued and unpaid cash interest of $3.8 million. We recognized pre-tax inducement charges of $37.4 million for the 2026 Notes Repurchases in the fourth quarter 2023, representing the total settlement value in excess of the total conversion value of the 2026 Notes Repurchases when the final negotiated offers were accepted. The conversion value paid in excess of the carrying amount of the 2026 Notes Repurchases is reflected in “Common stock” in the shareholders’ equity section of the accompanying consolidated balance sheets.

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In December 2023, $0.2 million aggregate principal amount of the 2026 Notes was tendered for conversion. We settled the conversions for $0.3 million cash in March 2024. The conversion value paid in excess of the $0.2 million carrying amount of the 2026 Notes that were tendered for conversion is reflected in “Common stock” in the shareholders’ equity section of the accompanying consolidated balance sheets.

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 consolidated statement of operations.

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. ~~Concurrently~~Concurrent with the settlement of the 2026 Notes Repurchases and the 2026 Notes Redemptions, we terminated the 2026 Capped Calls ~~with~~and ~~the~~received ~~counterparties, receiving~~ $20.0 million in cash (Note 9).

The 2026 Notes had a coupon interest rate of 6.75% per annum and an effective interest rate of 7.6%. For the years ended December 31, 2024, ~~2023~~ and ~~2022~~2023, total interest expense related to the 2026 Notes was $0.4 million, ~~$14.6 million~~ and $14.86 million, respectively, with coupon interest expense of $0.3 million, ~~$13.3 million~~ and $13.53 million, respectively, and the amortization of debt issuance costs of $0.1 million, ~~$1.3 million~~ and $1.3 million, respectively.

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 December 31, ~~2024~~2025, we were in compliance with these covenants.

The Convertible Senior Notes due 2023 (the “2023 Notes”) matured on September 15, 2023. Upon maturity of the 2023 Notes, we paid $29.6 million in cash to settle the conversion of $29.2 million aggregate principal amount of the notes, plus accrued and unpaid interest. We recorded the conversion value in excess of such principal amount converted to “Common stock” in the accompanying consolidated balance sheets. Notes representing the remaining $0.8 million aggregate principal amount of the 2023 Notes were redeemed at par, plus accrued and unpaid interest. The 2023 Notes had a coupon interest rate of 4.125% per annum and an effective interest rate of 4.8%. For the ~~years~~year ended December 31, 2023 ~~and 2022~~, total interest expense related to the 2023 Notes was $1.0 million ~~and $1.4 million~~, ~~respectively,~~ primarily from coupon interest expense.

WeScheduled ~~paid~~maturities ~~the~~of ~~$35~~our ~~million~~long-term ~~remaining~~debt ~~principal~~outstanding ~~amount~~as of ~~the 2022 Notes plus accrued interest by delivering cash at maturity on May 1, 2022. The effective interest rate for the 2022 Notes was 4.8%. For the year ended~~ December 31, ~~2022,~~2025 ~~total~~are ~~interest~~as ~~expense~~follows ~~related to the 2022 Notes was $0.6 million, primarily from coupon interest expense.~~(in thousands):

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Scheduled maturities of our long-term debt outstanding as of December 31, 2024 are as follows (in thousands):


	MARAD		2029
	Debt		Notes		Total
Less than one year	$	9,~~186~~644	$	—	$	9,~~186~~644
One to two years		95,~~644~~001		—		95,~~644~~001
Two to three years		~~5,001~~—		—		~~5,001~~—
Three to four years		—		—300,000		—300,000
Four to five years		—		300,000		300,000
Gross debt		14,645		300,000		314,645
Gross debt		23,831		300,000		323,831
Unamortized debt discount (1)		—		(946)		(946)
Unamortized debt discount (1)		—		(1,186)		(1,186)
Unamortized debt issuance costs (1)		(610)		(5,094)		(5,704)
Unamortized debt issuance costs (1)		(1,098)		(6,390)		(7,488)
Total debt		14,035		293,960		307,995
Total debt		22,733		292,424		315,157
Less current maturities		(9,644)		—		(9,644)
Less current maturities		(9,186)		—		(9,186)
Long-term debt	$	4,391	$	293,960	$	298,351
Long-term debt	$	13,547	$	292,424	$	305,971

(1)	Debt discount and debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Interest expense	$	3332,~~901~~973	$	2133,~~359~~901	$	2021,~~176~~359
Interest income		(1110,~~272~~196)		(411,~~021~~272)		(14,~~226~~021)
Net interest expense	$	22,~~629~~777	$	1722,~~338~~629	$	1817,~~950~~338

Note 8 — 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 consolidated financial statements.

~~Components~~On ofJuly 4, ~~income~~2025, ~~tax~~the ~~provision~~One ~~(benefit)~~Big ~~reflected~~Beautiful Bill Act was passed into law. The legislation provides us with benefits that are temporary in ~~the~~nature ~~consolidated~~with ~~statements~~no ofmaterial ~~operations~~impact ~~consist~~on ofour income tax expense or effective tax rate for the ~~following~~year ~~(in~~ended ~~thousands):~~December 31, 2025.

Components of income tax provision reflected in the consolidated statements of operations consist of the following (in thousands):


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Current tax provision (benefit):
Domestic	$	(97)	$	1,510	$	—
Federal	$	1,673	$	(107)	$	1,452
Foreign		15,918		5,310		8,217
State		53		10		58
Total current	$	15,821	$	6,820	$	8,217
Foreign		17,994		15,918		5,310
Total current	$	19,720	$	15,821	$	6,820
Deferred tax provision (benefit):
Domestic	$	11,638	$	8,689	$	1,167
Federal	$	(11,993)	$	11,562	$	8,990
Foreign		(1,032)		2,843		3,219
State		46		76		(301)
Total deferred	$	10,606	$	11,532	$	4,386
Foreign		3,880		(1,032)		2,843
Total income tax provision	$	26,427	$	18,352	$	12,603
Total deferred	$	(8,067)	$	10,606	$	11,532
Total income tax provision	$	11,653	$	26,427	$	18,352

Components of income ~~(loss)~~ before income taxes are as follows (in thousands):


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Domestic	$	(3248,~~980~~969)	$	(3132,~~646~~980)	$	(1331,~~745~~646)
Foreign		~~115~~91,~~044~~449		39115,~~160~~044		~~(61~~39,~~436)~~160
Income (loss) before income taxes	$	82,064	$	7,514	$	(75,181)
Income before income taxes	$	42,480	$	82,064	$	7,514

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~~The~~Reconciling ~~primary~~items ~~differences~~ between the ~~income tax provision (benefit) at the~~ U.S. statutory rate and our ~~actual~~effective ~~income~~ tax ~~provision~~rate ~~(benefit)~~for the year ended December 31, 2025 are as follows (dollars in thousands):


	Year Ended ~~December 31,~~
	~~2024~~December 31, 2025				~~2023~~				~~2022~~
Taxes at U.S. statutory rate	$	17,233	21.0	%	$	1,578	21.0	%	$	(15,788)	21.0	%
U.S. federal statutory tax rate	$	8,921	21.0	%
Foreign tax provision		7,944	9.7			1,590	21.2			18,011	(24.0)
Domestic federal:
Change in valuation allowance		(5,230)	(6.4)			6,374	84.8			8,110	(10.8)
Foreign tax credits		(518)	(1.2)
Non-deductible expenses		3,105	3.8			2,926	38.9			2,366	(3.1)
Non-taxable or non-deductible items:
Losses related to convertible senior notes (1)		4,078	5.0			6,372	84.8			—	—
Non-deductible compensation		1,266	3.0
Other		(703)	(0.9)			(488)	(6.5)			(96)	0.1
Other permanent adjustments		69	0.2
Income tax provision	$	26,427	32.2	%	$	18,352	244.2	%	$	12,603	(16.8)	%
Effect of cross-border tax laws (1)		1,472	3.4
Return-to-provision		(4,178)	(9.8)
Changes in valuation allowances		2,907	6.8
State and local income taxes, net of federal income tax effect (2)		89	0.2
Foreign tax effects:
U.K.:
Internal restructuring		(17,310)	(40.8)
Changes in valuation allowances		15,685	36.9
Other reconciling items		(598)	(1.4)
Brazil:
Statutory tax rate difference		5,025	11.8
Other reconciling items		22	0.1
Luxembourg:
Rate change		2,430	5.7
Changes in valuation allowances		(4,812)	(11.3)
Other reconciling items		638	1.5
Taiwan:
Non-taxable or non-deductible items		(1,906)	(4.5)
Return-to-provision		(949)	(2.2)
Other reconciling items		310	0.7
Nigeria:
Statutory tax rate difference		646	1.5
Non-refundable income taxes withheld		1,947	4.6
Return-to-provision		(2,094)	(4.9)
Withholding taxes		1,430	3.4
Malaysia – Withholding taxes		1,707	4.0
Other foreign jurisdictions		(546)	(1.3)
Effective tax rate	$	11,653	27.4	%

(1)	Net of jurisdictional foreign tax credits.

(2)	For the year ended December 31, 2025, state taxes were primarily related to Louisiana.

The primary differences between the income tax provision at the U.S. statutory rate and our actual income tax provision for the years ended December 31, 2024 and 2023 are as follows (dollars in thousands):


	Year Ended December 31,
	2024				2023
Taxes at U.S. statutory rate	$	17,233	21.0	%	$	1,578	21.0	%
Foreign tax provision		7,944	9.7			1,590	21.2
Change in valuation allowance		(5,230)	(6.4)			6,374	84.8
Non-deductible expenses		3,105	3.8			2,926	38.9
Losses related to convertible senior notes ⁽¹⁾		4,078	5.0			6,372	84.8
Other		(703)	(0.9)			(488)	(6.5)
Income tax provision	$	26,427	32.2	%	$	18,352	244.2	%

(1)	Relates to the non-deductibility for U.S. federal income tax purposes of certain charges associated with the 2026 Notes Repurchases and the 2026 Notes Redemptions (Note 7).

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~~After applying the existing Pillar Two laws, we have no incremental Pillar Two taxes.~~ Our ~~income~~operations isare subject to current taxation in the U.S. (21% statutory rate) and the U.K. (25% statutory rate), or subject to taxation in jurisdictions with statutory rates greater than the Pillar Two threshold of 15%. WeAfter ~~will~~applying ~~continue~~the toexisting ~~monitor~~Pillar ~~our~~Two ~~income~~laws, ~~attributes,~~we ~~and~~have ~~taxes~~no byincremental ~~jurisdiction as well as the impact of new and proposed~~ Pillar Two ~~legislation~~taxes.

For the year ended December 31, 2025, the valuation allowance increased by $9.6 million, which was predominantly driven by current year activity, including adjustments to prior year returns, and an internal restructuring.

For the year ended December 31, 2024, the valuation allowance decreased by $5.7 million, which included a $3.2 million decrease related to a valuation allowance release in Brazil, a $5.2 million increase in assessment on the realizability of U.S. group foreign tax credit carryforward, and a $7.7 million decrease in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

For the year ended December 31, 2023, the valuation allowance increased by $59.0 million, which included a $51.4 million increase for a change in assessment of our Luxembourg net operating losses, and a $7.6 million increase in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

For the year ended December 31, 2022, the $8.1 million increase in valuation allowance was predominantly driven by current year activity and the related change in unrealizable net deferred tax assets.

Deferred income taxes result from the effect of transactions that are recognized in different periods for financial and tax reporting purposes. The nature of these differences and the income tax effect of each are as follows (in thousands):


	December 31,
	~~2024~~2025		~~2023 (1)~~2024
Deferred tax liabilities:
Depreciation	$	~~126~~102,~~218~~597	$	~~132~~126,~~178~~218
Operating leases		7771,~~773~~064		3877,~~579~~773
Prepaid and other		1413,~~090~~641		1314,~~105~~090
Total deferred tax liabilities	$	~~218~~187,~~081~~302	$	~~183~~218,~~862~~081
Deferred tax assets:
Net operating losses	$	(7162,~~244~~107)	$	(7871,~~250~~244)
Operating leases		(7771,~~773~~064)		(3877,~~579~~773)
Asset retirement obligations		(1314,~~219~~442)		(1213,~~885~~219)
Reserves, accrued liabilities and other		(1719,~~253~~069)		(2417,~~708~~253)
Total deferred tax assets		(~~179~~166,~~489~~682)		(~~154~~179,~~422~~489)
Valuation allowance		7584,~~381~~951		8175,~~115~~381
Net deferred tax liabilities	$	~~113~~105,~~973~~571	$	~~110~~113,~~555~~973

(1) Amounts revised for an immaterial correction in the presentation of certain deferred taxes. There is no impact to the net deferred tax liabilities or consolidated financial statements.

At December 31, 2025, our U.S. tax attributes included $8.1 million in foreign tax credit carryforwards, which expire between 2033 and 2035. Our non-U.S. net operating losses totaled $257.6 million, which included $210.7 million net operating losses in Luxembourg, which expire between 2035 and 2041, and $46.9 million net operating losses in the U.K., which do not expire under local tax law.

We operate in multiple tax jurisdictions and our tax returns are subject to review and examination by local taxing authorities. We have filed, and will continue to file, our income tax returns based on the tax laws in effect for each year and have recorded and paid our tax liabilities appropriately. Although we cannot predict the final outcome of any review and/or examination by such taxing authorities, we do not believe their resolution would have a material impact on our consolidated financial statements. The tax periods from 2021 through 2025 are open to review and examination by the U.S. Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2020 through 2025.

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AtComponents ~~December 31,~~of ~~2024,~~income ~~our~~taxes ~~U.S.~~paid ~~tax attributes included $8.1 million in tax credits, which are subject to a full valuation allowance. Our non-U.S.~~ (net ~~operating~~of ~~losses~~refunds ~~totaled~~received) ~~$283.7~~by ~~million,~~jurisdiction ~~which~~during ~~included~~the ~~$228.7~~year ~~million~~ended ~~net operating losses in Luxembourg~~December 31, ~~and~~2025 ~~$55.0~~are ~~million~~as ~~net~~follows ~~operating losses~~ (in ~~the U.K. and Brazil, which do not expire under local tax law.~~thousands):

We file tax returns in the U.S. and in various state, local and non-U.S. jurisdictions. We anticipate that any potential adjustments to our state, local and non-U.S. jurisdiction tax returns by taxing authorities would not have a material impact on our financial position. The tax periods from 2021 through 2024 are open to review and examination by the U.S. Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2020 through 2024.


		Year Ended
		December 31, 2025
U.S. federal		$	9,500
U.S. state and local:
Louisiana			53
Foreign:
Brazil			9,060
Malaysia			1,707
Nigeria			6,868
Norway			2,360
Other			(316)
Total foreign			19,679
Total taxes paid, net		$	29,232

Note 9 — Shareholders’ Equity

Our amended and restated Articles of Incorporation provide for authorized Common Stock of 240,000,000 shares with no stated par value per share and 5,000,000 shares of preferred stock, $0.01 par value per share, issuable in one or more series.

In connection with the 2026 Notes offering (Note 7), we entered into the 2026 Capped Calls with three separate option counterparties. The 2026 Capped Calls were intended to offset some or all of the potential dilution to Helix common shares or increases to the economic cost caused by any conversion of the 2026 Notes up to the cap price. ~~Concurrently~~Concurrent with the 2026 Notes Repurchases in December 2023, we terminated a proportionate amount of the 2026 Capped Calls and received $15.6 million in cash, recognizing an increase to “Common stock” of $14.2 million and a $1.4 million gain. 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 consolidated balance sheet.

Note 10 — Share Repurchase Programs

In February 2023, our Board of Directors (our “Board”) authorized a share repurchase program (the “2023 Repurchase Program”). Under the 2023 Repurchase Program, we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. Concurrent with the authorization of the 2023 Repurchase Program, our Board revoked the prior authorization to repurchase shares of our common stock in an amount equal to any equity issued to our employees, officers and directors under our share-based compensation plans, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our Employee Stock Purchase Plan (the “ESPP”) (Note 13). ~~During~~Pursuant ~~2024~~to the 2023 Repurchase Program, we repurchased a total of 24,~~867~~643,~~293~~060 shares of our common stock for approximately $2930.60 million during 2025, ora antotal ~~average~~of 2,867,293 shares of ~~$10.33~~our ~~per~~common ~~share,~~stock ~~and~~for ~~during~~approximately ~~2023~~$29.6 wemillion ~~repurchased~~during 2024, and a total of 1,584,045 shares of our common stock for approximately $12.0 million, orduring an2023. ~~average~~As of December 31, 2025, approximately $7128.574 ~~per~~million ~~share,~~remained ~~pursuant~~authorized tofor the repurchase of shares 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 as well as a plan established under Rule 10b5-1 under the Exchange Act, ~~but~~and may also be made through privately negotiated transactions or future 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.

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Note 11 — Revenue from Contracts with Customers

Disaggregation of Revenue

The following table provides information about disaggregated revenue by contract duration (in thousands):


	Well				Shallow Water		Production		Intercompany		Total
	Intervention		Robotics		Abandonment		Facilities		Eliminations		Revenue
Year ended December 31, 2024
Short-term	$	496,164	$	156,656	$	154,280	$	—	$	(6,782)	$	800,318
Long-term		333,698		141,022		32,699		88,709		(37,886)		558,242
Total	$	829,862	$	297,678	$	186,979	$	88,709	$	(44,668)	$	1,358,560

Year ended December 31, 2023
Short-term	$	443,332	$	133,740	$	241,416	$	—	$	(3,441)	$	815,047
Long-term		264,386		124,135		33,538		87,885		(35,263)		474,681
Total	$	707,718	$	257,875	$	274,954	$	87,885	$	(38,704)	$	1,289,728

Year ended December 31, 2022
Short-term	$	395,867	$	97,533	$	124,810	$	—	$	(635)	$	617,575
Long-term		112,464		94,388		—		82,315		(33,642)		255,525
Total	$	508,331	$	191,921	$	124,810	$	82,315	$	(34,277)	$	873,100

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 table provides information about disaggregated revenue by market strategy (in thousands):


	Well				Shallow Water		Production		Intercompany		Total
	Intervention		Robotics		Abandonment		Facilities		Eliminations		Revenue
Year ended December 31, 2024
Year ended December 31, 2025
Production maximization	$	211,589	$	111,006	$	6,459	$	72,693	$	(10,460)	$	391,287
Decommissioning		507,977		36,052		193,098		—		(22,042)		715,085
Renewables		—		157,226		76		—		—		157,302
Other		9,805		19,069		—		—		(1,074)		27,800
Total	$	729,371	$	323,353	$	199,633	$	72,693	$	(33,576)	$	1,291,474

Year ended December 31, 2024 (1)
Production maximization	$	408,791	$	117,207	$	8,469	$	88,709	$	(29,678)	$	593,498
Decommissioning		416,057		17,717		178,462		—		(14,272)		597,964
Renewables		—		152,306		—		—		—		152,306
Other		5,014		10,448		48		—		(718)		14,792
Total	$	829,862	$	297,678	$	186,979	$	88,709	$	(44,668)	$	1,358,560

Year ended December 31, 2023
Year ended December 31, 2023 (1)
Production maximization	$	228,649	$	103,692	$	13,825	$	87,885	$	(17,824)	$	416,227
Decommissioning		458,437		47,768		261,129		—		(18,690)		748,644
Renewables		—		99,861		—		—		—		99,861
Other		20,632		6,554		—		—		(2,190)		24,996
Total	$	707,718	$	257,875	$	274,954	$	87,885	$	(38,704)	$	1,289,728

Year ended December 31, 2022
Production maximization	$	302,409	$	66,068	$	9,059	$	82,315	$	(18,115)	$	441,736
Decommissioning		194,985		24,289		115,509		—		(14,977)		319,806
Renewables		635		82,793		—		—		(635)		82,793
Other		10,302		18,771		242		—		(550)		28,765
Total	$	508,331	$	191,921	$	124,810	$	82,315	$	(34,277)	$	873,100

(1)	For the years ended December 31, 2024 and 2023, $27.6 million and $25.0 million, respectively, have been removed from Well Intervention segment revenues and related intersegment eliminations. See Note 14 regarding this change in prior year reported segment information.

Contract Balances

Net contract assets as of December 31, 2025 and 2024 were $10.9 million and $12.2 million, respectively, and are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 4). The decrease in net contract assets was primarily attributable to less accrued revenues related to lump sum demobilization fees. We had no credit losses on our contract assets for the years ended December 31, 2025, 2024 and 2023.

Net contract liabilities as of December 31, 2025 and 2024 totaled $17.1 million and $15.6 million, respectively, and are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 4). The increase was primarily attributable to a larger amount of deferred mobilization fees for work that has not yet been completed. Revenue recognized for the years ended December 31, 2025, 2024 and 2023 included $19.9 million, $36.3 million and $8.7 million, respectively, that were included in the contract liability balance at the beginning of each period.

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Contract Balances

Net contract assets as of December 31, 2024 and 2023 were $12.2 million and $5.8 million, respectively, and are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 4). The increase in net contract assets was primarily attributable to 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 years ended December 31, 2024, 2023 and 2022.

Net contract liabilities as of December 31, 2024 and 2023 totaled $15.6 million and $32.8 million, respectively, and are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 4). The decrease was primarily attributable to the reduction in deferred mobilization revenue due to the timing of mobilization payments for contracts. Net contract liabilities as of December 31,2023 also included amounts billed to the customer in excess of revenue recognized for a lump sum contract. Revenue recognized for the years ended December 31, 2024, 2023 and 2022 included $36.3 million, $8.7 million and $7.4 million, respectively, that were included in the contract liability balance at the beginning of each period.

Performance Obligations

As of December 31, ~~2024~~2025, $1.43 billion related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $~~680~~693.6 million, $~~383~~391.84 million and $~~347~~225.27 million in ~~2025,~~ 2026, 2027 and ~~2027~~2028 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 December 31, ~~2024~~2025.

For the years ended December 31, 2025, 2024 and 2023, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial. For the year ended December 31, 2022, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were $1.0 million, which resulted from the retrospective application of certain contractual adjustments.

Contract Fulfillment Costs

Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 4). Our deferred contract costs as of December 31, ~~2024~~2025 and ~~2023~~2024 totaled $3725.26 million and $3637.62 million, respectively. For the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we recorded $6268.90 million, $4362.29 million and $2943.72 million, respectively, related to amortization of deferred contract costs. There were no material impairment losses on deferred contract costs for any period presented.

Note 12 — Earnings Per Share

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

Year Ended December 31,

~~2024~~2025

~~2023~~2024

~~2022~~2023

Income

Basic:

Net income (loss)

5530,~~637~~827

~~(10~~55,~~838)~~637

(8710,~~784~~838)

Less: Undistributed earnings allocated to participating securities

(5322)

—(53)

—

Net income (loss) available to common shareholders, basic

5530,~~584~~805

~~151~~148,~~989~~349

~~(10~~55,~~838)~~584

~~150~~151,~~917~~989

(8710,~~784~~838)

~~151~~150,~~276~~917

Earnings (loss) per share, basic

0.3721

(0.~~07)~~37

(0.5807)


		Year Ended December 31,
		2025					2024					2023
		Income			Shares		Income			Shares		Income			Shares
Diluted:
Net income (loss) available to common shareholders, basic		$	30,805		148,349		$	55,584		151,989		$	(10,838)		150,917
Effect of dilutive securities:
Share-based awards other than participating securities			—		105			—		2,710			—		—
Undistributed earnings reallocated to participating securities			—		—			1		—			—		—
Net income (loss) available to common shareholders, diluted		$	30,805		148,454		$	55,585		154,699		$	(10,838)		150,917

Earnings (loss) per share, diluted		$	0.21				$	0.36				$	(0.07)

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	Year Ended December 31,
	2024			2023			2022
	Income		Shares	Income		Shares	Income		Shares
Diluted:
Net income (loss) available to common shareholders, basic	$	55,584	151,989	$	(10,838)	150,917	$	(87,784)	151,276
Effect of dilutive securities:
Share-based awards other than participating securities		—	2,710		—	—		—	—
Undistributed earnings reallocated to participating securities		1	—		—	—		—	—
Net income (loss) available to common shareholders, diluted	$	55,585	154,699	$	(10,838)	150,917	$	(87,784)	151,276

Earnings (loss) per share, diluted	$	0.36		$	(0.07)		$	(0.58)

We had a net loss for the year ended December 31, 2023. 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):

We had net losses for the years ended December 31, 2023 and 2022. Accordingly, our diluted EPS calculation for these periods 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 periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):


		Year Ended
		December 31, 2023
Diluted shares (as reported)		150,917
Share-based awards		3,154
Total		154,071


	Year Ended December 31,
	2023	2022
Diluted shares (as reported)	150,917	151,276
Share-based awards	3,154	2,158
Total	154,071	153,434

The following potentially dilutive shares related to the 2023 Notes and the 2026 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):

The following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2026 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):


	Year Ended December 31,
	2025		2024		2023
2023 Notes	—		—		2,247
2026 Notes	—		1,297		28,139


	Year Ended December 31,
	2024	2023	2022
2022 Notes	—	—	600
2023 Notes	—	2,247	3,168
2026 Notes	1,297	28,139	28,676

We have outstanding RSUs (Note 13) 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.

We have outstanding RSUs (Note 13) 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 13 — 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”). The 2005 Incentive Plan is administered by the Compensation Committee of our Board (the “Compensation Committee”). The Compensation Committee also determines the type of award to be made to each recipient and, as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The Compensation Committee may grant various forms of award in accordance with the 2005 Incentive Plan. Awards that have been granted to employees under the 2005 Incentive Plan have a vesting period of three years (or 33% per year) with the exception of PSUs, which vest in amounts in accordance with their terms on the third anniversary date of the grant.

On May 15, 2024, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan, which, among other things, authorizes 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy. The 2005 Incentive Plan currently has 24.3 million shares authorized for issuance, which includes a maximum of 2.0 million shares that may be granted as incentive stock options. As of December 31, ~~2024~~2025, there were approximately 98.45 million shares of our common stock available for issuance under the 2005 Incentive Plan, assuming outstanding equity classified PSUs vest in shares of our common stock at 100% of the original awards and nooutstanding liability classified PSUs and RSUs are settled in cash. No incentive stock options are currently outstanding.

72The following grants of share-based awards were made in 2025 under the 2005 Incentive Plan:

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The following grants of share-based awards were made in 2024 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, 2024 (1)	RSU	375,730	$	10.28	33% per year over three years
January 1, 2025 (1)	RSU	443,401	$	9.32	33% per year over three years
January 1, 2024 (1)	PSU	351,410	$	12.30	100% on December 31, 2026
January 1, 2025 (2)	PSU	397,264	$	10.56	100% on December 31, 2027
January 1, 2024 (2)	Restricted stock	5,776	$	10.28	100% on January 1, 2026
January 1, 2025 (3)	Restricted stock	3,018	$	9.32	100% on January 1, 2027
April 1, 2024 (2)	Restricted stock	2,595	$	10.84	100% on January 1, 2026
December 10, 2025 (3)	Restricted stock	124,140	$	7.25	100% on December 10, 2026
July 1, 2024 (2)	Restricted stock	2,356	$	11.94	100% on January 1, 2026
October 1, 2024 (2)	Restricted stock	2,534	$	11.10	100% on January 1, 2026
December 11, 2024 (2)	Restricted stock	89,286	$	10.08	100% on December 11, 2025

(1) Reflects grants to ~~certain~~our executive officers ~~including~~and ~~our~~certain ~~executive~~other officers.

(2) Reflects grants to ~~certain independent members of~~ our ~~Board~~executive officers.

(3)	Reflects grants to certain independent members of our Board.

In January 2025, we granted certain officers 443,401 RSUs and 397,264 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $9.32 per unit or $4.1 million. The grant date fair value of the PSUs was $10.56 per unit or $4.2 million. PSUs and RSUs issued in 2025 are payable in either cash or stock, or a combination thereof, at the discretion of the Compensation Committee. Also in January 2025, we granted $6.7 million of fixed value cash awards to select management employees under the 2005 Incentive Plan.72

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In January 2026, we granted certain officers 719,298 RSUs and 605,661 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $6.27 per unit or $4.5 million. The grant date fair value of the PSUs was $6.93 per unit or $4.2 million. PSUs and RSUs issued in 2026 are payable in either cash or stock, or a combination thereof, at the discretion of the Compensation Committee. Also in January 2026, we granted $6.8 million of fixed value cash awards to select management employees under the 2005 Incentive Plan.

Restricted Stock Awards

We grant restricted stock to members of our Board and from time to time our executive officers and select management employees. The following table summarizes information about our restricted stock:


	Year Ended December 31,
	~~2024~~2025			~~2023~~2024			~~2022~~2023
		Grant Date			Grant Date			Grant Date
	Shares	Fair Value (1)		Shares	Fair Value (1)		Shares	Fair Value (1)
Awards outstanding at beginning of year	~~193~~114,~~129~~331	$	79.5290	~~387~~193,~~628~~129	$	67.7052	~~853~~387,~~726~~628	$	56.6270
Granted	~~102~~127,~~547~~158		107.1830	~~148~~102,~~224~~547		810.6818	~~253~~148,~~358~~224		58.3368
Vested (2)	(~~146~~104,~~947~~110)		79.2579	(~~342~~146,~~723~~947)		7.1025	(~~719~~342,~~456~~723)		47.9410
Forfeited	~~(34,398)~~—		~~8.70~~—	—(34,398)		—8.70	—		—
Awards outstanding at end of year	~~114~~137,~~331~~379	$	97.9058	~~193~~114,~~129~~331	$	79.5290	~~387~~193,~~628~~129	$	67.7052

(1)	Represents the weighted average grant date fair value, which is based on the quoted closing market price of our common stock on the trading day prior to the date of grant.

(2) During the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, total fair value of vested restricted stock was $10.58 million, $21.95 million and $2.9 million, respectively.

For the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, $1.0 million, $1.30 million and $21.53 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost and the weighted average vesting period associated with unvested restricted stock at December 31, ~~2024~~2025 were approximately $0.9 million and 0.89 years, respectively.

PSU Awards

Our outstanding PSUs ~~granted~~can ~~beginning in January 2021 may~~ be settled in either cash or shares of our common stock, or a combination thereof, ~~upon vesting~~ at the discretion of the Compensation Committee 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% containing a service and market condition based on the performance of our common stock against peer group companies, ~~(TSR~~and ~~component~~(ii), 50% ~~which~~containing ~~component contains~~ a service and aperformance ~~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 athe three-year period with the maximum amount of the award being 200% of the original PSU awards and the minimum amount being zero.

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The following table summarizes information about our PSU awards:

Year Ended December 31,

~~2024~~2025

~~2023~~2024

~~2022~~2023

Grant Date

Units

Fair Value (1)

Units

Fair Value (1)

Units

Fair Value (1)

PSU awards outstanding at beginning of year

21,~~007~~906,~~584~~613

57.7101

12,~~888~~007,~~024~~584

65.2571

1,~~381~~888,~~469~~024

86.3425

Granted

~~351~~397,~~410~~264

1210.3056

~~489~~351,~~498~~410

912.2630

1489,~~065,705~~498

49.2526

Vested (2)

(~~452~~1,~~381~~065,705)

54.3325

(~~369~~452,~~938~~381)

135.1533

(~~559~~369,~~150~~938)

713.6015

PSU awards outstanding at end of year

1,~~906~~238,~~613~~172

710.0153

21,~~007~~906,~~584~~613

57.7101

12,~~888~~007,~~024~~584

65.2571

(1)	Represents the weighted average grant date fair value.

(2) During the years ended December 31, 2024, 2023 and 2022, our 2021, 2020 and 2019 PSU awards vested at 818,812 shares, 285,778 shares and 876,469 shares, respectively, of our common stock with a total market value of $8.4 million, $3.6 million and $3.2 million, respectively.73

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(2)

During the year ended December 31, 2025, our 2022 PSU awards 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. During the years ended December 31, 2024 and 2023, our 2021 and 2020 PSU awards vested at 818,812 shares and 285,778 shares, respectively, with a total market value of $8.4 million and $3.6 million, respectively.

For the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, $75.31 million, $47.83 million and $4.8 million, respectively, were recognized as share-based compensation related to PSUs. In connection with the Compensation Committee’s decision in December 2025 to cash settle the 2023 PSU awards in 2026, 489,498 PSUs, which were previously accounted for as equity awards, were reclassified as liability awards with a liability balance of $4.6 million, reflecting the estimated fair value of the modified awards as of December 31, 2025. The cumulative compensation cost recognized in excess of the estimated fair value of the modified liability PSU awards is reflected in equity. For the year ended December 31, 2024, we recognized incremental compensation cost of $1.1 million related to the equity-to-liability award modification of 86,538 PSUs granted in 2022 to one of our officers. Future compensation cost and the weighted average vesting period associated with unvested PSU awards at December 31, ~~2024~~2025 were approximately $54.34 million and 0.69 year, respectively.

RSU Awards

Our ~~currently~~ outstanding RSUs ~~may~~can be settled in either cash or shares of our common stock, or a combination thereof, ~~upon vesting~~ at the discretion of the Compensation Committee upon vesting and generally have been accounted for as liability awards.

The following table summarizes information about our RSU awards:

Year Ended December 31,

~~2024~~2025

~~2023~~2024

~~2022~~2023

Grant Date

Units

Fair Value (1)

Units

Fair Value (1)

Units

Fair Value (1)

RSU awards outstanding at beginning of year

1,~~367~~068,~~702~~592

46.8298

1,367,~~294~~702

34.3682

~~452~~1,~~381~~367,294

43.2036

Granted

~~375~~443,~~730~~401

109.2832

~~506~~375,~~436~~730

710.3828

1506,~~065,705~~436

37.1238

Vested

(~~674~~649,~~840~~289)

45.4361

(~~506~~674,~~028~~840)

34.4443

(~~150~~506,~~792~~028)

43.2044

RSU awards outstanding at end of year

1862,~~068,592~~704

69.9822

1,~~367~~068,~~702~~592

46.8298

1,367,~~294~~702

34.3682

(1)	Represents the weighted average grant date fair value, which is based on the quoted closing market price of our common stock on the trading day prior to the date of grant.

Compensation cost recognized for the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023 was $52.89 million and $65.8 million and $36.78 million, respectively, which approximated the fair value of RSUs vested in January ~~2025~~2026, ~~2024~~2025 and ~~2023~~2024, respectively. Future compensation cost based on the fair value of unvested RSUs at December 31, ~~2024~~2025 totaled approximately $32.96 million. The weighted average vesting period related to unvested RSUs at December 31, ~~2023~~2025 was approximately 1.03 years.

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Cash Awards

In ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we granted fixed value cash awards of $6.17 million, $6.01 million and $56.50 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 years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we recognized compensation costs of $5.45 million and $4.5.4 million and $4.35 million, respectively, which reflect the cash payouts made in January ~~2025~~2026, ~~2024~~2025 and ~~2023~~2024, respectively.

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 years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we made contributions to our defined contribution plans totaling $5.5 million, $45.35 million and $34.03 million, respectively.

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Employee Stock Purchase Plan

As of December 31, ~~2024~~2025, 1.0.7 million shares were available for issuance under the ESPP. Eligible employees who participate in the ESPP may purchase shares of our common stock through payroll deductions on an after-tax basis over a four-month period beginning on January 1, May 1, and September 1 of each year during the term of the ESPP, subject to certain restrictions and limitations established by the Compensation Committee and Section 423 of the Internal Revenue Code. The per share price of common stock purchased under the ESPP is equal to 85% of the lesser of its fair market value on (i) the first trading day of the purchase period or (ii) the last trading day of the purchase period. The ESPP currently has a purchase limit of 260 shares per employee per purchase period.

Note 14 — 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. ~~We formed the Shallow Water Abandonment segment in the third quarter 2022 following the Alliance acquisition (Note 3).~~ All material intercompany transactions between the segments have been eliminated. See Note 1 for more information on our business segments.

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
Year ended December 31, 2024
Year ended December 31, 2025
External revenues	$	729,371	$	289,841	$	199,569	$	72,693	$	1,291,474
Intersegment revenues (1)		—		33,512		64		—		33,576
Segment revenues		729,371		323,353		199,633		72,693		1,325,050
Elimination of intersegment revenues										(33,576)
Total consolidated net revenues									$	1,291,474

Less (2):
Direct cost of revenues		(673,111)		(235,975)		(171,030)		(50,997)
Operations support		(15,666)		(5,597)		(10,671)		(549)
Selling, general and administrative expenses		(16,227)		(10,456)		(7,429)		(849)
Segment operating income	$	24,367	$	71,325	$	10,503	$	20,298	$	126,493

Year ended December 31, 2024
External revenues	$	823,472	$	259,639	$	186,740	$	88,709	$	1,358,560
Intersegment revenues (1)		6,390		38,039		239		—		44,668
Segment revenues		829,862		297,678		186,979		88,709		1,403,228
Elimination of intersegment revenues										(44,668)
Total consolidated net revenues									$	1,358,560

Less (2):
Direct cost of revenues		(704,120)		(203,849)		(175,111)		(64,429)
Operations support		(15,130)		(5,542)		(12,645)		(514)
Selling, general and administrative expenses		(16,991)		(10,944)		(8,396)		(2,513)
Other segment items (3)		(416)		—		(150)		87
Segment operating income (loss)	$	93,205	$	77,343	$	(9,323)	$	21,340	$	182,565

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	Well				Shallow Water		Production
	Intervention		Robotics		Abandonment		Facilities		Total
Year ended December 31, 2023
External revenues	$	704,365	$	222,612	$	274,866	$	87,885	$	1,289,728
Intersegment revenues (1)		3,353		35,263		88		—		38,704
Segment revenues		707,718		257,875		274,954		87,885		1,328,432
Elimination of intersegment revenues										(38,704)
Total consolidated net revenues									$	1,289,728

Less (2):
Direct cost of revenues		(646,127)		(192,419)		(186,873)		(63,785)
Operations support		(14,427)		(4,838)		(16,820)		(606)
Selling, general and administrative expenses		(14,766)		(8,468)		(5,088)		(2,662)
Other segment items (3)		—		300		67		—
Segment operating income	$	32,398	$	52,450	$	66,240	$	20,832	$	171,920

Year ended December 31, 2022
External revenues	$	507,696	$	158,279	$	124,810	$	82,315	$	873,100
Intersegment revenues (1)		635		33,642		—		—		34,277
Segment revenues		508,331		191,921		124,810		82,315		907,377
Elimination of intersegment revenues										(34,277)
Total consolidated net revenues									$	873,100

Less (2):
Direct cost of revenues		(536,923)		(150,020)		(92,036)		(51,165)
Operations support		(11,515)		(4,394)		(8,855)		(484)
Selling, general and administrative expenses		(12,949)		(7,526)		(1,735)		(3,465)
Segment operating income (loss)	$	(53,056)	$	29,981	$	22,184	$	27,201	$	26,310

(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 years ended December 31, 2024, ~~2023~~ and ~~2022~~2023, $27.6 million, and $25.0 million ~~and $15.9 million~~, respectively, 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 in 2024 and 2023 relate to gain (loss) on disposition of assets, net.

The table below provides a reconciliation of segment profit to income ~~(loss)~~ before income taxes (in thousands):


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Reconciliation of segment profit —
Segment operating income	$	~~182~~126,~~565~~493	$	~~171~~182,~~920~~565	$	26171,~~310~~920
Change in fair value of contingent consideration		—		(42,246)		(16,054)
Long-lived asset impairment (1)		(18,064)		—		—
Corporate, eliminations and other		(55,130)		(66,164)		(55,111)
Change in fair value of contingent consideration (2)		—		—		(42,246)
Net interest expense		(22,629)		(17,338)		(18,950)
Corporate, eliminations and other		(43,294)		(55,130)		(66,164)
Losses related to convertible senior notes		(20,922)		(37,277)		—
Net interest expense		(22,777)		(22,629)		(17,338)
Other non-operating expense, net		(1,820)		(1,381)		(11,376)
Losses related to convertible senior notes (3)		—		(20,922)		(37,277)
Income (loss) before income taxes	$	82,064	$	7,514	$	(75,181)
Other non-operating income (expense), net		122		(1,820)		(1,381)
Income before income taxes	$	42,480	$	82,064	$	7,514

(1)	Represents the impairment charge on the remaining net book value of the Thunder Hawk field (Note 5)

(2)	Represents the change in fair value of the earnout consideration associated with the Alliance acquisition (Note 3).

(3)	Represent the losses from the repurchases and redemptions of the 2026 Notes during December 2023 and the first quarter 2024 (Note 7).

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


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Capital expenditures (1) —
Well Intervention	$	106,~~955~~062	$	710,~~763~~955	$	177,~~617~~763
Robotics		107,~~402~~900		310,~~957~~402		153,~~603~~957
Shallow Water Abandonment		12,~~403~~010		61,~~890~~403		~~532~~6,890
Production Facilities		—		—		~~(1,424)~~—
Corporate, eliminations and other		~~543~~370		~~978~~543		~~1,176~~978
Total	$	2316,~~303~~342	$	1923,~~588~~303	$	3319,~~504~~588

Depreciation and amortization (2) —
Well Intervention	$	~~123~~140,~~517~~211	$	~~113~~123,~~025~~517	$	~~103~~113,~~952~~025
Robotics		74,~~601~~805		97,~~604~~601		129,~~209~~604
Shallow Water Abandonment		2023,~~463~~045		20,~~150~~463		820,~~172~~150
Production Facilities		2119,~~279~~080		21,~~028~~279		1821,~~520~~028
Corporate and eliminations		~~432~~241		~~309~~432		~~(167)~~309
Total	$	~~173~~187,~~292~~382	$	~~164~~173,~~116~~292	$	~~142~~164,~~686~~116

(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 certification 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.

Revenues by individually significant geographic location are as follows (in thousands):


	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
U.S.	$	~~542~~494,~~860~~544	$	~~644~~542,~~755~~860	$	~~447~~644,~~205~~755
North Sea (1)		~~249~~272,~~968~~254		~~274~~249,~~745~~968		~~206~~274,~~647~~745
Brazil		~~185~~354,~~538~~509		~~177~~185,~~070~~538		81177,~~940~~070
Asia Pacific		~~222~~68,~~119~~415		~~163~~222,~~957~~119		43163,~~648~~957
West Africa		7195,~~960~~519		871,~~423~~960		878,~~488~~423
Other		866,~~115~~233		2086,~~778~~115		620,~~172~~778
Total	$	1,~~358~~291,~~560~~474	$	1,~~289~~358,~~728~~560	$	~~873~~1,~~100~~289,728

(1) Includes revenues generated from the U.K. of $~~181~~194.83 million, $~~236~~181.28 million and $~~167~~236.02 million, respectively, during the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023.

Vessels, systems and other property and equipment work in various offshore basins around the world such as the ~~U.S.~~ Gulf ~~Coast,~~of ~~U.S. East Coast~~America, Brazil, North Sea, ~~Asia~~West ~~Pacific~~Africa and ~~West~~Asia ~~Africa~~Pacific regions. Vessels and equipment may temporarily work in a region other than the country in which those assets are based. For instance, the Q4000 and related IRS system, which are based in the U.S., are temporarily operating offshore West Africa. The following table provides our property and equipment, net of accumulated depreciation, by individually significant country where those assets are based (in thousands):


	December 31,
	~~2024~~2025		~~2023~~2024
U.S.	$	~~659~~581,~~721~~297	$	~~735~~659,~~406~~721
U.K.		~~578~~583,~~505~~464		~~617~~578,~~819~~505
Brazil		~~199~~197,~~627~~733		~~219~~199,~~624~~627
Total	$	1,~~437~~362,~~853~~494	$	1,~~572~~437,~~849~~853

~~The~~We ~~CODM~~have ~~does~~ not ~~regularly~~included ~~review~~a ~~segment~~disclosure ~~asset~~of ~~information~~total assets by segment as management’s focus is on operating performance and cash flow generation. Asand ~~such, we have omitted~~ the ~~disclosure~~CODM ofdoes ~~total~~not ~~assets~~regularly byreview segment asset information.

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Note 15 — Asset Retirement Obligations

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


	~~2024~~2025		~~2023~~2024		~~2022~~2023
AROs at January 1,	$	6162,~~356~~947	$	5161,~~956~~356	$	2951,~~658~~956
Liability incurred during the period		—		—		23,601
Revisions in estimates		—		(4,010)		3,257
Revisions in estimates		(4,010)		3,257		(3,285)
Accretion expense		5,823		5,601		6,143
Accretion expense		5,601		6,143		1,982
AROs at December 31,	$	68,770	$	62,947	$	61,356
AROs at December 31,	$	62,947	$	61,356	$	51,956

Note 16 — 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~~Sea Helix 1 and Siem Helix 2 vessels, whose charter terms expire in December 2030 and December 2031, respectively. Our Robotics segment has long-term vessel charters for the Grand Canyon II, the Grand Canyon III, the Shelia Bordelon, and the North Sea Enabler, ~~and~~whose ~~the~~charter ~~Glomar~~terms ~~Wave.~~expire ~~Our~~in ~~time~~December 2030, ~~charter~~May 2028, ~~agreement~~June 2026, ~~for~~and ~~the~~March 2026, ~~Grand~~respectively. ~~Canyon~~In IIFebruary 2025, ~~expires~~our inRobotics ~~December 2030.~~segment ~~Our~~took ~~time~~delivery ~~charter~~of ~~agreement~~the ~~for~~Trym ~~the~~with ~~Grand~~a ~~Canyon~~three-year ~~III~~charter that expires in ~~May~~February 2028. ~~Our~~On ~~time~~April 1, ~~charter~~2025, ~~agreement~~we ~~for~~extended the ~~Shelia~~Trym ~~Bordelon~~charter inby ~~the~~one Uyear.S. ~~Gulf~~In ~~Coast~~December 2025, ~~expires~~we inexecuted ~~June 2026.~~a ~~Our~~new ~~time~~two-year charter agreement for the North Sea Enabler ~~expires~~starting in ~~December~~July ~~2025~~2026. WeIn ~~have~~January 2026, aour ~~three-year~~Robotics ~~charter~~segment ~~agreement~~took ~~for~~delivery of the ~~Glomar~~Patriot ~~Wave~~with ina ~~the~~four-year ~~North~~charter ~~Sea~~ that expires in ~~2025~~January 2030.

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 and other matters 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, and employee-related disputes ~~and subsequently identified legacy issues related to Alliance~~. We recognize losses for ~~lawsuits~~contingencies 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 accrued for or covered by insurance, will have a material adverse impact on our consolidated financial statements.

Note 17 — Statement of Cash Flow Information

The following table provides supplemental cash flow information (in thousands):



	Year Ended December 31,
	~~2024~~2025		~~2023~~2024		~~2022~~2023
Interest paid	$	2530,~~447~~844	$	2025,~~984~~447	$	1820,~~267~~984
Income taxes paid (1)		1430,~~124~~753		714,~~394~~124		97,~~516~~394

(1) Exclusive of any income tax refunds. ~~During the years ended December 31, 2022, we received refunds related to the U.S. Coronavirus Aid, Relief, and Economic Security Act of $1.1 million.~~

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Our capital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, ~~2024~~2025 and ~~2023~~2024, these non-cash capital additions totaled $0.1.0 million and $10.1 million, respectively.

Non-cash financing activities during the year ended December 31, 2024 included the non-cash settlement of the entire $14.0 million financing liabilities with certain customer receivables. We incurred these financing liabilities as a result of the purchase of certain P&A equipment in 2023 ~~(Note 4)~~. Non-cash investing and financing activities for the year ended December 31, 2023 included financing liabilities with an estimated fair value of $11.6 million at the time of the P&A equipment purchase in 2023. Non-cash financing activities for the year ended December 31, 2023 included the issuance of 1.5 million shares of our common stock for the repurchase of a portion of our 2026 Notes. Non-cash investing activities for the year ended December 31, 2022 included $26.7 million in estimated fair value of contingent earnout consideration as of July 1, 2022, the date of the Alliance acquisition (Note 3).

Note 18 — Allowance Accounts

The following table sets forth the activity in our valuation accounts for each of the three years in the period ended December 31, ~~2024~~2025 (in thousands):


	Allowance for		Deferred Tax Asset
	Credit Losses		Valuation Allowance
Balance at December 31, 2021	$	1,477	$	14,047
Balance at December 31, 2022	$	2,277	$	22,157
Additions (1)		800		—
Additions (1) (2)		1,149		51,354
Adjustments (2)		—		8,110
Write-offs		(19)		—
Balance at December 31, 2022		2,277		22,157
Adjustments (3)		—		7,604
Additions (1) (3)		1,149		51,354
Write-offs (4)		(19)		—
Adjustments (2)		—		7,604
Balance at December 31, 2023		3,407		81,115
Additions (1)		275		—
Adjustments (5)		—		(5,734)
Adjustments (4)		—		(5,734)
Balance at December 31, 2024	$	3,682	$	75,381
Reductions (1)		(136)		—
Adjustments (3)		(17)		9,570
Balance at December 31, 2025	$	3,529	$	84,951

(1) The additions/reductions in allowance for credit losses relate to reserves (releases) for expected credit losses during the respective years.

(2) The ~~increase~~addition in valuation allowance relates to ~~current~~the ~~year~~adjustment ~~activity,~~for ~~including~~a ~~adjustments~~change toin ~~prior~~assessment ~~year~~on ~~returns, and~~ the ~~related~~realizability ~~change~~of inour ~~unrealized~~Luxembourg net ~~deferred~~operating ~~tax~~losses ~~assets~~from remote to less likely than not.

(3) The ~~addition~~increase in valuation allowance relates to ~~the~~current ~~adjustment~~year ~~for~~activity, aincluding ~~change~~adjustments into ~~assessment~~prior onyear ~~the~~returns, ~~realizability~~and ofan ~~our~~internal ~~Luxembourg net operating losses from remote to less likely than not~~restructuring.

(4) The ~~write-offs~~net ofdecrease ~~allowance~~in ~~for~~valuation ~~credit~~allowance ~~losses~~included ~~reflect~~a ~~certain~~$3.2 ~~receivables~~million decrease related to ~~our~~a ~~Robotics~~valuation ~~segment~~allowance ~~that~~release ~~were~~in ~~previously~~Brazil, ~~reserved~~a $5.2 million increase in assessment on the realizability of U.S. group foreign tax credit carryforward, and ~~subsequently~~a ~~deemed~~$7.7 million decrease in valuation allowance, which was predominantly driven by current year activity, including adjustments to beprior ~~uncollectible~~year returns.

(5) The net decrease in valuation allowance included a $3.2 million decrease related to a valuation allowance release in Brazil, a $5.2 million increase in assessment on the realizability of U.S. group foreign tax credit carryforward, and a $7.7 million decrease in valuation allowance, which was predominantly driven by current year activity, including adjustments to prior year returns.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for credit losses. See Note 8 for a detailed discussion of the valuation allowance related to our deferred tax assets.

Note 19 — 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.

We used Level 3 input to estimate the fair value of the Thunder Hawk field during our asset impairment assessment in 2025. See Note 5 for additional disclosures.

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


	December 31, ~~2024~~2025				December 31, ~~2023~~2024
	Principal		Fair		Principal		Fair
	Amount (1)		Value (2)		Amount (1)		Value (2)
2026 Notes (fully redeemed March 2024)	$	—	$	—	$	40,199	$	64,117
MARAD Debt (matures February 2027)	$	14,645	$	14,611	$	23,831	$	23,505
MARAD Debt (matures February 2027)		23,831		23,505		32,580		32,348
2029 Notes (mature March 2029)		300,000		317,250		300,000		319,500
2029 Notes (mature March 2029)		300,000		319,500		300,000		315,987
Total debt	$	314,645	$	331,861	$	323,831	$	343,005
Total debt	$	323,831	$	343,005	$	372,779	$	412,452

(1)	Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 7 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.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

(a)Disclosure Controls and Procedures. We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. Based on this evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, ~~2024~~2025 to provide reasonable assurance that the information required to be disclosed in our reports 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, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

(b)Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. This process includes policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Our management assessed the effectiveness of our internal control over financial reporting at December 31, ~~2024~~2025. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on those criteria, management concluded that, as of December 31, ~~2024~~2025, our internal control over financial reporting was effective.

The effectiveness of our internal control over financial reporting as of December 31, ~~2024~~2025 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in its report which appears in Item 8. Financial Statements and Supplemental Data of this Annual Report on Form 10-K.

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(c)Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal ~~2024~~2025 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

(b) During the three-month period ended December 31, ~~2024~~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 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Except as set forth below, the information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Exchange Act in connection with our ~~2025~~2026 Annual Meeting of Shareholders to be held on May 14 13, ~~2025~~2026. See also “Executive Officers of the Company” appearing in Part I of this Annual Report.

Code of Ethics

We have a Code of Business Conduct and Ethics for all of our directors, officers and employees as well as a Code of Ethics for Chief Executive Officer and Senior Financial Officers specific to those officers. Copies of these documents are available under Corporate Governance of the Investor Relations section of our website www.helixesg.com. Interested parties may also request a free copy of these documents from:

Helix Energy Solutions Group, Inc.

ATTN: Corporate Secretary

3505 W. Sam Houston Parkway N., Suite 400

Houston, Texas 77043

Insider Trading Compliance Program

We have adopted the Helix Energy Solutions Group, Inc. Insider Trading Compliance Program and the Insider Trading Policy (Guidelines with Respect to Certain Transactions in Company Securities), included as an exhibit to the Insider Trading Compliance Program, to govern transactions in the Company’s securities by employees, officers, directors and other related individuals of the Company and its subsidiaries. The Insider Trading Policy prohibits transactions involving a purchase or sale of Company securities while an individual is in possession of material non-public information and provides for trading windows during which the Company’s securities can be bought, sold or otherwise transferred. The Insider Trading Compliance Program and the Insider Trading Policy are reasonably designed to promote compliance with insider trading laws, rules and regulations and listing standards of the NYSE. The foregoing summary of the Insider Trading Compliance Program and the Insider Trading Policy does not purport to be complete and is qualified in its entirety by reference to the full text of the Insider Compliance Trading Program and the Insider Trading Policy attached to this Annual Report as Exhibit 19.1 and incorporated herein by reference.

Item 11. Executive Compensation

The information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Exchange Act in connection with our ~~2025~~2026 Annual Meeting of Shareholders to be held on May 14 13, ~~2025~~2026.

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Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Item 13. Certain Relationships and Related Transactions, and Director Independence

Item 14. Principal Accounting Fees and Services

PART IV

Item 15. Exhibit and Financial Statement Schedules

(1)

Financial Statements

The following financial statements included on pages 45 through 80 of this Annual Report are for the fiscal year ended December 31, ~~2024~~2025.

●

Report of Independent Registered Public Accounting Firm

●

Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

● Consolidated Balance Sheets as of December 31, ~~2024~~2025 and ~~2023~~2024

● Consolidated Statements of Operations for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023

● Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023

● Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023

● Consolidated Statements of Cash Flows for the Years Ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023

●

Notes to Consolidated Financial Statements

All financial statement schedules are omitted because the information is not required or because the information required is in the financial statements or notes thereto.

(2)

Exhibits

The documents set forth below are filed or furnished herewith or incorporated by reference to the location indicated. Pursuant to Item 601(b)(4)(iii), the Registrant agrees to forward to the commission, upon request, a copy of any instrument with respect to long-term debt not exceeding 10% of the total assets of the Registrant and its consolidated subsidiaries.


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

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Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.2	Second Amended and Restated By-Laws of Helix, as amended.	Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
4.1	Description of Securities Registered Pursuant to Section 12 of the Exchange Act of 1934.	Exhibit 4.1 to the 2024 Form 10-K filed on February 27, 2025 (001-32936)
4.1	Description of Securities Registered Pursuant to Section 12 of the Exchange Act of 1934.	Filed herewith
4.2	Form of Common Stock certificate.	Exhibit 4.7 to the Form 8-A filed on June 30, 2006 (001-32936)
4.3	Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of August 16, 2000.	Exhibit 4.4 to the 2001 Form 10-K filed on March 28, 2002 (000-22739)
4.4	Amendment No. 1 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of January 25, 2002.	Exhibit 4.9 to the 2002 Form 10-K/A filed on April 8, 2003 (000-22739)
4.5	Amendment No. 2 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of November 15, 2002.	Exhibit 4.4 to the Form S-3 filed on February 26, 2003 (333-103451)
4.6	Amendment No. 3 Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of July 31, 2003.	Exhibit 4.12 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.7	Amendment No. 4 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of December 15, 2004.	Exhibit 4.13 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.8	Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.	Exhibit 4.1 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.9	Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.	Exhibit 4.2 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.10	Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.	Exhibit 4.3 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.11	Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.	Exhibit 4.4 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.12	Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.	Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.13	Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027.	Exhibit A to Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.14	Form of Third Amended and Restated Promissory Note to United States of America.	Exhibit 4.7 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.15	Senior Debt Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.1 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
4.16	First Supplemental Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.2 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)

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Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.16	First Supplemental Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.2 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
4.17	Second Supplemental Indenture, dated as of March 20, 2018, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.2 to the Current Report on Form 8-K filed on March 21, 2018 (001-32936)
4.18	Indenture, dated as of August 14, 2020, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.1 to the Current Report on Form 8-K filed on August 14, 2020 (001-32936)
4.19	First Supplemental Indenture, dated as of August 14, 2020, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.2 to the Current Report on Form 8-K filed on August 14, 2020 (001-32936)
4.20	Loan, Guaranty and Security Agreement, dated as of September 30, 2021, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as Borrowers, the Lenders from time to time party thereto, and Bank of America, N.A. as Agent.	Exhibit 4.1 to the Current Report on Form 8-K filed on October 1, 2021 (001-32936)
4.21	Amendment No. 1, dated as of July 1, 2022, to Loan, Security and Guaranty Agreement, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders.	Exhibit 4.1 to the Current Report on Form 8-K filed on July 1, 2022 (001-32936)
4.22	Letter Agreement, dated as of January 25, 2023, to Loan, Security and Guaranty Agreement, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders.	Exhibit 4.32 to the Annual Report on Form 10-K filed on February 24, 2023 (001-32936)
4.23	Amendment No. 2, dated as of June 23, 2023, to Loan, Security and Guaranty Agreement dated as of September 30, 2021, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Alliance Offshore, L.L.C., Triton Diving Services, LLC, Alliance Energy Services, LLC, Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders, as previously amended.	Exhibit 4.1 to the Current Report on Form 8-K filed on June 23, 2023 (001-32936)

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

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.24	Amendment No. 3, dated as of November 15, 2023, to Loan, Security and Guaranty Agreement dated as of September 30, 2021, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Alliance Offshore, L.L.C., Triton Diving Services, LLC, Alliance Energy Services, LLC, Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders, as previously amended.	Exhibit 4.1 to the Current Report on Form 8-K filed on November 15, 2023 (001-32936)
4.25	Amendment No. 4, dated as of August 2, 2024 to Loan, Security and Guaranty Agreement dated as of September 30, 2021, among Helix Energy Solutions Group, Inc., Helix Well Ops Inc., Helix Robotics Solutions, Inc., Deepwater Abandonment Alternatives, Inc., Alliance Offshore, L.L.C., Triton Diving Services, LLC, Alliance Energy Services, LLC, Helix Well Ops (U.K.) Limited and Helix Robotics Solutions Limited as borrowers, the guarantors party thereto, the lenders party thereto, and Bank of America, N.A., as agent and security trustee for the lenders, as previously amended.	Exhibit 4.1 to the Current Report on Form 8-K filed on August 2, 2024 (001-32936)
4.26	Indenture, dated as of December 1, 2023, by and among Helix Energy Solutions Group, Inc., the guarantors listed therein and The Bank of New York Mellon Trust Company, N.A., as trustee.	Exhibit 4.1 to the Current Report on Form 8-K filed on December 1, 2023 (001-32936)
10.1 *	2009 Long-Term Incentive Cash Plan of Helix Energy Solutions Group, Inc.	Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2009 (001-32936)
10.2 *	Form of Award Letter related to the 2009 Long-Term Incentive Cash Plan.	Exhibit 10.2 to the Current Report on Form 8-K filed on January 6, 2009 (001-32936)
10.3 *	2005 Long Term Incentive Plan of Helix Energy Solutions Group, Inc., as Amended and Restated Effective May 15, 2024.	Annex A to the Definitive Proxy Statement filed on April 3, 2024 (001-32936)
10.4 *	Form of Restricted Stock Award Agreement.	Exhibit 10.3 to the Current Report on Form 8-K filed on December 15, 2011 (001-32936)
10.5 *	Form of Performance Share Unit Award Agreement.	Exhibit 10.1 to the Current Report on Form 8-K/A filed on December 14, 2020 (001-32936)
10.6 *	Form of Restricted Stock Unit Award Agreement.	Exhibit 10.1 to the Current Report on Form 8-K filed on December 16, 2020 (001-32936)
10.7 *	Employee Stock Purchase Plan of Helix Energy Solutions Group, Inc., as Amended and Restated Effective May 15, 2019.	Annex B to the Definitive Proxy Statement filed on April 2, 2019 (001-32936)
10.8 *	Employment Agreement between Owen Kratz and the Company dated February 28, 1999.	Exhibit 10.5 to the 1998 Form 10-K filed on March 31, 1999 (000-22739)
10.9 *	Employment Agreement between Owen Kratz and the Company dated November 17, 2008.	Exhibit 10.1 to the Current Report on Form 8-K filed on November 19, 2008 (001-32936)

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Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.10 *	First Amendment to Employment Agreement between Helix Energy Solutions Group, Inc. and Owen Kratz effective May 22, 2020.	Exhibit 10.1 to the Current Report on Form 8-K filed on May 22, 2020 (001-32936)
10.11 *	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Scotty Sparks dated May 11, 2015.	Exhibit 10.1 to the Current Report on Form 8-K/A filed on May 12, 2015 (001-32936)
10.12 *	Deferred Compensation Agreement by and between Helix Energy Solutions Group, Inc. and Scotty Sparks dated January 1, 2012.	Exhibit 10.2 to the Current Report on Form 8-K/A filed on May 12, 2015 (001-32936)
10.13 *	First Amendment to Employment Agreement between Helix Energy Solutions Group, Inc. and Scotty Sparks effective May 22, 2020.	Exhibit 10.2 to the Current Report on Form 8-K filed on May 22, 2020 (001-32936)
10.14 *	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Erik Staffeldt dated June 5, 2017.	Exhibit 10.1 to the Current Report on Form 8-K filed on June 6, 2017 (001-32936)
10.15 *	First Amendment to Employment Agreement between Helix Energy Solutions Group, Inc. and Erik Staffeldt effective May 22, 2020.	Exhibit 10.3 to the Current Report on Form 8-K filed on May 22, 2020 (001-32936)
10.16 *	Employment Agreement by and between Helix Energy Solutions Group, Inc. and Ken Neikirk dated May 1, 2019.	Exhibit 10.2 to the Quarterly Report on Form 10-Q filed on July 26, 2019 (001-32936)
10.17 *	First Amendment to Employment Agreement between Helix Energy Solutions Group, Inc. and Ken Neikirk effective May 22, 2020.	Exhibit 10.4 to the Current Report on Form 8-K filed on May 22, 2020 (001-32936)
10.18	Underwriting Agreement dated as of January 4, 2017, between Helix Energy Solutions Group, Inc. and Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein.	Exhibit 1.1 to the Current Report on Form 8-K filed on January 6, 2017 (001-32936)
10.19	Underwriting Agreement dated as of March 13, 2018, by and among Helix Energy Solutions Group, Inc., Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner & Smith Incorporated.	Exhibit 1.1 to the Current Report on Form 8-K filed on March 19, 2018 (001-32936)
10.20	Underwriting Agreement, dated as of August 11, 2020, by and among Helix Energy Solutions Group, Inc., Wells Fargo Securities, LLC and Evercore Group L.L.C.	Exhibit 1.1 to the Current Report on Form 8-K filed on August 14, 2020 (001-32936)
10.21	Strategic Alliance Agreement dated January 5, 2015 among Helix Energy Solutions Group, Inc., OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V., and Schlumberger Oilfield Holdings Ltd.	Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2015 (001-32936)
10.22	~~Equity~~Amendment ~~Purchase~~and Assignment Agreement, ~~dated~~to asStrategic ~~of May 16, 2022, by and among Helix~~ Alliance ~~Decom, LLC, Stephen J~~Agreement. ~~Williams and Helix Energy Solutions Group, Inc. (solely for purposes of Sections 1.05(d) and 6.14).~~	Exhibit 210.1 to the Current Report on Form 8-K filed on ~~July~~February 121, ~~2022~~2025 (001-32936)
10.23	Equity Purchase Agreement, dated ~~November~~as of May 16, ~~2023~~2022, by and among Helix ~~Energy~~Alliance ~~Solutions Group~~Decom, ~~Inc.~~LLC, ~~guarantors~~Stephen ~~party~~J. ~~thereto~~Williams and ~~Wells~~Helix ~~Fargo~~Energy ~~Securities,~~Solutions ~~LLC~~Group, asInc. ~~representative~~(solely offor ~~the~~purposes ~~several~~of ~~initial~~Sections ~~purchasers~~1.05(d) ~~named~~and ~~therein~~6.14).	Exhibit 102.1 to the Current Report on Form 8-K filed on ~~November~~July 171, ~~2023~~2022 (001-32936)
10.24	Purchase Agreement, dated November 16, 2023, among Helix Energy Solutions Group, Inc., guarantors party thereto and Wells Fargo Securities, LLC, as representative of the several initial purchasers named therein.	Exhibit 10.1 to the Current Report on Form 8-K filed on November 17, 2023 (001-32936)

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Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.24	Form of Purchase Agreement with certain holders of 6.75% Convertible Senior Notes due 2026.	Exhibit 10.1 to the Current Report on Form 8-K filed on December 6, 2023 (001-32936)
10.25	Form of Purchase Agreement with certain holders of 6.75% Convertible Senior Notes due 2026.	Exhibit 10.1 to the Current Report on Form 8-K filed on December 6, 2023 (001-32936)
10.25	Form of Exchange Agreement with certain holders of 6.75% Convertible Senior Notes due 2026.	Exhibit 10.2 to the Current Report on Form 8-K filed on December 6, 2023 (001-32936)
10.26	Form of Exchange Agreement with certain holders of 6.75% Convertible Senior Notes due 2026.	Exhibit 10.2 to the Current Report on Form 8-K filed on December 6, 2023 (001-32936)
14.1	Code of Ethics for Chief Executive Officer and Senior Financial Officers.	Exhibit 14.1 to the 2021 Form 10-K filed on February 24, 2022 (001-32936)
19.1	Helix Energy Solutions Group, Inc. Insider Trading Compliance Program.	~~Filed~~Exhibit ~~herewith~~19.1 to the 2024 Form 10-K filed on February 27, 2025 (001-32936)
21.1	List of Helix’s Subsidiaries.	Filed herewith
23.1	Consent of KPMG LLP.	Filed herewith
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
97.1	Mandatory Recoupment Policy.	Exhibit 99.1 to the Current Report on Form 8-K filed on September 20, 2023 (001-32936)
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

*Management contracts or compensatory plans or arrangements

Item 16. Form 10-K Summary

None.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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.

	By:	/s/ ERIK STAFFELDT
		Erik Staffeldt
		Executive Vice President and
		Chief Financial Officer

February 26, ~~2025~~2026

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date

/s/ OWEN KRATZ	President, Chief Executive Officer and Director	February 26, ~~2025~~2026
Owen Kratz	(principal executive officer)

/s/ ERIK STAFFELDT	Executive Vice President and Chief Financial Officer	February 26, ~~2025~~2026
Erik Staffeldt	(principal financial officer)

/s/ BRENT ARRIAGA	~~Chief~~Vice ~~Accounting~~President ~~Officer~~– Finance and ~~Corporate~~Accounting ~~Controller~~and Chief Accounting Officer	February 26, ~~2025~~2026
Brent Arriaga	(principal accounting officer)

/s/ DIANA GLASSMAN	Director	February 26, ~~2025~~2026
Diana Glassman

/s/ PAULA HARRIS	Director	February 26, ~~2025~~2026
Paula Harris

/s/ T. MITCH LITTLE	Director	February 26, ~~2025~~2026
T. Mitch Little

/s/ JOHN V. LOVOI	Director	February 26, ~~2025~~2026
John V. Lovoi

/s/ AMY H. NELSON	Director	February 26, ~~2025~~2026
Amy H. Nelson

/s/ WILLIAM L. TRANSIER	Director	February 26, ~~2025~~2026
William L. Transier

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