10-K

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, 2022

or

☐ 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, 2022 was approximately $442.6 million based on the closing price of the registrant’s common stock as quoted on the New York Stock Exchange on June 30, 2022.

The number of shares of the registrant’s common stock outstanding as of February 17, 2023 was 152,153,912.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 17, 2023 are incorporated by reference into Part III hereof.

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

		Page
	PART I
Item 1.	Business	5
Item 1A.	Risk Factors	18
Item 1B.	Unresolved Staff Comments	30
Item 2.	Properties	30
Item 3.	Legal Proceedings	32
Item 4.	Mine Safety Disclosures	32
Unnumbered Item	Information about our Executive Officers	32
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	33
Item 6.	[Reserved]	35
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	35
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	46
Item 8.	Financial Statements and Supplementary Data	47
	Report of Independent Registered Public Accounting Firm (KPMG LLP, Houston, Texas, Auditor Firm ID 185)	47
	Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting	49
	Consolidated Balance Sheets as of December 31, 2022 and 2021	50
	Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020	51
	Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2022, 2021 and 2020	52
	Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2022, 2021 and 2020	53
	Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020	54
	Notes to Consolidated Financial Statements	55
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	84
Item 9A.	Controls and Procedures	84
Item 9B.	Other Information	85
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	85
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	86
Item 11.	Executive Compensation	86
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	86
Item 13.	Certain Relationships and Related Transactions, and Director Independence	86
Item 14.	Principal Accounting Fees and Services	86
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	87
Item 16.	Form 10-K Summary	92
	Signatures	93

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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, working capital, debt and liquidity, future operations expenditures or other financial items;

● statements regarding our backlog and commercial contracts and rates thereunder;

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

● statements regarding the spot market, the continuation of our current backlog, visibility and future utilization, our spending and cost management efforts and our ability to manage changes, and the COVID-19 pandemic and oil price volatility and their respective effects and results on the foregoing as well as our protocols and plans;

● statements regarding energy transition and energy security;

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

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

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

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

● statements regarding our trade receivables and their collectability;

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

● statements regarding our Environmental, Social and Governance (“ESG”) initiatives and the successes thereon or regarding our environmental efforts, including greenhouse gas emissions (“GHG Emissions”) targets;

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

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

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

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

● statements regarding our share repurchase authorization or program;

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

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

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

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● the results and effects of the COVID-19 pandemic and actions by governments, customers, suppliers and partners with respect thereto;

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

● the results of corporate initiatives such as alliances, partnerships, joint ventures, mergers, acquisitions, divestitures and restructurings, or the determination not to pursue or effect such initiatives;

● the results of acquired properties;

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

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

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

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

● the performance of contracts by suppliers, customers and partners;

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

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

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

● the effects of competition;

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

● the effectiveness of our ESG initiatives and disclosures;

● the impact of current and future laws and governmental regulations and how they will be interpreted or enforced, including related to fossil fuel production 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 impact of foreign currency exchange controls, potential illiquidity of those currencies and exchange rate fluctuations;

● the effectiveness of our future hedging activities;

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

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

● the factors generally described in Item 1A. Risk Factors 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 18 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 35 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 full-field decommissioning operations. Our services are centered on a three-legged business model well positioned to facilitate global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. For additional information regarding business operations, see sections titled “Our Operations” included within Item 1. Business of this Annual Report.

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 June 2022 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 16 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 located elsewhere in this Annual Report.

OUR OPERATIONS

We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. We have expanded our service capabilities to the Gulf of Mexico shelf with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022, which we have re-branded as Helix Alliance. Our services are segregated into four reportable business segments: Well Intervention, Robotics, Production Facilities and our new reporting segment, Shallow Water Abandonment, which was formed in the third quarter 2022 comprising the Helix Alliance business.

Our Well Intervention segment provides services enabling our customers to safely access offshore wells for the purpose of performing well production enhancement or decommissioning operations, thereby avoiding drilling new wells by extending the useful lives of existing wells and preserving the environment by safely decommissioning aged wells and restoring the seabed. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and the Siem Helix 1 and Siem Helix 2 chartered vessels. Our well intervention equipment includes intervention systems such as intervention riser systems (“IRSs”), subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module (“ROAM”), some of which we provide on a stand-alone basis.

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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 affordable and reliable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our Robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, the IROV boulder grab and robotics support vessels under term charters as well as spot vessels as needed.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of Mexico shelf, through offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat and plug and abandonment (“P&A”) and coiled tubing systems.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), the Helix Fast Response System (the “HFRS”) and our ownership of oil and gas properties. All of our current Production Facilities activities are located in the Gulf of Mexico.

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

● 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. Well intervention; intervention engineering; production enhancement; coiled tubing operations; IRM of production structures, trees, jumpers, risers, pipelines and subsea equipment; and related support services.

● Decommissioning. Reclamation and remediation services; well P&A services; pipeline, cable and umbilical abandonment services; and site inspections.

● Production Facilities. Provision of 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 Mexico.

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

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

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

● Trenching. Cable burial via jetting and/or cutting by self-propelled trenching ROVs and plough trenching.

● Subsea Support. General subsea support of engineering, procurement, construction and installation contractors with 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. Historically, drilling rigs have been used in subsea well intervention to enhance production and decommission wells. Our purpose-built well intervention vessels serve as work platforms and derive competitive advantages from their lower operating costs, with an ability to mobilize quickly and to maximize operational time by 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. We believe we offer efficiency gains from our specialized intervention assets.

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Our well intervention business currently includes seven purpose-built well intervention vessels and 12 intervention systems (including two recently acquired deepwater IRSs) providing services primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa, with expansion into Asia Pacific.

In the Gulf of Mexico, the Q4000, a riser-based semi-submersible well intervention vessel, has been serving customers in the spot market since 2002. In 2010, the Q4000 served as a key emergency response vessel in the Macondo well control and containment efforts. The Q5000 riser-based semi-submersible well intervention vessel commenced operations in the Gulf of Mexico in 2015.

In Brazil, we provide well intervention services with the Siem Helix 1 and Siem Helix 2 vessels under long-term charter from Siem Offshore AS (“Siem”). The Siem Helix 1, which commenced operations in April 2017, completed its four-year contract with Petróleo Brasileiro S.A. (“Petrobras”) in 2021 and worked on short-term accommodations and ROV projects prior to commencing a long-term P&A project for Trident Energy do Brasil Ltda. (“Trident”) starting December 2022. The Siem Helix 2 commenced operations for Petrobras in December 2017 and is under contract through at least December 2024.

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

The Q7000, a semi-submersible well intervention vessel built to U.K. North Sea standards and capable of working globally, commenced operations in January 2020 performing various integrated well intervention operations offshore Nigeria. The Nigeria campaign completed in 2022 and the vessel is currently mobilizing for decommissioning campaigns in Asia Pacific and 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, we and SLB jointly developed a 15K IRS and the ROAM.

Robotics

We have been actively engaged in robotics for over three decades. We operate robotics assets to complement offshore construction, maintenance and well intervention services for the oil and gas market and to support offshore renewable energy projects for the renewable energy market. We often integrate our services with chartered vessels. Our robotics business operates globally, with primary operations in the North Sea, Gulf of Mexico, U.S. East Coast, 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 robotics assets and experience, coupled with our chartered vessel fleet and schedule flexibility, allow us to meet the technological challenges of our customers’ subsea activities worldwide. As of December 31, 2022, our robotics assets included 41 work class ROVs, seven trenchers (including three recently acquired trenchers) and the IROV boulder grab. We charter vessels on a long-term or a spot basis to support deployment of our robotics assets.

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, especially in the North Sea where offshore wind farming is currently concentrated. We provide cable burial services related to subsea power cable installations as well as seabed clearing and site preparation services around the world using our chartered vessels, trenchers and ROVs. In 2022, revenues derived from offshore renewable energy contracts accounted for 43% 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.

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Shallow Water Abandonment

In July 2022, we completed the acquisition of Alliance, a vertically integrated company specializing in comprehensive offshore oilfield decommissioning services predominantly in the Gulf of Mexico shelf. Helix Alliance’s decommissioning offerings include well plugging and abandonment, subsea infrastructure flushing and abandonments (or removals), platform decommissioning and structure removals, and subsea site clearance, and engineering, permitting and project management. In addition to its end-of-life decommissioning services, Helix Alliance offers services to support the full life cycle of offshore upstream and midstream industries, including oil and gas production through well intervention, coiled tubing and pumping; installations and construction; and IRM.

Production Facilities

We 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, 2024.

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 the HP I, the Q4000 and the Q5000 with certain well control equipment that can be deployed to respond to a well control incident. We are under agreement through March 31, 2024 with various operators to provide access to the HFRS for well control purposes.

Our Production Facilities segment includes mature deepwater offshore wells, including two remaining wells acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019, for which Marathon Oil agreed to pay us certain amounts as we complete the related P&A work, and three wells and related subsea infrastructure acquired from MP Gulf of Mexico, LLC (“MP GOM”), a joint venture controlled by Murphy Exploration & Production Company – USA, in August 2022.

GEOGRAPHIC AREAS

We primarily operate in the Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations and our Gulf of Mexico shelf operations related to Helix Alliance are usually subject to seasonal changes in demand, which generally peaks in the summer months and declines in the winter months. See Note 14 for revenues as well as property and equipment by geographic location.

CUSTOMERS

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 level of services required by any particular customer depends, in part, on the size of that customer’s budget in a particular year. Consequently, a customer that accounts for a significant portion of revenues in one fiscal year may represent an immaterial portion of revenues in subsequent fiscal years. The percentages of consolidated revenues from major customers (those representing 10% or more of our consolidated revenues) are as follows: 2022 — Shell (15%); 2021 — Petrobras (23%) and Shell (17%); and 2020 — Petrobras (28%) and BP (17%). We provided services to over 80 customers in 2022.

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COMPETITORS

The oilfield services and renewable energy 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 include AKOFS Offshore, Baker Hughes, C-Innovation, Expro, FTAI, Oceaneering, TechnipFMC, Trendsetter and international drilling contractors. Our principal competitors in the robotics business include Atlantic Marine, Briggs Marine, C-Innovation, DeepOcean, DOF Subsea, Fugro, James Fisher, Oceaneering, ROVOP 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.

ENVIRONMENTAL, SOCIAL AND GOVERNANCE

Safety, Sustainability and Value Creation – our core goals – support our vision as a preeminent offshore energy transition company. ESG 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”). Specifically, the Corporate Governance and Nominating Committee of our Board (the “Governance Committee”) oversees, assesses and reviews the disclosure and reporting of any ESG matters, including with respect to climate change, regarding the Company’s business and industry, and that committee’s charter formally incorporates oversight of ESG matters as a stated responsibility. Sustainability is reviewed on an ongoing basis in conjunction with environmental, health and safety, and social matters at each Governance Committee meeting.

While the Board oversees strategic ESG initiatives, our Climate Change Action Committee, comprised of key leaders from QHSE, 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 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 reduce our environmental impact, improve our safety record and increase transparency for our stakeholders. In 2022, we disclosed our GHG Emissions metrics for 2019, 2020 and 2021 and our reduction targets for GHG Emissions by 2024. 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 with respect to our GHG Emissions. In tandem with such disclosures and targets, we continued to support renewable energy through our three-legged business model well positioned to facilitate global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. 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 helps clients avoid drilling new wells. These efforts are published in greater detail in our most recent Corporate Sustainability Report, a copy of which is available on our website at www.helixesg.com/about-helix/our-company/corporate-sustainability.

HUMAN CAPITAL RESOURCES

Labor Practices

As of December 31, 2022, we had 2,280 employees. Of our total employees, we had 447 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/corporate-governance.

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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 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.

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 and employees to work in compliance with our goals to avoid injuries to people, environmental disturbances and damage to assets. 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).

Health and Safety during COVID-19

The nature of offshore operations requires our offshore crew members as well as our customers and vendors to periodically travel to and from vessels. In response to the COVID-19 pandemic, both Helix and Alliance implemented numerous health and safety protocols. In light of updated guidance pertaining to the COVID-19 pandemic, rates of community transmission, and widespread vaccination, we continue to evolve our protocols to align with what we understand to be best practices designed to protect our personnel, those partners with whom we work and their collective families.

Employee Engagement, Diversity and Inclusion

Employee Tenure and Turnover

We track tenure and voluntary employee turnover. We then use this data to develop our human capital management strategy. As of December 31, 2022, 57% of our workforce had been with Helix for five years or longer, and our global voluntary turnover rate was 12.5% (excluding employees added through our Alliance acquisition, which closed on July 1, 2022).

Training, Engagement and Improvement

Proper and recurring training is necessary so our staff can be as prepared as possible to perform our operations safely. Our staff receives up to date and relevant training required for their jobs, and Helix leadership actively engages staff so that behaviors reflect the training and critical safety approach we all desire. The initial vessel orientation for new hires is the first of many steps in shaping those behaviors. Each vessel and shore-based employee is assigned a Qualifications and Training Matrix that specifies the qualifications and training that the employee is required to have for the applicable position. Training is tracked annually and evaluated to confirm the quality of training. 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 behavior and feedback of our employees.

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Diversity and Inclusion

We are committed to diversity and inclusion throughout our workforce. In 2022, our worldwide workforce represented 34 different nationalities. Our hiring managers and human resources departments in all regions partner to find 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 or any other basis that would be in violation of any applicable federal, state, local or international law. Employing people with different backgrounds, experiences and perspectives makes Helix a stronger business. To reinforce this commitment in the U.S., our Houston office implemented a blind hiring initiative through which Human Resources can mask certain identifying characteristics of new hire candidates at the initial stages of the hiring process, including characteristics that may identify a person’s gender, race, disability, ethnicity or nationality. We are committed to attracting and retaining high-performing employees through this diverse talent base and evaluating and promoting throughout our organization based on skills and performance. The latest statistics showing the breakdown of how our employees (excluding employees added through our Alliance acquisition, which closed on July 1, 2022) self-identify their ethnicity is available in our most recent Corporate Sustainability Report, a copy of which is available on our website at www.helixesg.com/about-helix/our-company/corporate-sustainability.

Board Diversity

Our Board defines diversity expansively and has determined that it is desirable to have diverse viewpoints, professional experiences, backgrounds (including gender, race, ethnicity and educational backgrounds) and skills, with the principal qualification of a director being the ability to act effectively on behalf of Company shareholders. As part of a long-standing refreshment process, the Governance Committee of our Board remained engaged in a search for additional independent directors with the diverse characteristics sought by our Board and in September 2022, our Board added two new gender and ethnically diverse members.

GOVERNMENT REGULATION

Overview

We provide services primarily in the Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa 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. Beginning in 2019 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, as described below. In addition, these conventions impose liability for certain environmental discharges, including strict liability in some cases.

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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 generally 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 Oil and Gas Authority (the “OGA”) in accordance with the Petroleum Act 1998. The OGA controls the Petroleum Operations Notices with which we comply for various well intervention and subsea construction projects, as required. The OGA also regulates the environmental requirements for our operations in the North Sea. We comply with the Oil Pollution Prevention and Control Regulations 2005 as required. In the North Sea, international regulations govern working hours and the working environment, as well as standards for diving procedures, equipment and diver health. We also note that the U.K.’s exit from the European Union (the “EU”) may result in the imposition of new laws, rules or regulations affecting operations inside U.K. territorial waters.

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 including work-related accident prevention and the use of machinery and equipment, 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 must also maintain its “in-class” status with a classification society, evidencing that 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 must 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 also adhere to 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, remain active in establishing and enforcing such requirements along with other aspects of the energy industries in their respective countries.

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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 Merchandise Statute (commonly known as the “Jones Act”), which generally provides that only vessels built in the U.S., owned 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 and BSEE

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 requires 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 are required to have 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.

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 has 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.

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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” and 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 satisfy 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 must be obtained to discharge 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, meaning that vessels operating in the U.S. must use fuel with a sulfur content no greater than 0.1%. Directives have been issued designed to reduce the emission of nitrogen oxides and sulfur oxides. These can impact both the fuel and the 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.

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Current Compliance and Potential Impact

We believe that we are in compliance in all material respects with the applicable environmental laws and regulations to which we are subject. 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 thus there can be no assurance that we will not incur significant environmental compliance costs or liabilities in the future.

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 operations. We maintain the 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 program generally covers 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 (“P&I”) insurance, which covers liabilities arising from the operation of vessels, and General Liability insurance, which covers liabilities arising from construction operations. Onshore employees are covered by Workers’ Compensation. 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 the liability policies described above, 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 with coverage as required by BOEM.

In addition, we maintain a separate insurance program for Helix Alliance, which provides physical damage coverage up to an agreed amount for each vessel. Helix Alliance onshore employees are covered by Workers’ Compensation, and Helix Alliance offshore employees and marine crews are covered by MEL insurance policy, which covers Jones Act exposures. We also carry a General Liability policy which covers liability arising from operations. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability.

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 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 that would cover us under certain circumstances against any such third-party claims associated with well control events.

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. Although there can be no assurance the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations.

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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, 2022, 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 “For the Investor” 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.

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

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 “For the Investor” 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:

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.

Coiled tubing system:  A continuous length of steel tubing (coiled tubing), 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 coiled tubing 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.

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.

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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, coiled tubing operations, well stimulation, and full plug and abandonment 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).

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.

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.

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 Gulf of Mexico 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.

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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 monohull 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 coiled tubing 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.

Market and Industry Risks

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

Our services are substantially dependent upon the condition of the oil and gas market, and in particular, the willingness of oil and gas companies 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 gas prices, which is influenced by numerous factors, including:

● 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;

● the global supply and demand for oil and natural gas;

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

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

● the occurrence or threat of an epidemic or pandemic disease and any related governmental response, including the COVID-19 pandemic and related governmental response;

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

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

● the level of excess production capacity;

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

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

● the sale and expiration dates of offshore leases globally;

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

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

● potential acceleration of the development of alternative fuels;

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

● weather conditions and natural disasters with respect to marine operations;

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

● environmental and other governmental regulations; and

● 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 our 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, or to cancel their contracts with us even if cancellation involves their paying a cancellation fee. 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.

We continue to actively monitor ongoing military hostilities in Ukraine and applicable laws, sanctions and trade control restrictions resulting from the conflict. 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 the ongoing conflict in Ukraine will depend on various factors, including the extent and duration of the conflict and its related effects on operating and capital spending by our oil and gas production customers.

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 have risen significantly since 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic. We bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification 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.

The COVID-19 pandemic could continue to disrupt our operations and adversely impact our business and financial results.

In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic. The nature of COVID-19 led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world imposed regulations such as shelter-in-place orders, quarantines, travel bans and similar restrictions in efforts to control its spread. As of December 31, 2022, despite the rollout of vaccines and the successes of mitigation efforts, new strains of coronavirus have arisen and may continue to be identified that may be more contagious, more severe, and for which vaccinations may not be effective. Furthermore, although vaccines have been identified, their efficacy and rollout pose logistical and other challenges. The pandemic resulted in the global economy experiencing a significant slowdown and uncertainty in 2020, which led to a precipitous decline in oil prices in response to demand concerns, as further discussed herein. These events resulted in reduced operating and capital spending by oil and gas producers. Although the oil and gas market has recovered since 2020, we expect that the uncertainty surrounding the spread of COVID-19 will continue to create market disruption that may undermine the confidence in overall industry viability. We are currently unable to predict the duration or severity of the ongoing pandemic or the responses thereto, and these events may continue to adversely impact our financial condition and results of operations.

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The spread of COVID-19 to one or more of our locations, including our vessels, could significantly impact our operations. We have implemented various protocols for both onshore and offshore personnel in efforts to limit the impact of COVID-19, however those may not prove fully successful. The spread of COVID-19 to our onshore workforce could prevent us from supporting our offshore operations, 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 result in the vessel, or some or all of a vessel crew (including customer crew), being quarantined and therefore impede the vessel’s ability to generate revenue. We have experienced several instances of COVID-19 among our offshore crew, and although to date we have managed to avoid major operational disruptions, there can be no guarantee that will remain the case. We have experienced challenges in connection with our offshore crew changes due to health and travel restrictions related to COVID-19, and those challenges and/or restrictions may continue or worsen. Further, we have been and may continue to be impacted by a decline in the available offshore workforce, whether due to the spread of COVID-19, considerations related to our protocols, attrition from our industry, or a combination of the foregoing.

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, 2022, backlog for our services supported by written agreements or contracts totaled $847 million, of which $533 million is expected to be performed in 2023.

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 able to be terminated earlier than expected, in the event of our customers’ diminished demand for our services due to global or industry conditions affecting our customers and their own revenues. 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 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.

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 four customers that represent approximately 69% of our total backlog as of December 31, 2022. 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 the 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.

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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 its own 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 soil conditions. In particular, our assets may experience challenges operating in new locations, presenting incremental complications; any of these factors could lead to performance concerns. The nature of offshore operations requires our offshore crew members as well as our customers and vendors to periodically travel to and from the vessels. The occurrence or threat of an epidemic or pandemic disease, including the COVID-19 pandemic and any related governmental regulations or other travel restrictions or safety measures, 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), contractual penalties, and ultimately, termination in the event of sustained non-performance. 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.

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

Continued industry uncertainty and domestic and global economic conditions, including the financial condition of our customers, 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. In the event one or more of our customers is adversely affected by the COVID-19 pandemic or otherwise, 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.

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 to the same extent as larger operators and/or 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 more frequent collection issues. Our financial results and liquidity could be adversely affected and we could incur losses.

Our forward-looking statements assume that our customers, lenders, insurers and other financial institutions will be able to fulfill their obligations under our various contracts, credit agreements and insurance policies. The inability of our customers and other counterparties to perform under these agreements may materially adversely affect our business, financial position, results of operations and cash flows.

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

We own vessels, systems and other equipment for which there are ongoing 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 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.

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Asset upgrade, modification, refurbishment, repair, dry dock and construction projects, and customer contractual acceptance of vessels, systems and other equipment, are subject to risks, including delays, cost overruns, loss of revenue 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.

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.

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. 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.

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 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.

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

Sustainability and ESG initiatives remain increasingly 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. We understand we have an important role to play as a steward of the people, communities and environments we serve, and we regularly look for ways to emphasize and improve our own ESG record. However the nature of the oil and gas sector in which we predominantly operate may impact in the near or long term sustainability sentiment of investors, lenders, other industry participants and individuals, as the global markets shift towards green energy and environmental conservation. This sentiment may in turn lead to a lack of investment, investability or borrowing capital, or a more negative overall perception related to the fossil fuel industry. Further, we may not succeed in implementing or communicating an ESG message that is well understood or received. 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 or vendors.

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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 Gulf of Mexico 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 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 Gulf of Mexico 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 offshore 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 catastrophic disaster, 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 could have a material adverse effect on us.

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.

In January 2019 we began owning oil and gas properties as part of our strategy to secure utilization for our vessels, systems and other equipment. 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 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:

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

● increases in taxes and governmental royalties;

● 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 in and out of foreign jurisdictions;

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

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

● currency exchange restrictions and exchange rate fluctuations;

● global economic cycles;

● restrictions or quotas on production and commodity sales;

● limited market access;

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

● 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 and logistics necessitated by the COVID-19 pandemic 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.

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, 2022, we had consolidated indebtedness of $264 million. The level of indebtedness may have an adverse effect on our future operations, including:

● 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;

● 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;

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

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

● 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;

● 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

● 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 and 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.

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

Prolonged periods of low utilization and 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.

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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. As of December 31, 2022, we had approximately $28.9 million in Nigerian Naira, which is subject to currency exchange controls established by the Central Bank of Nigeria. Those exchange controls limit our ability to convert our Nigerian Naira into U.S. dollars.

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 may affect our business operations, including impeding our operations and making our operations more difficult and/or costly.

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 operations. Offshore oil and gas 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. 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.

On December 20, 2019, CBP finalized a new set of rulings (the “2019 CBP Rulings”) that (i) restrict the scope of items that may be transported aboard non-coastwise qualified vessels on the OCS and (ii) establish rules regarding incidental vessel movements related to offshore lifting operations. The 2019 CBP Rulings constitute a significant step towards establishing a predictable regime of regulation for offshore operations. We are aware, however, that certain organizations are seeking to overturn the 2019 CBP Rulings, particularly with respect to offshore lifting operations. CBP, its parent agency, the Department of Homeland Security, the federal courts or the U.S. Congress could revisit the issue and, if a challenge to the 2019 CBP Rulings were successful along the lines sought by those organizations, the resulting interpretation of the Jones Act could adversely impact the operations of non-coastwise qualified vessels working in the Gulf of Mexico, and could potentially make it more difficult and/or costly to perform our offshore services in the area.

On January 1, 2021, the National Defense Authorization Act for fiscal year 2021 came into force which, among other things, extended federal law, including the Jones Act, to U.S. offshore wind farm projects, making it more difficult and/or costly to provide for U.S. renewables customers the services that we currently provide for renewables customers in the North Sea and Asia Pacific.

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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 entire 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 all applicable requirements when we performed them. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from our operations, would 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 EU and individual taxing jurisdictions are focused on tax base erosion and profit shifting as well as minimum tax directives. These initiatives and directives continue to evolve with country specific implementation legislation forthcoming. Additionally, we anticipate increased disclosure and information reporting to facilitate compliance with these rules and initiatives when enacted. While the impact of these proposed and future rules cannot be determined, they may have adverse effects on us, including increased administrative and compliance costs.

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. As a result of the Alliance acquisition, we acquired 21 vessels registered under the U.S. flag which operate in the U.S. Gulf of Mexico 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 are responsible for monitoring our ownership to ensure 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.

Enhanced regulations for deepwater offshore drilling may reduce the need for our services.

Exploration and development activities and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulations. To conduct deepwater drilling in the Gulf of Mexico, an operator is required to comply with existing and newly developed regulations and enhanced safety standards. Before drilling may commence, BSEE conducts many inspections of deepwater drilling operations for compliance with its regulations. Operators also are required to comply with Safety and Environmental Management System (“SEMS”) regulations within the deadlines specified by the regulations and confirm that their contractors have SEMS-compliant safety and environmental policies and procedures in place. Additionally, each operator must demonstrate that it has containment resources that are available promptly in the event of a loss of well control. It is expected that government authorities, including BOEM and BSEE, will continue to issue further regulations regarding deepwater offshore drilling. Our business, a significant portion of which is in the Gulf of Mexico, provides development services to newly drilled wells, and therefore relies heavily on the industry’s drilling of new oil and gas wells. If the issuance of drilling or other permits is significantly delayed, or if other oil and gas operations are delayed or reduced due to increased costs of complying with regulations, demand for our services may also decline. Moreover, if our assets are not redeployed such that we can provide our services at profitable rates, our business, financial condition, results of operations and cash flows would be materially adversely affected.

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In January 2021, the U.S. Department of the Interior issued Order No. 3395, “Temporary Suspension of Delegated Authority” (“Order 3395”), suspending the authority of the Department of Interior’s Bureaus and Offices to, among other things, issue any fossil fuel authorization including a lease, contract, or other agreement or drilling permit, and thereafter President Biden signed Executive Order 14008 (“EO 14008” and together with Order 3395, the “Orders”) which, among other things, established a moratorium on new oil and gas leasing of public lands and offshore waters pending the completion of a comprehensive review and reconsideration of federal oil and gas permitting and lease practices. While certain portions of the Orders have subsequently been challenged in the court system and the ultimate interpretation and enforcement of the Orders remains uncertain at this time, they appear reflective of a broader regulatory agenda that may pose additional challenges for the industries we serve. The Orders and other similar regulation may directly impede our operations or ability to service our customers’ needs. Such regulations could also result in offshore drilling rigs being diverted to well intervention work, which may create more competition for the services we offer. Such regulations may also affect oil and gas prices, which could impact the demand for our services. Such impediments, competition or reduction in activity could have a material adverse effect on our operations, competitive position, results of operations and cash flows.

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 drilling or further regulate offshore drilling, 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.

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 authorities, including prohibition of our participating in or curtailment of business operations in certain jurisdictions and the seizure of vessels or other assets. Further, we may have competitors who are not subject to the same laws, which may provide them with a competitive advantage over us in securing business or gaining other preferential treatment.

General Risks

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 industry has lost a significant number of experienced professionals over the years due to its cyclical nature, including recently in connection with industry downturn, the effects of the COVID-19 pandemic, 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 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.

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

We rely on our information 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, may be subject to cybersecurity breaches caused by, among other things, illegal hacking, insider threats, computer viruses, phishing, malware, ransomware, or acts of vandalism or terrorism, or those perpetrated by criminals or nation-state actors. Furthermore, we may also experience increased cybersecurity risk as some of our onshore personnel may periodically work remotely.

In 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 ensuing investigation of the incident would take time to complete. During that period, we would 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 litigation or indemnity claims including resulting from customer-imposed cybersecurity controls or other related contractual obligations. There could also be increased costs to detect, prevent, respond, or recover from cybersecurity incidents. 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.

We may execute a strategic transaction that may not achieve intended results, could increase our 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 ordinary 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, 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.

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, which may result in a decrease in the trading price of our common stock.

Our Board has in the past and may from time to time in the future authorize share repurchase programs. On February 20, 2023, we announced that our Board approved a new share repurchase program authorizing the repurchase of up to $200 million issued and outstanding shares of our common stock. The timing and amount of repurchases, if any, under such program would 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. Our cash flow typically fluctuates seasonally and the amount of Free Cash Flow returned in any quarter during the year may vary. 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. Furthermore, a share repurchase program could diminish our cash reserves, which may impact our ability to finance future growth or engage in alternative activities that could generate greater shareholder value. In addition, repurchases of our common stock pursuant to a share repurchase program could cause our stock price to be higher than it would be in the absence of such a program and could potentially reduce the market liquidity for our stock. 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.

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 arrangements with all of our executive officers that could require cash payments, terms in our convertible senior notes that could increase the applicable conversion rate and covenants in our asset-based credit agreement (the “ABL Facility”) 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

VESSELS AND OTHER OPERATING ASSETS

As of December 31, 2022, our fleet included 27 owned vessels, eight IRSs, three SILs, the ROAM, 15 marketable P&A systems (with the ability to scale up to 20 systems), six coiled tubing systems, 41 ROVs, seven trenchers and the IROV boulder grab. We also had six 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.

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Listing of Vessels and Other Assets Related to Operations as of December 31, 2022 ⁽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	DP2
Q5000	Bahamas	4/2015	358	DP3
Siem Helix 1 (5)	Bahamas	6/2016	521	DP3
Siem Helix 2 (5)	Bahamas	2/2017	521	DP3
Q7000 (6)	Bahamas	1/2020	320	DP3
8 IRSs, 3 SILs and the ROAM (7)	—	Various	—	—
Helix Alliance —
EPIC Hedron (heavy lift barge)	Vanuatu	7/2022	400	—
10 liftboats, 6 OSVs, 3 DSVs and 1 crew boat (8)	U.S.	7/2022	Various	DP1
15 marketable P&A systems and 6 coiled tubing systems	—	Various	—	—
Robotics —
41 ROVs, 7 Trenchers and the IROV boulder grab (4), (9)	—	Various	—	—
Grand Canyon II (5)	Norway	4/2015	419	DP3
Grand Canyon III (5)	Norway	5/2017	419	DP3
Horizon Enabler (5)	Barbados	5/2022	316	DP2
Shelia Bordelon (5)	U.S.	2/2022	257	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.

(2) Represents the date we placed our owned vessels in service (rather than the date of commissioning) or the date the 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 ABL Facility described in Note 7.

(5) Vessel under time charter agreement.

(6) Served as collateral for surety bond related to one campaign offshore Nigeria. Security interest was released in January 2023.

(7) We own a 50% interest in the ROAM and three of the IRSs. The two recently acquired deepwater IRSs have not yet been placed in service.

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

(9) Average age of our Robotics assets is approximately 11.0 years. One of the recently acquired trenchers has not yet been placed in service.

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 permit us to continue to provide our customers with well-maintained, reliable assets.

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FACILITIES

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

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	68	President, Chief Executive Officer and Director
Erik Staffeldt	51	Executive Vice President and Chief Financial Officer
Scott A. Sparks	49	Executive Vice President and Chief Operating Officer
Kenneth E. Neikirk	47	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 27 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.

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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 32 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 22 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 17, 2023, the closing sale price of our common stock on the NYSE was $7.62 per share. As of February 17, 2023, there were 280 registered shareholders and approximately 75,590 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, 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 Management’s Discussion and Analysis of Financial Condition and Results of Operations “— Liquidity and Capital Resources.”

Shareholder Return Performance Graph

The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2017 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 2022 (the “2022 Performance Peer Group”) including the following companies: Archrock, Inc., ChampionX Corporation, Core Laboratories N.V., Dril-Quip, Inc., Forum Energy Technologies, Inc., Helmerich & Payne, Inc., Nabors Industries Ltd., Newpark Resources, Inc., NexTier Oilfield Solutions Inc., Oceaneering International, Inc., Oil States International, Inc., Patterson-UTI Energy, Inc., ProPetro Holding Corp., RPC, Inc., Select Energy Services, Inc., TETRA Technologies, Inc., Tidewater Inc., Transocean Ltd. and USA Compression Partners, LP. The returns of each member of the 2022 Performance Peer Group have been weighted according to each individual company’s equity market capitalization as of December 31, 2022 and have been adjusted for the reinvestment of any dividends. We believe that in 2022 the members of the 2022 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, 2017 in our common stock at the closing price on that date price and on December 31, 2017 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 — (2.1)%; the 2022 Performance Peer Group — (41.4)%; the OSX — (38.5)%; and S&P 500 — 56.9%. 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,
	2017		2018		2019		2020		2021		2022
Helix	$	100.0	$	71.8	$	127.7	$	55.7	$	41.4	$	97.9
2022 Performance Peer Group Index	$	100.0	$	54.2	$	54.8	$	32.7	$	38.8	$	58.6
Oil Service Index	$	100.0	$	54.8	$	54.5	$	31.6	$	38.1	$	61.5
S&P 500	$	100.0	$	95.6	$	125.7	$	148.9	$	191.6	$	156.9

Source: Bloomberg

Issuer Purchases of Equity Securities

				(c)	(d)
				Total number	Maximum
				of shares	number of shares
	(a)	(b)		purchased as	that may yet
	Total number	Average		part of publicly	be purchased
	of shares	price paid		announced plans	under the plans
Period	purchased (1)	per share		or programs	or programs (2) (3)
October 1 to October 31, 2022	—	$	—	—	9,371,145
November 1 to November 30, 2022	—		—	—	9,371,145
December 1 to December 31, 2022	61,553		5.97	—	9,547,027
	61,553	$	5.97	—

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

(2) Under the terms of this share repurchase program, we were authorized 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, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our Employee Stock Purchase Plan (Note 13). On February 20, 2023, we announced that our Board authorized a new share repurchase program for repurchase of up to $200 million issued and outstanding shares of our common stock (Note 10). At the same time, our Board revoked the prior authorization relating to this repurchase program.

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(3) In December 2022, we issued 175,882 shares of restricted stock to independent members of our Board. In January 2023, we issued 9,210 shares of restricted stock to certain independent members of our Board who elected to take their 2022 quarterly fees in stock in lieu of cash. These issuances increase the number of shares available for repurchase under our previously authorized share repurchase program by a corresponding amount.

Item 6. [Reserved]

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.

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 full-field decommissioning operations. Our services are centered on a three-legged business model well positioned for a global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. Our well intervention fleet includes seven purpose-built well intervention vessels and 12 intervention systems. Our robotics equipment includes 41 work-class ROVs, seven trenchers and the IROV boulder grab. We charter robotics support vessels on long-term, short-term, flexible and spot bases to facilitate our ROV and trenching operations. Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties including the recently acquired interest in the Thunder Hawk Field. On July 1, 2022, we completed our acquisition of Alliance and formed a new reporting segment in the third quarter 2022 comprised of the Helix Alliance business. Our new Shallow Water Abandonment segment includes 10 liftboats, six OSVs, three DSVs, one 1760T heavy lift derrick barge, one crew boat, 15 marketable P&A systems (with the ability to scale up to 20 systems) and six coiled tubing systems.

Economic Outlook and Industry Influences

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

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

● the global supply and demand for oil and natural gas;

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

● actions taken by OPEC and/or OPEC+;

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

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

● the level of excess production capacity;

● the ability of oil and gas companies to generate funds or otherwise obtain 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;

● the transition towards renewable energy and carbon neutrality and away from fossil fuels;

● national energy sovereignty and energy security;

● the sale and expiration dates of offshore leases globally;

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

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

● potential acceleration of the development of alternative fuels;

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

● weather conditions, natural disasters, and epidemic and pandemic diseases, including the COVID-19 pandemic;

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

● environmental and other governmental regulations; and

● domestic and international tax laws, regulations and policies.

Oil and gas prices reached ten-year highs during the middle of 2022 and experienced moderate declines and volatility during the remainder of 2022. Global demand for oil and gas continues to recover as supply has been disrupted by regional conflicts. We expect oil and gas prices will remain robust for the near term, which should lead to higher customer spending for the industry. However, despite the current strong commodity price environment, there remain headwinds to commodity price stability, including those regional conflicts, high inflation and in particular governments’ and central banks’ efforts to taper economic growth, COVID-related uncertainties, various governmental and customer ESG initiatives and continued shifting of resource allocation to renewable energy. We expect these factors will continue to contribute to commodity price volatility and may temper customer spending for oil and gas projects.

We maximize production of remaining oil and gas reserves for our customers primarily in our Well Intervention segment. Historically, drilling rigs have been the asset class used for offshore well intervention work, and rig day rates are a pricing indicator for our services. Our customers have used drilling rigs on existing long-term contracts (rig overhang) to perform well intervention work instead of new drilling activities. Current volumes of work, rig utilization rates, the day rates quoted by drilling rig contractors and existing rig overhang affect the utilization and/or rates we can achieve for our assets and services.

Over the near-term, with the current high commodity price environment we expect oil and gas companies to invest in new long-cycle exploration projects in addition to maintaining and/or increasing production from their remaining reserves. As historically production enhancement through well intervention is less expensive per incremental barrel of oil than exploration, we continue to expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells. We expect the fundamentals for our business will remain favorable over the longer term as the need to prolong well life in oil and gas production is the primary driver of demand for our production enhancement services. This expectation is based on multiple factors, including (1) maintaining the optimal production of a well through enhancement is fundamental to maximizing the overall economics of well production; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling; and (3) extending the production of offshore wells not only maximizes a well’s production economics but also enables the financial benefit of delaying P&A costs, which can be substantial.

We support the energy transition to renewables through our services in offshore wind farm developments, primarily including subsea cable trenching and burial as well as 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 production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and government subsidies for renewable energy projects. We expect growth in our renewables services as the energy market transitions to continued renewable energy developments.

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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. As the subsea tree base expands and ages and customers shift resources to renewable energy, the demand for P&A services should persist. Our operations service the life cycle of an oil and gas field and provide P&A services at the end of the life of a field as required by governmental regulations, and we believe that we have a competitive advantage in performing these services efficiently.

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 have risen significantly since 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic. Although we may be able to mitigate our exposure to price increases through the rates we charge, we bear the costs of operating and maintaining our assets, including labor and material costs as well as recertification and dry dock costs. While the cost outlook is not certain, we believe that we can manage these inflationary pressures by introducing appropriate sales price adjustments and by actively pursuing internal cost management efforts. However, competitive market pressures may affect our ability to recoup these price increases through the rates we charge, which may result in reductions in our operating margins and cash flows in the future. The recent high inflation rates seen in various major economies have caused concerns for central banks’ tightening of monetary policies. These concerns have contributed to stock market volatility as well as higher interest rates, which, combined with ongoing regional conflicts and unrest and continued COVID-related disruptions throughout the globe, could provide a strained macroeconomic outlook and in turn affect energy markets.

The COVID-19 pandemic resulted in new market dynamics and challenges to us, including contributing significantly to oil and gas price volatility and increased costs related to our supply chain, logistics and human capital resources. While the COVID-19 pandemic has significantly receded since its peak, the full impact of the COVID-19 pandemic, including the duration of its impact on economic activity, remains unknown, we expect such impact could escalate in the future, including affecting our customers’ willingness to commit to future spending, limiting access to and use of capital, disrupting supply chains and increasing costs, and negatively affecting human capital resources.

Business Activity Summary

As the oil and gas market has improved due to the post-COVID-19 recovery and the impact of sovereign energy security and independence, and as the energy market continues its migration of energy transition towards renewables, we executed a number of transactions during 2022 that demonstrate our commitment to our strategy and outlook for the markets we serve.

In February 2022, we entered into a two-year P&A contract with Trident for the Siem Helix 1, which commenced in December 2022. In September 2022, our contract with Petrobras for the Siem Helix 2 was extended for two years until December 2024. In October 2022, we entered into an intervention and decommissioning contract with Shell Brasil Petroleo LTDA for the Q7000, which is scheduled to commence in 2024. In November 2022, we extended the agreement for the HP 1 for one year until at least June 1, 2024.

In January 2022, we executed a time charter agreement for the Horizon Enabler in the North Sea with minimum firm periods in 2022 and 2023. In February 2022, we executed a time charter agreement for the Shelia Bordelon in the Gulf of Mexico until June 2024. In February 2022, the charter agreements for the Siem Helix 1 and the Siem Helix 2 were extended to February 2025 and February 2027, respectively. In August 2022, the time charter agreements for the Grand Canyon II and Grand Canyon III vessels were extended to December 2027 and May 2028, respectively.

In July 2022, we completed the acquisition of Alliance, expanding our services to the shallow waters predominantly in the Gulf of Mexico shelf.

In August 2022, we acquired from MP GOM a 62.5% interest in the Thunder Hawk Field, which is comprised of mature wells located in the Gulf of Mexico.

In December 2022, we acquired a 50% interest in two deepwater IRSs that can be used on our vessels, serve as backups, or be deployed on a stand-alone basis to our customers around the world.

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We have continued to expand our services and offerings into the offshore renewable energy sector. During 2022, we performed site clearance and/or ROV support work on multiple renewable energy projects in the Asia Pacific and North Sea regions and offshore U.S. East Coast. In November 2022, we acquired two jet trenchers and one plough trencher, which will enable us to expand our renewables trenching services into new markets.

Backlog

We define backlog as firm commitments represented by signed contracts. As of December 31, 2022, our consolidated backlog totaled $847 million, of which $533 million is expected to be performed in 2023. As of December 31, 2022, our contracts with Shell in the Gulf of Mexico, U.K. and Brazil, our contracts with Trident and Petrobras in Brazil and our agreement for the HP I in the Gulf of Mexico represented approximately 69% of our total backlog. As of December 31, 2021, our consolidated backlog totaled $348 million. Backlog is not necessarily a reliable indicator of revenues derived from our contracts as services are often added but may sometimes be subtracted; contracts may be renegotiated, deferred, canceled and in many cases modified while in progress; and reduced rates, fines and penalties may be imposed by our customers. Furthermore, our contracts are in certain cases cancelable without penalty. If there are cancellation fees, the amount of those fees can be substantially less than amounts reflected in backlog.

RESULTS OF OPERATIONS

Non-GAAP Financial Measures

A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under 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 measure our operating performance 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 income or cash flow data prepared in accordance with GAAP.

We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets, acquisition and integration costs, the change in fair value of contingent consideration and the general provision (release) for current expected credit losses, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, which are excluded from EBITDA as a component of net other income or expense. We define Free Cash Flow as cash flows from operating activities less capital expenditures, net of proceeds from sale of assets. Net Debt is calculated as long-term debt including current maturities of long-term debt less cash and cash equivalents and restricted cash. In the following reconciliation, we provide amounts as reflected in the condensed 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,
	2022		2021		2020
Net income (loss)	$	(87,784)	$	(61,684)	$	20,084
Adjustments:
Income tax provision (benefit)		12,603		(8,958)		(18,701)
Net interest expense		18,950		23,201		28,531
(Gain) loss on extinguishment of long-term debt		—		136		(9,239)
Other (income) expense, net		23,330		1,490		(4,724)
Depreciation and amortization		142,686		141,514		133,709
Goodwill impairment		—		—		6,689
Gain on equity investment		(8,262)		—		(264)
EBITDA		101,523		95,699		156,085
Adjustments:
(Gain) loss on disposition of assets, net		—		631		(889)
Acquisition and integration costs		2,664		—		—
Change in fair value of contingent consideration		16,054		—		—
General provision (release) for current expected credit losses		781		(54)		746
Realized losses from foreign exchange contracts not designated as hedging instruments		—		—		(682)
Adjusted EBITDA	$	121,022	$	96,276	$	155,260

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

	Year Ended December 31,
	2022		2021		2020
Cash flows from operating activities	$	51,108	$	140,117	$	98,800
Less: Capital expenditures, net of proceeds from sale of assets		(33,504)		(8,271)		(19,281)
Free Cash Flow	$	17,604	$	131,846	$	79,519

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

	December 31,
	2022		2021
Long-term debt including current maturities	$	264,075	$	305,010
Less: Cash and cash equivalents and restricted cash		(189,111)		(327,127)
Net Debt	$	74,964	$	(22,117)

Comparison of Years Ended December 31, 2022 and 2021

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

	Year Ended December 31,				Increase/(Decrease)
	2022		2021		Amount		Percent
Net revenues —
Well Intervention	$	524,241	$	516,564	$	7,677	1	%
Robotics		191,921		137,295		54,626	40	%
Shallow Water Abandonment		124,810		—		124,810	100	%
Production Facilities		82,315		69,348		12,967	19	%
Intercompany eliminations		(50,187)		(48,479)		(1,708)
	$	873,100	$	674,728	$	198,372	29	%

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	Year Ended						Increase/
	December 31,						(Decrease)
	2022			2021			Amount		Percent
Gross profit (loss) —
Well Intervention	$	(40,107)		$	(21,262)		$	(18,845)	89	%
Robotics		37,507			13,441			24,066	179	%
Shallow Water Abandonment		23,919			—			23,919	100	%
Production Facilities		30,666			25,024			5,642	23	%
Corporate, eliminations and other		(1,369)			(1,810)			441
	$	50,616		$	15,393		$	35,223	229	%
Gross margin —
Well Intervention		(8)	%		(4)	%
Robotics		20	%		10	%
Shallow Water Abandonment		19	%		—	%
Production Facilities		37	%		36	%
Total company		6	%		2	%
Number of vessels, Robotics assets or Shallow Water Abandonment systems (1) / Utilization (2)
Well Intervention vessels		7 / 80	%		7 / 67	%
Robotics assets (3)		48 / 53	%		47 / 36	%
Chartered Robotics vessels		5 / 95	%		3 / 97	%
Shallow Water Abandonment vessels (4)		21 / 73	%		— / —	%
Shallow Water Abandonment systems (5)		21 / 62	%		— / —	%

(1) Represents the number of vessels, Robotics assets or marketable 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 marketable Shallow Water Abandonment systems generated revenues by the total number of calendar days in the applicable period. Utilization rates of chartered Robotics vessels in 2022 and 2021 included 420 and 477 spot vessel days, respectively, at near full utilization.

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

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

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

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/
	2022		2021		(Decrease)
Well Intervention	$	16,545	$	21,521	$	(4,976)
Robotics		33,642		26,958		6,684
	$	50,187	$	48,479	$	1,708

Net Revenues. Our consolidated net revenues increased by 29% in 2022 as compared to 2021, reflecting the addition of Shallow Water Abandonment segment in the third quarter 2022 and higher revenues from all of our segments.

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Our Well Intervention revenues increased by 1% in 2022 as compared to 2021, primarily reflecting higher vessel utilization and rates in the Gulf of Mexico and the North Sea as well as higher utilization on the Siem Helix 1 during 2022, offset in part by lower utilization on the Q7000 due to its scheduled maintenance during 2022, lower rates on the Siem Helix 1 and the Siem Helix 2 as they transitioned from their legacy contracts with Petrobras, and a weaker British pound during 2022 as compared to 2021. Overall Well Intervention vessel utilization increased to 80% in 2022 as compared to 67% in 2021.

Our Robotics revenues increased by 40% in 2022 as compared to 2021, primarily reflecting higher vessel, trenching and ROV activities. Chartered vessel days increased to 1,401 days, which included 420 spot vessel days, in 2022 as compared to 1,178 days, which included 477 spot vessel days, in 2021. Trenching days increased to 483 days during 2022 as compared to 336 days during 2021. Overall ROV and trencher utilization increased to 53% during 2022 from 36% during 2021.

Our Shallow Water Abandonment revenues in 2022 reflected revenues generated by Helix Alliance since the acquisition on July 1, 2022 (Note 3). The Epic Hedron heavy lift barge was 21% utilized, utilization of other Helix Alliance vessels was 76%, and utilization across marketable P&A and coiled tubing systems was 2,324 days, or 62%.

Our Production Facilities revenues increased by 19% in 2022 as compared to 2021, primarily reflecting higher oil and gas prices and improved rates related to the HFRS, offset in part by lower oil and gas production volumes in 2022. Revenues also benefitted from retroactive rate adjustment on our production contract with the HP I.

Gross Profit (Loss). Our consolidated 2022 gross profit increased by $35.2 million as compared to 2021, primarily reflecting increased profitability in our Robotics and Production Facilities segments and the addition of Shallow Water Abandonment segment in the third quarter 2022, offset in part by decreased profitability in our Well Intervention segment.

Our Well Intervention segment had a gross loss of $40.1 million in 2022 as compared to a gross loss of $21.3 million in 2021, primarily reflecting our mix of contracting year over year, with our lower rates in Brazil generating higher losses, offset in part by increased Gulf of Mexico and North Sea revenues generating lower incremental margins driven by an increase in integrated projects and reimbursable revenues during 2022.

Our Robotics gross profit increased by $24.1 million in 2022 as compared to 2021, primarily reflecting higher revenues due to increased trenching and ROV activities and a higher number of vessel days.

Our Shallow Water Abandonment gross profit in 2022 reflected results from Helix Alliance since the acquisition on July 1, 2022.

Our Production Facilities gross profit increased by $5.6 million in 2022 as compared to 2021, primarily reflecting increases in revenues, offset in part by higher costs during 2022.

Acquisition and Integration Costs. Our acquisition and integration costs of $2.7 million reflected Alliance acquisition related costs incurred during 2022 (Note 3).

Change in Fair Value of Contingent Consideration. The $16.1 million change in fair value of contingent consideration reflected an increase in the estimated earn-out payable in 2024 to the seller in the Alliance transaction as Helix Alliance’s 2022 results following the acquisition date and its expected 2023 results have both improved as compared to forecasts and information available at the time of acquisition (Notes 3 and 19).

Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $76.8 million in 2022 as compared to $63.4 million in 2021, primarily reflecting higher employee incentive and share-based compensation costs as well as increased general and administrative expenses related to Helix Alliance.

Equity in Earnings of Investment. Equity in earnings of investment of $8.3 million primarily reflected the cash distribution as a result of the sale of the “Independence Hub” platform in 2022 (Note 2).

Net Interest Expense. Our net interest expense totaled $19.0 million in 2022 as compared to $23.2 million in 2021, primarily reflecting lower funded debt, which decreased by $42.9 million during 2022, and lower fees associated with our credit facility as compared to 2021 (Note 7).

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Other Income (Expense), Net. Net other expense was $23.3 million in 2022 as compared to $1.5 million in 2021, primarily reflecting higher foreign currency losses due to weakening of the British pound in 2022.

Income Tax Provision (Benefit). Income tax provision was $12.6 million for 2022 as compared to income tax benefit of $9.0 million for 2021. The effective tax rates for 2022 and 2021 were (16.8)% and 12.7%, respectively. These variances were primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions as well as losses in certain jurisdictions for which no financial statement benefits have been recognized (Note 8).

Comparison of Years Ended December 31, 2021 and 2020

Various financial and operational highlights for the years ended December 31, 2021 and 2020 were previously presented in our 2021 Annual Report on Form 10-K.

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,
	2022		2021
Net working capital	$	162,634	$	251,255
Long-term debt		225,875		262,137
Liquidity		284,729		304,660

Net Working Capital

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

Long-Term Debt

Long-term debt in the table above is net of unamortized debt issuance costs and excludes current maturities of $38.2 million and $42.9 million, respectively, at December 31, 2022 and 2021. See Note 7 for information relating to our long-term debt.

Liquidity

We define liquidity as cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility. Our liquidity at December 31, 2022 included $186.6 million of cash and cash equivalents and $98.1 million of available borrowing capacity under the ABL Facility (Note 7) and excluded $2.5 million of restricted cash. Our liquidity at December 31, 2021 included $253.5 million of cash and cash equivalents and $51.1 million of available borrowing capacity under the ABL Facility and excluded $73.6 million of short-term project related restricted cash. The reduction in cash and cash equivalents was primarily attributable to our acquisition of Alliance on July 1, 2022 (Note 3). The increase in available borrowing capacity under the ABL Facility resulted from debt repayments during 2022. As of December 31, 2022, we had approximately $28.9 million in Nigerian Naira, which is subject to currency exchange controls established by the Central Bank of Nigeria. Those exchange controls have to date restricted our ability to convert our Nigerian Naira into U.S. dollars.

During 2022, we saw an improvement in the markets we serve as evidenced by increases in our revenues and gross profit. We expect continued improvements in our operating performance, increases in our cash position and high availability on the ABL Facility. We believe that our cash on hand, internally generated cash flows and availability under the ABL Facility will be sufficient to fund our operations and service our debt over at least the next 12 months.

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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 ABL Facility. We currently do not anticipate borrowing under the ABL Facility other than for the issuance of letters of credit.

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. The repurchase program has no set expiration date. Repurchases under the program would be made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management based on an evaluation of market conditions, stock price, liquidity and other factors. The program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. The purchase of shares by us under the program is at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled. No repurchases have been made pursuant to this program at the time of this filing.

Cash Flows

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

	Year Ended December 31,
	2022		2021		2020
Cash provided by (used in):
Operating activities	$	51,108	$	140,117	$	98,800
Investing activities		(138,289)		(8,271)		(19,281)
Financing activities		(44,844)		(95,997)		(52,578)

Operating Activities

The decrease in our operating cash flows for 2022 as compared to 2021 primarily reflects higher regulatory recertification costs for our vessels and systems and negative changes in net working capital. Regulatory recertification spend on our vessels and systems amounted to $35.1 million and $9.6 million, respectively, during the comparable year over year periods. Operating cash flows for 2022 and 2021 included the receipt of $1.1 million and $18.9 million, respectively, in income tax refunds related to the U.S. Coronavirus Aid, Relief, and Economic Security Act.

Investing Activities

Cash flows used in investing activities for 2022 as compared to 2021 primarily reflect $112.6 million in net cash paid to acquire Alliance (Note 3), offset in part by $7.8 million in net cash distribution from Independence Hub in May 2022 (Note 2) and the deferral or reduction of our planned capital expenditures as our response to the adverse impact to our operations as a result of the COVID-19 pandemic.

Financing Activities

Net cash outflows from financing activities in 2022 primarily reflect the repayment of $7.9 million related to the MARAD Debt and $35 million related to the 2022 Notes (Note 7). Net cash outflows from financing activities of $96.0 million in 2021 primarily reflect the repayment of $90.9 million related to our indebtedness, including the final maturity of $53.6 million of the Nordea Q5000 Loan in January 2021 and $28.0 million in full repayment of the Term Loan in September 2021.

Material Cash Requirements

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

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Long-term debt and other contractual commitments

The following table summarizes the principal amount of our long-term debt and related debt service costs as well as other contractual commitments, which include commitments for property and equipment and operating lease obligations, as of December 31, 2022 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated maturities (in thousands). Our property and equipment commitments include contractually committed amounts to purchase and service certain property and equipment (inclusive of commitments related to regulatory recertification and dry dock as discussed below) but do not include expected capital spending that is not contractually committed as of December 31, 2022. Our 2023 Notes and 2026 Notes have certain early redemption and conversion features that could affect the timing and amount of any cash requirements. Although upon conversion these notes are able to be settled in either cash or shares, we intend to settle their principal amounts in cash (Note 7).

	Total		Short-Term		Long-Term
MARAD debt	$	40,913	$	8,333	$	32,580
2023 Notes		30,000		30,000		—
2026 Notes		200,000		—		200,000
Interest related to debt		49,439		16,668		32,771
Property and equipment		14,350		14,350		—
Operating leases (1)		406,378		114,378		292,000
Earn-out consideration (2)		42,754		—		42,754
Total cash obligations	$	783,834	$	183,729	$	600,105

(1) Operating leases include vessel charters and facility and equipment leases. At December 31, 2022, our commitment related to long-term vessel charters totaled approximately $378.8 million, of which $157.3 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, 2022.

(2) As part of the Alliance acquisition, we are required to make the earn-out payment to the seller in the Alliance transaction in 2024 in the event the Helix Alliance business achieves certain financial metrics in 2022 and 2023 (Note 3). Amount reflects the estimated fair value of the earn-out as of December 31, 2022 although the final earn-out payable is not capped.

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 $78.6 million (undiscounted) as of December 31, 2022, none of which is expected to be paid during the next 12 months. We are entitled to receive certain amounts from Marathon Oil as certain decommissioning obligations are fulfilled.

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

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

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CRITICAL ACCOUNTING ESTIMATES

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.

Business Acquisition

We account for business acquisitions under the acquisition method of accounting. We determine the purchase price to be the cash and other assets transferred to the seller and the value of any liabilities, such as contingent consideration or other seller financing incurred. The estimate of any contingent consideration and its fair value on the acquisition date and subsequent reporting periods is a significant estimate.

We allocate the purchase price of businesses we acquire to identifiable assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. Any excess purchase price over the fair value of the net identifiable assets acquired is recorded as goodwill. The allocation of the purchase price requires management to make significant estimates in determining the fair values of assets acquired and liabilities assumed. These estimates and assumptions may include, but are not limited to, the cash flows that an asset is expected to generate in the future, the appropriate weighted average cost of capital, and the estimated useful lives. Changes in these assumptions could affect the carrying value of these assets, the amount of future depreciation or amortization and any possible impairment charges.

We use available and relevant information to estimate fair values (including quoted market prices when available) and the nominal value of acquired assets and assumed liabilities as well as deploy various valuation techniques such as discounted cash flows. We may engage third party specialists to assist in the fair value determination of acquired assets and liabilities, including identifiable long-lived assets and identifiable intangible assets, as well as any contingent earn-out consideration to be paid to the seller if certain future conditions are met. The judgments made in determining the estimated fair value assigned to each class of assets acquired and liabilities assumed, the estimated fair value of contingent earn-out considerations, as well as the remaining useful lives of these assets, could materially impact our financial condition or results of operations. See Note 3 to our consolidated financial statements for further discussion on our acquisition of Alliance during 2022.

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.

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The determination of the appropriate asset groups at which to evaluate impairment, 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.

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.

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, 2022, approximately 40% 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, 2022, 2021 and 2020, we recorded foreign currency translation gains (losses) of $(49.2) million, $(4.5) million and $12.8 million, respectively, to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as the related undistributed earnings are permanently reinvested.

When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the 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, 2022, 2021 and 2020, we recorded foreign currency transaction gains (losses) of $(23.4) million, $(1.5) million and $4.6 million, respectively, primarily related to U.S. dollar denominated intercompany debt in our U.K. entities.

Interest Rate Risk. In order to maintain a cost-effective capital structure, we borrow funds using a mix of fixed rate debt and variable rate debt. For fixed rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Changes in fair value should not have a significant impact on fixed rate debt as there is typically no repayment obligation prior to maturity. We currently have no exposure to interest rate risks as we have no outstanding debt subject to floating rates. However, we may be at risk upon refinancing maturing debt.

Commodity Price Risk. We are exposed to market price risks related to oil and natural gas with respect to offshore oil and gas production in our Production Facilities business. Prices are volatile and unpredictable and are dependent on many factors beyond our control. See Item 1A. Risk Factors for a list of factors affecting oil and 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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2022, 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, 2022, 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 23, 2023 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 Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate 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 critical audit matters 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 matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

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, 2022 was $1,642 million.

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.

47

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.

Fair value measurement of contingent consideration and property and equipment acquired in the Alliance acquisition

As discussed in Note 3 to the consolidated financial statements, on July 1, 2022, the Company acquired the Alliance group of companies (Alliance) in a business combination for total purchase consideration of $145.7 million, including contingent consideration related to the post-closing earn-out consideration. In connection with the transaction, the purchase price consideration was allocated to the assets acquired and liabilities assumed of Alliance based upon their fair values as of the acquisition date, primarily comprised of property and equipment which the Company estimated the fair value to be approximately $117.3 million. The acquisition date fair value of the contingent consideration was approximately $26.7 million and year end fair value was approximately $42.8 million.

We identified the evaluation of the fair value measurement of the contingent consideration and the property and equipment acquired in the Alliance acquisition, including the subsequent fair value measurement of the contingent consideration, as a critical audit matter. Specifically, there was complex auditor judgment involved in evaluating (1) the weighted average cost of capital and the expected gross profit assumptions used to estimate the fair value of the contingent consideration which was sensitive to changes in those assumptions and (2) the estimated replacement cost and economic obsolescence assumptions used to determine the fair value of the property and equipment.

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 over the Company’s acquisition-date and year-end valuation process, including controls related to the determination of the assumptions listed above. We evaluated the reasonableness of the Company’s forecasted gross profit as of the acquisition date and year-end for the period of the contingent consideration by comparing the forecast to (1) Alliance’s historical gross profit trends, (2) Alliance’s actual performance subsequent to the acquisition, and (3) external economic and market data. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in evaluating:

● the weighted average cost of capital assumption by independently developing a range of rates using publicly available market interest rate data

● the Company’s assumptions over the estimated replacement cost including economic obsolescence applied by comparing selected trends and data with leading industry sources.

/s/ KPMG LLP

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

Houston, Texas

February 23, 2023

48

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, 2022, 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, 2022, 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, 2022 and 2021, 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, 2022, and the related notes (collectively, the consolidated financial statements), and our report dated February 23, 2023 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired the Alliance group of companies during 2022, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2022, the Alliance group of companies’ internal control over financial reporting associated with approximately 8.7% of total assets and 14.3% of total revenues included in the consolidated financial statements of the Company as of and for the year ended December 31, 2022. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of the Alliance group of companies.

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 23, 2023

49

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31,
	2022		2021
ASSETS
Current assets:
Cash and cash equivalents	$	186,604	$	253,515
Restricted cash		2,507		73,612
Accounts receivable, net of allowance for credit losses of $2,277 and $1,477, respectively		212,779		144,137
Other current assets		58,699		58,274
Total current assets		460,589		529,538
Property and equipment		3,016,312		2,938,154
Less accumulated depreciation		(1,374,697)		(1,280,509)
Property and equipment, net		1,641,615		1,657,645
Operating lease right-of-use assets		197,849		104,190
Deferred recertification and dry dock costs, net		38,778		16,291
Other assets, net		50,507		18,364
Total assets	$	2,389,338	$	2,326,028
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable	$	135,267	$	87,959
Accrued liabilities		73,574		91,712
Current maturities of long-term debt		38,200		42,873
Current operating lease liabilities		50,914		55,739
Total current liabilities		297,955		278,283
Long-term debt		225,875		262,137
Operating lease liabilities		154,686		50,198
Deferred tax liabilities		98,883		86,966
Other non-current liabilities		95,230		975
Total liabilities		872,629		678,559
Commitments and contingencies
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 151,935 and 151,124 shares issued, respectively		1,298,740		1,292,479
Retained earnings		323,288		411,072
Accumulated other comprehensive loss		(105,319)		(56,082)
Total shareholders’ equity		1,516,709		1,647,469
Total liabilities and shareholders’ equity	$	2,389,338	$	2,326,028

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

50

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per share amounts)

	Year Ended December 31,
	2022		2021		2020
Net revenues	$	873,100	$	674,728	$	733,555
Cost of sales		822,484		659,335		653,646
Gross profit		50,616		15,393		79,909
Gain (loss) on disposition of assets, net		—		(631)		889
Goodwill impairment		—		—		(6,689)
Acquisition and integration costs		(2,664)		—		—
Change in fair value of contingent consideration		(16,054)		—		—
Selling, general and administrative expenses		(76,753)		(63,449)		(61,084)
Income (loss) from operations		(44,855)		(48,687)		13,025
Equity in earnings (losses) of investment		8,262		(1)		216
Net interest expense		(18,950)		(23,201)		(28,531)
Gain (loss) on extinguishment of long-term debt		—		(136)		9,239
Other income (expense), net		(23,330)		(1,490)		4,724
Royalty income and other		3,692		2,873		2,710
Income (loss) before income taxes		(75,181)		(70,642)		1,383
Income tax provision (benefit)		12,603		(8,958)		(18,701)
Net income (loss)		(87,784)		(61,684)		20,084
Net loss attributable to redeemable noncontrolling interests		—		(146)		(2,090)
Net income (loss) attributable to common shareholders	$	(87,784)	$	(61,538)	$	22,174
Earnings (loss) per share of common stock:
Basic	$	(0.58)	$	(0.41)	$	0.13
Diluted	$	(0.58)	$	(0.41)	$	0.13
Weighted average common shares outstanding:
Basic		151,276		150,056		148,993
Diluted		151,276		150,056		149,897

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

51

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

	Year Ended December 31,
	2022		2021		2020
Net income (loss)	$	(87,784)	$	(61,684)	$	20,084
Other comprehensive income (loss), net of tax:
Net unrealized loss on hedges arising during the period		—		—		(95)
Reclassifications into earnings		—		—		452
Income taxes on hedges		—		—		(72)
Net change in hedges, net of tax		—		—		285
Foreign currency translation gain (loss)		(49,237)		(4,462)		12,835
Other comprehensive income (loss), net of tax		(49,237)		(4,462)		13,120
Comprehensive income (loss)		(137,021)		(66,146)		33,204
Less comprehensive loss attributable to redeemable noncontrolling interests:
Net loss		—		(146)		(2,090)
Foreign currency translation gain		—		50		90
Comprehensive loss attributable to redeemable noncontrolling interests		—		(96)		(2,000)
Comprehensive income (loss) attributable to common shareholders	$	(137,021)	$	(66,050)	$	35,204

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

52

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY

(in thousands)

						Accumulated
						Other		Total		Redeemable
	Common Stock			Retained		Comprehensive		Shareholders’		Noncontrolling
	Shares	Amount		Earnings		Loss		Equity		Interests
Balance, December 31, 2019	148,888	$	1,318,961	$	445,370	$	(64,740)	$	1,699,591	$	3,455
Net income (loss)	—		—		22,174		—		22,174		(2,090)
Credit losses recognized in retained earnings upon adoption of ASU No. 2016-13	—		—		(620)		—		(620)		—
Foreign currency translation adjustments	—		—		—		12,835		12,835		90
Unrealized gain on hedges, net of tax	—		—		—		285		285		—
Accretion of redeemable noncontrolling interests	—		—		(2,400)		—		(2,400)		2,400
Equity component of convertible senior notes	—		33,336		—		—		33,336		—
Re-acquisition of equity component of convertible senior notes	—		(18,006)		—		—		(18,006)		—
Capped call transactions	—		(10,625)		—		—		(10,625)		—
Activity in company stock plans, net and other	1,453		(4,345)		—		—		(4,345)		—
Share-based compensation	—		8,271		—		—		8,271		—
Balance, December 31, 2020	150,341	$	1,327,592	$	464,524	$	(51,620)	$	1,740,496	$	3,855
Net loss	—		—		(61,538)		—		(61,538)		(146)
Cumulative-effect adjustments upon adoption of ASU No. 2020-06	—		(41,456)		6,682		—		(34,774)		—
Foreign currency translation adjustments	—		—		—		(4,462)		(4,462)		50
Accretion of redeemable noncontrolling interests	—		—		1,404		—		1,404		(1,404)
Acquisition of redeemable noncontrolling interests	—		—		—		—		—		(2,355)
Activity in company stock plans, net and other	783		(1,128)		—		—		(1,128)		—
Share-based compensation	—		7,471		—		—		7,471		—
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	$	—

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

53

HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2022		2021		2020
Cash flows from operating activities:
Net income (loss)	$	(87,784)	$	(61,684)	$	20,084
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		142,686		141,514		133,709
Goodwill impairment		—		—		6,689
Amortization of debt discounts		—		—		6,964
Amortization of debt issuance costs		2,334		3,179		3,177
Share-based compensation		7,451		7,689		8,568
Deferred income taxes		4,386		(15,202)		(3,883)
Equity in (earnings) losses of investment		(8,262)		1		(216)
(Gain) loss on disposition of assets, net		—		631		(889)
(Gain) loss on extinguishment of long-term debt		—		136		(9,239)
Unrealized gain on derivative contracts, net		—		—		(601)
Unrealized foreign currency (gain) loss		21,596		2,252		(2,665)
Change in fair value of contingent consideration		16,054		—		—
Changes in operating assets and liabilities:
Accounts receivable, net		(29,865)		(14,154)		(8,419)
Other current assets		7,593		22,973		(28,664)
Income tax payable, net of income tax receivable		(49)		18,610		(22,124)
Accounts payable and accrued liabilities		9,807		46,645		10,830
Deferred recertification and dry dock costs, net		(35,072)		(9,620)		(19,348)
Other, net		233		(2,853)		4,827
Net cash provided by operating activities		51,108		140,117		98,800
Cash flows from investing activities:
Alliance acquisition, net of cash acquired		(112,625)		—		—
Capital expenditures		(33,504)		(8,322)		(20,244)
Distribution from equity investment, net		7,840		—		—
Proceeds from sale of assets		—		51		963
Net cash used in investing activities		(138,289)		(8,271)		(19,281)
Cash flows from financing activities:
Proceeds from convertible senior notes		—		—		200,000
Repayment of convertible senior notes		(35,000)		—		(183,150)
Repayment of Term Loan		—		(29,826)		(3,500)
Repayment of Nordea Q5000 Loan		—		(53,572)		(35,714)
Repayment of MARAD Debt		(7,937)		(7,560)		(7,200)
Capped call transactions		—		—		(10,625)
Debt issuance costs		(580)		(1,337)		(7,747)
Acquisition of redeemable noncontrolling interests		—		(2,355)		—
Payments related to tax withholding for share-based compensation		(1,902)		(2,001)		(5,264)
Proceeds from issuance of ESPP shares		575		654		622
Net cash used in financing activities		(44,844)		(95,997)		(52,578)
Effect of exchange rate changes on cash and cash equivalents and restricted cash		(5,991)		(42)		1,818
Net increase (decrease) in cash and cash equivalents and restricted cash		(138,016)		35,807		28,759
Cash and cash equivalents and restricted cash:
Balance, beginning of year		327,127		291,320		262,561
Balance, end of year	$	189,111	$	327,127	$	291,320

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

54

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 full-field decommissioning operations. Our services are centered toward and well positioned to facilitate global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. We have expanded our service capabilities to the Gulf of Mexico shelf with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022. Our North Sea operations and our Gulf of Mexico shelf operations related to our Alliance acquisition are subject to seasonal changes in demand, 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, Production Facilities and our new reporting segment, Shallow Water Abandonment, which was formed in the third quarter 2022 comprising the Helix Alliance business (Note 14).

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

Our Robotics segment provides trenching, seabed clearance, offshore construction and inspection, repair and maintenance (“IRM”) services to both the oil and gas and the renewable energy markets globally, thereby assisting the delivery of affordable and reliable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, the IROV boulder grab and robotics support vessels under term charters as well as spot vessels as needed.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat and plug and abandonment (“P&A”) and coiled tubing systems.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), the Helix Fast Response System (the “HFRS”), and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the Gulf of Mexico.

55

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of our majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership but have the ability to exert significant influence. All material intercompany accounts and transactions have been eliminated.

Basis of Presentation

Our consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”) in U.S. dollars. 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.

Restricted Cash

We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. Our restricted cash as of December 31, 2022 consisted of $2.5 million pledged toward our asset-based credit agreement (the “ABL Facility”). Our restricted cash as of December 31, 2021 consisted of $71.1 million pledged as collateral for a letter of credit for a temporary importation permit for work offshore Nigeria and $2.5 million pledged toward the ABL Facility. These cash pledges increase the availability under the ABL Facility.

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 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).

56

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, must be finalized as soon as practicable, but no later than one year from the closing of the acquisition.

Contingent consideration payable in cash, which is included in “Other non-current liabilities” in the accompanying consolidated balance sheet (Note 4), 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 earnings until the liability is settled.

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. Also presented separately are the changes in fair value of the contingent earn-out consideration (Note 19).

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.

Capitalized Interest

Interest from external borrowings is capitalized on major projects under development until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset. Capitalized interest is excluded from our interest expense (Note 7) and is included as an investing cash outflow in the consolidated statements of cash flows.

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.

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Leases

Leases with a term greater than one year are recognized in the consolidated balance sheet as right-of-use (“ROU”) assets and lease liabilities. 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.

Goodwill

Goodwill impairment is evaluated using a two-step process. The first step involves comparing a reporting unit’s fair value with its carrying amount. We have the option to assess qualitative factors to determine if it is necessary to perform the first step. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we must perform the quantitative goodwill impairment test, which involves estimating the reporting unit’s fair value and comparing it to its carrying amount. If the reporting unit’s carrying amount exceeds its fair value, impairment loss is recognized in an amount equal to that excess, but not to exceed the goodwill’s carrying amount.

We perform an impairment analysis of goodwill at least annually as of November 1 or more frequently whenever events or circumstances occur indicating that goodwill might be impaired. Our goodwill balance attributable to the acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) was fully impaired during 2020 (Note 3).

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 dry dock. 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 if the appropriate permitting is obtained. A recertification process, including vessel dry dock, typically lasts between one to three months, 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.

During the years ended December 31, 2022, 2021 and 2020, amortization expense related to deferred recertification and dry dock costs was $14.0 million, $14.6 million and $14.3 million, respectively.

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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 clearing for the oil and gas and the renewable energy markets and to provide offshore construction 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 new Shallow Water Abandonment segment by providing decommissioning and intervention services with P&A and coiled tubing 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 DSVs and personnel and with the heavy lift barge.

Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.

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 in which we provide 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.

The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We generally do not provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. 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.

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 and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. 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.

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 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. At December 31, 2022, we believe that we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit has been recognized or are required to pay amounts exceeding the liability, our effective tax rate in a given financial statement period may be affected.

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Share-Based Compensation

Share-based compensation is measured at the grant date based on the estimated fair value of an award. Share-based compensation based solely on service conditions is recognized on a straight-line basis over the vesting period of the related shares. Forfeitures are recognized as they occur.

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 performance share unit (“PSU”) awards that have a service and a market condition and 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 PSUs that have a service and a performance condition and 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.

Compensation cost for restricted stock unit (“RSU”) awards, which are accounted for as liability awards, is 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.

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, 2022, 2021 and 2020, our foreign currency transaction gains (losses) totaled $(23.4) million, $(1.5) million and $4.6 million, respectively.

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Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects of dilutive common stock equivalents, if any. 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 basic and diluted EPS under the two-class method in periods in which we have earnings. Under the two-class method, net income or loss attributable to common shareholders 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.

Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable 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 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) are as follows: 2022 — Shell (15%); 2021 — Petrobras (23%) and Shell (17%); and 2020 — Petrobras (28%) and BP (17%). Most of the concentration of revenues are in our Well Intervention segment.

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).

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New Accounting Standards

New accounting standards adopted

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Measurement of Credit Losses on Financial Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets (including trade receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. Upon adoption of ASU No. 2016-13 on January 1, 2020, we recognized $0.6 million (net of deferred taxes of $0.2 million) related to the provision for current expected credit losses on our accounts receivable through a cumulative effect offset to retained earnings. The credit loss standard also resulted in the recognition of an additional $0.7 million in credit loss reserves on our accounts receivable for the year ended December 31, 2020. See Note 18 for additional information regarding allowance for credit losses on our accounts receivable.

In August 2020, the FASB issued ASU No. 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity's Own Equity,” which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Among other changes, this ASU removes from GAAP the requirement to separate certain convertible instruments, such as our Convertible Senior Notes Due 2022 (the “2022 Notes”), Convertible Senior Notes Due 2023 (the “2023 Notes”) and Convertible Senior Notes Due 2026 (the “2026 Notes”) (Note 7), into liability and equity components. Consequently, those convertible instruments will be accounted for in their entirety as liabilities measured at their amortized cost. We elected to early adopt ASU No. 2020-06 on a modified retrospective basis beginning January 1, 2021. The adoption of this ASU increased our long-term debt and decreased the reported value of our common stock by $44.1 million and $41.5 million, respectively, as we reclassified the conversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of this ASU also increased our retained earnings and decreased deferred tax liabilities by $6.7 million and $9.3 million, respectively. As a result of our adoption of ASU No. 2020-06, interest expense associated with our outstanding convertible senior notes decreased by $7.6 million in 2021 as there were no longer any debt discounts to amortize.

New accounting standards issued but not yet effective

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

Note 3 — Business Combinations

Alliance Acquisition

On July 1, 2022, we completed our acquisition of all of the equity interests of Alliance. The Alliance acquisition extends our energy transition strategy by adding shallow water capabilities into what we expect to be a growing offshore decommissioning market.

The aggregate preliminary purchase price of the Alliance acquisition was $145.7 million, consisting of $119.0 million with cash on hand and the estimated fair value of $26.7 million of contingent consideration related to the post-closing earn-out consideration. The earn-out is payable in 2024 to the seller in the Alliance transaction in either cash or shares of our common stock pursuant to the terms of the Equity Purchase Agreement (the “Equity Purchase Agreement”) dated May 16, 2022. The earn-out is not capped and is calculated based on certain financial metrics of the Helix Alliance business for 2022 and 2023 relative to amounts as set forth in the Equity Purchase Agreement.

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The following table summarizes the purchase consideration and the preliminary purchase price allocation to estimated fair values of the identifiable assets acquired and liabilities assumed as of July 1, 2022 (in thousands):

	As Originally				As
	Reported		Adjustments (1)		Adjusted
Cash consideration	$	118,961	$	—	$	118,961
Contingent consideration		26,700		—		26,700
Total fair value of consideration transferred	$	145,661		—	$	145,661
Assets acquired:
Cash and cash equivalents	$	6,336		—	$	6,336
Accounts receivable (2)		43,378		—		43,378
Other current assets		4,879		1,198		6,077
Property and equipment		118,619		(1,298)		117,321
Operating lease right-of-use assets		1,205		—		1,205
Intangible assets		1,400		100		1,500
Other assets		2,133		—		2,133
Total assets acquired		177,950		—		177,950
Liabilities assumed:
Accounts payable		20,480		—		20,480
Accrued liabilities		3,073		—		3,073
Operating lease liabilities		1,205		—		1,205
Deferred tax liabilities		7,531		—		7,531
Total liabilities assumed		32,289		—		32,289
Net assets acquired	$	145,661	$	—	$	145,661

(1) Adjustments to the preliminary purchase price allocation stem mainly from additional information obtained in between the closing of the Alliance acquisition on July 1, 2022 and December 31, 2022 about facts and circumstances that existed as of the acquisition date.

(2) The gross contractual accounts receivable totaled $44.2 million. The fair value of accounts receivable reflects our best estimate at the acquisition date of contractual cash flows expected to be collected.

The pro forma summary below presents the results of operations as if the Alliance acquisition had occurred on January 1, 2021 and includes transaction accounting adjustments such as incremental depreciation and amortization expense from acquired tangible and intangible assets, elimination of interest expense on Alliance’s long-term debt that was paid off in conjunction with the acquisition, and tax-related effects. The pro forma summary uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any cost savings, operating synergies or revenue enhancements that might have been achieved from combining the operations. The unaudited pro forma summary is provided for illustrative purposes only and does not purport to represent Helix’s actual consolidated results of operations had the acquisition been completed as of the date presented, nor should it be considered indicative of Helix’s future consolidated results of operations.

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

	Year Ended December 31,
	2022		2021
Revenues	$	952,837	$	789,051
Net loss		(79,686)		(56,203)

STL Acquisition

In May 2019, we acquired a 70% controlling interest in STL, a subsea engineering firm based in Aberdeen, Scotland. The acquisition resulted in goodwill of $6.9 million. Oil prices as well as energy and energy services valuations experienced significant decline during the first quarter 2020 and as a result, we impaired all of our goodwill, which consisted entirely of goodwill attributable to STL. In June 2021, we acquired the remaining 30% interest in STL, which had been recognized as temporary equity. STL is included in our Well Intervention segment and its revenue and earnings are immaterial to our consolidated results.

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The changes in the carrying amount of goodwill are as follows (in thousands):

	Well Intervention
Balance at December 31, 2019	$	7,157
Impairment loss		(6,689)
Foreign currency adjustments		(468)
Balance at December 31, 2020	$	—

Note 4 — Details of Certain Accounts

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

	December 31,
	2022		2021
Prepaids	$	26,609	$	18,228
Income tax receivable		—		1,116
Contract assets (Note 11)		6,295		639
Deferred costs (Note 11)		13,969		2,967
Other receivable (1)		—		28,805
Other		11,826		6,519
Total other current assets	$	58,699	$	58,274

(1) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil in 2019; classified as current as the P&A work was expected to be performed within 12 months from December 31, 2021.

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

	December 31,
	2022		2021
Prepaid charter (1)	$	12,544	$	12,544
Deferred costs (Note 11)		6,432		381
Other receivable (2)		24,827		—
Intangible assets with finite lives, net		4,465		3,472
Other		2,239		1,967
Total other assets, net	$	50,507	$	18,364

(1) Represents prepayments to the owner of the Siem Helix 1 and the Siem Helix 2 to offset certain payment obligations associated with the vessels at the end of their respective charter term.

(2) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil; reclassified to non-current as we expect the remaining P&A work to be performed beyond 12 months from December 31, 2022.

Accrued liabilities consist of the following (in thousands):

	December 31,
	2022		2021
Accrued payroll and related benefits	$	41,339	$	28,657
Accrued interest		6,306		6,746
Income tax payable		479		—
Deferred revenue (Note 11)		9,961		8,272
Asset retirement obligations (Note 15)		—		29,658
Other		15,489		18,379
Total accrued liabilities	$	73,574	$	91,712

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

	December 31,
	2022		2021
Deferred revenue (Note 11)	$	—	$	476
Asset retirement obligations (Note 15)		51,956		—
Contingent consideration (Note 19)		42,754		—
Other		520		499
Total other non-current liabilities	$	95,230	$	975

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	2022		2021
Vessels	15 to 30 years	$	2,371,084	$	2,343,162
ROVs and trenchers	5 to 10 years		262,763		257,274
Machinery, equipment, buildings and other	5 to 39 years		382,465		337,718
Total property and equipment		$	3,016,312	$	2,938,154

Note 6 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. The majority of the increases in our operating leases during the year ended December 31, 2022 are related to the vessel charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II, the Grand Canyon III and the Shelia Bordelon (Note 16). We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, 2022, the minimum sublease income to be received in the future totaled $1.3 million.

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

	Year Ended December 31,
	2022		2021		2020
Operating lease cost	$	61,067	$	60,636	$	64,742
Variable lease cost		20,562		16,711		15,021
Short-term lease cost		29,487		20,590		37,524
Sublease income		(1,275)		(1,303)		(1,286)
Net lease cost	$	109,841	$	96,634	$	116,001

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

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	58,063	$	6,603	$	64,666
One to two years		55,515		5,697		61,212
Two to three years		43,400		2,797		46,197
Three to four years		35,200		959		36,159
Four to five years		26,244		959		27,203
Over five years		3,041		2,783		5,824
Total lease payments	$	221,463	$	19,798	$	241,261
Less: imputed interest		(32,986)		(2,675)		(35,661)
Total operating lease liabilities	$	188,477	$	17,123	$	205,600
Current operating lease liabilities	$	45,131	$	5,783	$	50,914
Non-current operating lease liabilities		143,346		11,340		154,686
Total operating lease liabilities	$	188,477	$	17,123	$	205,600

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Maturities of our operating lease liabilities as of December 31, 2021 are as follows (in thousands):

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	55,573	$	5,601	$	61,174
One to two years		34,580		4,844		39,424
Two to three years		2,470		4,514		6,984
Three to four years		—		2,462		2,462
Four to five years		—		1,074		1,074
Over five years		—		4,193		4,193
Total lease payments	$	92,623	$	22,688	$	115,311
Less: imputed interest		(5,633)		(3,741)		(9,374)
Total operating lease liabilities	$	86,990	$	18,947	$	105,937
Current operating lease liabilities	$	51,035	$	4,704	$	55,739
Non-current operating lease liabilities		35,955		14,243		50,198
Total operating lease liabilities	$	86,990	$	18,947	$	105,937

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

	December 31,
	2022		2021		2020
Weighted average remaining lease term	4.0	years	2.4	years	3.1	years
Weighted average discount rate	7.84	%	7.57	%	7.53	%

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

	Year Ended December 31,
	2022		2021		2020
Cash paid for operating lease liabilities	$	58,129	$	61,826	$	66,026
Right-of-use assets obtained in exchange for new operating lease obligations		144,134		5,992		516

Note 7 — Long-Term Debt

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

	December 31,
	2022		2021
2022 Notes (matured May 2022)	$	—	$	35,000
2023 Notes (mature September 2023)		30,000		30,000
2026 Notes (mature February 2026)		200,000		200,000
MARAD Debt (matures February 2027)		40,913		48,850
Unamortized debt issuance costs		(6,838)		(8,840)
Total debt		264,075		305,010
Less current maturities		(38,200)		(42,873)
Long-term debt	$	225,875	$	262,137

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 on July 1, 2022 we entered into a first amendment to the credit agreement (collectively, the “Amended ABL Facility”). The Amended ABL Facility provides for a $100 million asset-based revolving credit facility, which matures on September 30, 2026, with a springing maturity 91 days prior to the maturity of any outstanding indebtedness with a principal amount in excess of $50 million. The Amended ABL Facility also permits us to request an increase of the facility by up to $50 million, subject to certain conditions.

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Commitments under the Amended ABL Facility are comprised of separate U.S. and U.K. revolving credit facility commitments of $65 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 $10 million sub-limit for the issuance of letters of credit. As of December 31, 2022, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity under that facility, based on the borrowing base, totaled $98.1 million, net of $1.9 million of letters of credit issued under that facility.

We and certain of our U.S. and U.K. subsidiaries including Helix Alliance 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 (also known as CME Term SOFR as administered by CME Group, Inc.) rate 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 $10 million. The Amended ABL Facility also requires us to maintain a pro forma minimum excess availability of $20 million for the 91 days prior to the maturity of each of our outstanding convertible senior notes.

The Amended ABL Facility also (i) limits the amount of permitted debt for the deferred purchase price of property not to exceed $50 million, (ii) establishes an excess availability requirement for the portion of any post-closing earn-out consideration related to our acquisition of Alliance that will be paid in cash (Note 3), and (iii) provides for potential 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, related to environmental, social and governance (“ESG”) changes implemented by us in our business.

2022 Notes

We fully redeemed the $35 million remaining principal amount of the 2022 Notes plus accrued interest by delivering cash upon maturity as of May 1, 2022. The effective interest rate for the 2022 Notes was 4.8%. For the years ended December 31, 2022 and 2021, total interest expense related to the 2022 Notes was $0.6 million and $1.7 million, respectively, primarily from coupon interest expense. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). During 2020, we repurchased $90 million in aggregate principal amount of the 2022 Notes, and for the year ended December 31, 2020, total interest expense related to the 2022 Notes was $6.6 million, with coupon interest expense of $3.9 million and the amortization of debt discount and issuance costs of $2.7 million.

2023 Notes

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

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

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

The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2023 Notes together with any accrued interest will become immediately due and payable.

The effective interest rate for the 2023 Notes is 4.8%. For each of the years ended December 31, 2022 and 2021, total interest expense related to the 2023 Notes was $1.4 million primarily from coupon interest expense. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). During 2020, we repurchased $95 million in aggregate principal amount of the 2023 Notes, and for the year ended December 31, 2020, total interest expense related to the 2023 Notes was $6.6 million, with coupon interest expense of $3.7 million and the amortization of debt discount and issuance costs of $2.9 million.

2026 Notes

The 2026 Notes bear interest at a coupon interest rate of 6.75% per annum payable semi-annually in arrears on February 15 and August 15 of each year, beginning on February 15, 2021 until maturity. The 2026 Notes mature on February 15, 2026 unless earlier converted, redeemed or repurchased by us. The 2026 Notes are convertible by their holders at any time beginning November 17, 2025 at an initial conversion rate of 143.3795 shares of our common stock per $1,000 principal amount, which currently represents 28,675,900 potentially convertible shares at an initial conversion price of approximately $6.97 per share of common stock. Upon conversion, we have the right to satisfy our conversion obligation by delivering cash, shares of our common stock or any combination thereof. In order to reduce the potential dilution of the 2026 Notes to shareholders’ equity, we entered into capped call transactions (the “2026 Capped Calls”) in August 2020 concurrent with the 2026 Notes offering (Note 9). The 2026 Capped Calls effectively increase the conversion price of the 2026 Notes to approximately $8.42 per share. However, the 2026 Capped Calls are separate transactions from the 2026 Notes and do not change the holders’ rights under the 2026 Notes, and holders of the 2026 Notes do not have any rights with respect to the 2026 Capped Calls.

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

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Prior to August 15, 2023, the 2026 Notes are not redeemable. On or after August 15, 2023, we may redeem all or any portion of the 2026 Notes if the price of our common stock has been at least 130% of the conversion price for at least 20 trading days during any 30 consecutive trading day period preceding our redemption notice. Any redemption would be payable in cash equal to 100% of the principal amount plus accrued and unpaid interest and a “make-whole premium” calculated as the present value of all remaining scheduled interest payments. Holders of the 2026 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2026 Notes may also require us to repurchase the notes following a “fundamental change,” which includes a change of control or a termination of trading of our common stock (as defined in the indenture governing the 2026 Notes).

The indenture governing the 2026 Notes contains customary terms and covenants, including that upon certain events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2026 Notes together with any accrued interest will become immediately due and payable.

The effective interest rate for the 2026 Notes is 7.6%. For the years ended December 31, 2022 and 2021, total interest expense related to the 2026 Notes was $14.8 million and $14.7 million, respectively, with coupon interest expense of $13.5 million each, and the amortization of debt issuance costs of $1.3 million and $1.2 million, respectively. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). For the year ended December 31, 2020, total interest expense related to the 2026 Notes was $7.5 million, with coupon interest expense of $5.1 million and the amortization of debt discount and issuance costs of $2.4 million.

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

Other

In accordance with the Amended ABL Facility, the 2023 Notes, the 2026 Notes and the MARAD Debt, 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, 2022, we were in compliance with these covenants.

We previously had a credit agreement (and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America. The Credit Agreement was comprised of a term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) with a maximum availability of $175 million and had a maturity date of December 31, 2021. Concurrent with our entering into the ABL Facility on September 30, 2021, the Credit Agreement was terminated, the $28 million remaining balance of the Term Loan was repaid in full and the letters of credit issued under the Revolving Credit Facility were transferred to the ABL Facility. We had no borrowings under the Revolving Credit Facility.

We previously had a credit agreement with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) to finance the construction of the Q5000. The loan was secured by the Q5000 and its charter earnings. In January 2021, we repaid the remaining principal amount of $53.6 million.

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Scheduled maturities of our long-term debt outstanding as of December 31, 2022 are as follows (in thousands):

	2023		2026		MARAD
	Notes		Notes		Debt		Total
Less than one year	$	30,000	$	—	$	8,333	$	38,333
One to two years		—		—		8,749		8,749
Two to three years		—		—		9,186		9,186
Three to four years		—		200,000		9,644		209,644
Four to five years		—		—		5,001		5,001
Gross debt		30,000		200,000		40,913		270,913
Unamortized debt issuance costs (1)		(133)		(4,632)		(2,073)		(6,838)
Total debt		29,867		195,368		38,840		264,075
Less current maturities		(29,867)		—		(8,333)		(38,200)
Long-term debt	$	—	$	195,368	$	30,507	$	225,875

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

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

	Year Ended December 31,
	2022		2021		2020
Interest expense	$	20,176	$	23,489	$	30,538
Capitalized interest		—		—		(1,182)
Interest income		(1,226)		(288)		(825)
Net interest expense	$	18,950	$	23,201	$	28,531

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

	Year Ended December 31,
	2022		2021		2020
Current tax provision (benefit):
Domestic	$	—	$	(1,103)	$	(18,927)
Foreign		8,217		7,347		4,109
Total current	$	8,217	$	6,244	$	(14,818)
Deferred tax provision (benefit):
Domestic	$	1,167	$	(5,756)	$	3,853
Foreign		3,219		(9,446)		(7,736)
Total deferred	$	4,386	$	(15,202)	$	(3,883)
Total income tax provision (benefit)	$	12,603	$	(8,958)	$	(18,701)

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

	Year Ended December 31,
	2022		2021		2020
Domestic	$	(13,745)	$	(53,989)	$	(3,406)
Foreign		(61,436)		(16,653)		4,789
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383

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The primary differences between the income tax provision (benefit) at the U.S. statutory rate and our actual income tax provision (benefit) are as follows (dollars in thousands):

	Year Ended December 31,
	2022				2021				2020
Taxes at U.S. statutory rate	$	(15,788)	21.0	%	$	(14,835)	21.0	%	$	290	21.0	%
Foreign tax provision (benefit)		18,011	(24.0)			10,326	(14.6)			(4,517)	(326.7)
CARES Act		—	—			—	—			(7,596)	(549.2)
Subsidiary restructuring		—	—			—	—			(8,333)	(602.5)
Change in valuation allowance		8,110	(10.8)			(5,675)	8.0			1,091	78.9
Non-deductible expenses		2,366	(3.1)			1,487	(2.1)			1,184	85.6
Other		(96)	0.1			(261)	0.4			(820)	(59.3)
Income tax provision (benefit)	$	12,603	(16.8)	%	$	(8,958)	12.7	%	$	(18,701)	(1,352.2)	%

During 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.

During the year ended December 31, 2021, we released a non-U.S. valuation allowance of $5.0 million for deferred tax assets as it is more likely than not that they will be fully utilized.

On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) was enacted, extending the U.S. tax loss carryback period from three years to five years. As a result, we recognized a $7.6 million net tax benefit for the year ended December 31, 2020, consisting of an $18.9 million current tax benefit (refund received) and an $11.3 million deferred tax expense (reduction in U.S. net operating loss). Also during the year ended December 31, 2020, we migrated two of our foreign subsidiaries into our U.S. consolidated tax group. As a result, these subsidiaries are not subject to future U.S. branch profits tax and a net deferred tax benefit of $8.3 million was recognized.

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,
	2022		2021
Deferred tax liabilities:
Depreciation	$	147,302	$	137,898
Prepaid and other		1,868		1,088
Total deferred tax liabilities	$	149,170	$	138,986
Deferred tax assets:
Net operating losses	$	(53,136)	$	(56,369)
Reserves, accrued liabilities and other		(19,308)		(9,698)
Total deferred tax assets		(72,444)		(66,067)
Valuation allowance		22,157		14,047
Net deferred tax liabilities	$	98,883	$	86,966

At December 31, 2022, our U.S. net operating losses available for carryforward totaled $163.1 million, of which $74.5 million will begin to expire between 2036 and 2037, with the remaining $88.6 million not subject to expiration. Management believes it is more likely than not that these tax losses will be utilized prior to their expiration. At December 31, 2022, we had $4.2 million in gross U.S. tax credits, which included $3.0 million of foreign tax credits subject to a full valuation allowance. At December 31, 2022, our non-U.S. net operating losses totaled $69.7 million, which do not expire under local tax law.

At December 31, 2022, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries of approximately $78.9 million, which management intends to indefinitely reinvest in our international operations. Due to the enactment of the U.S. Tax Cuts and Jobs Act, repatriations of foreign earnings will generally be free of U.S. federal tax but may be subject to changes in future tax legislation that may result in taxation. It is not practicable to calculate deferred income taxes associated with these undistributed earnings given the complexities in tax laws and the manner and timing of repatriation.

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At December 31, 2022, we had unrecognized tax benefits of $0.1 million related to uncertain tax positions, which, if recognized, would have an insignificant effect on the annual effective tax rate. Due to the expiration of the statute of limitations as well as effective settlements in 2021 we released the full $0.6 million reserve related to uncertain tax positions recorded in 2020. We account for tax-related interest in interest expense and tax penalties in selling, general and administrative expenses. However, no interest has been recorded for these positions as the amount was immaterial.

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 2018 through 2022 are open to review and examination by the U.S. Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2014 through 2022.

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

The 2026 Capped Calls are subject to either adjustment or termination upon the occurrence of specified extraordinary events affecting Helix, including a merger, tender offer, nationalization, insolvency or delisting. In addition, certain events may result in a termination of the 2026 Capped Calls, including changes in law, insolvency filings and hedging disruptions. The 2026 Capped Calls are recorded at their aggregate cost of $10.6 million as a reduction to common stock in the shareholders’ equity section of our consolidated balance sheets are not recognized as either asset or liability at fair value.

Note 10 — Share Repurchase Programs

Our Board of Directors (our “Board”) previously granted us the authority 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). As of December 31, 2022, 9,547,027 shares of our common stock were available for repurchase under the program. Concurrent with the authorization of a new share repurchase program as discussed below, our Board revoked the prior authorization relating to this repurchase program.

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. The repurchase program has no set expiration date. Repurchases under the program would be made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management based on an evaluation of market conditions, stock price, liquidity and other factors. The program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. The purchase of shares by us under the program is at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled. No repurchases have been made pursuant to this program at the time of this filing.

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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, 2022
Short-term	$	395,867	$	97,533	$	124,810	$	—	$	(635)	$	617,575
Long-term		128,374		94,388		—		82,315		(49,552)		255,525
Total	$	524,241	$	191,921	$	124,810	$	82,315	$	(50,187)	$	873,100
Year ended December 31, 2021
Short-term	$	308,734	$	89,668	$	—	$	—	$	(627)	$	397,775
Long-term		207,830		47,627		—		69,348		(47,852)		276,953
Total	$	516,564	$	137,295	$	—	$	69,348	$	(48,479)	$	674,728
Year ended December 31, 2020
Short-term	$	206,812	$	117,439	$	—	$	—	$	—	$	324,251
Long-term		332,437		60,579		—		58,303		(42,015)		409,304
Total	$	539,249	$	178,018	$	—	$	58,303	$	(42,015)	$	733,555

Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 4). Contract assets as of December 31, 2022 and 2021 were $6.3 million and $0.6 million, respectively. We had no credit losses on our contract assets for the years ended December 31, 2022, 2021 and 2020.

Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to a single performance obligation and recognized ratably over the contract term and/or (ii) amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 4). Contract liabilities as of December 31, 2022 and 2021 totaled $10.0 million and $8.7 million, respectively. Revenue recognized for the years ended December 31, 2022, 2021 and 2020 included $7.4 million, $7.9 million and $11.6 million, respectively, that were included in the contract liability balance as the beginning of each period.

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

Performance Obligations

As of December 31, 2022, $846.7 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $532.6 million and $314.1 million in 2023 and 2024, 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, 2022.

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For the years 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. For the years ended December 31, 2021 and 2020, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial.

Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 4). Our deferred contract costs as of December 31, 2022 and 2021 totaled $20.4 million and $3.3 million, respectively. For the years ended December 31, 2022, 2021 and 2020, we recorded $29.7 million, $39.1 million and $35.8 million, respectively, related to amortization of deferred contract costs. There were no associated impairment losses 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):

	Year Ended December 31,
	2022			2021			2020
	Income		Shares	Income		Shares	Income		Shares
Basic:
Net income (loss) attributable to common shareholders	$	(87,784)		$	(61,538)		$	22,174
Less: Undistributed earnings allocated to participating securities		—			—			(140)
Less: Accretion of redeemable noncontrolling interests		—			(241)			(2,400)
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Diluted:
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Effect of dilutive securities:
Share-based awards other than participating securities		—	—		—	—		—	904
Undistributed earnings reallocated to participating securities		—	—		—	—		1	—
Net income (loss) available to common shareholders, diluted	$	(87,784)	151,276	$	(61,779)	150,056	$	19,635	149,897

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We had net losses for the years ended December 31, 2022 and 2021. Accordingly, our diluted EPS calculation for these periods excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):

	Year Ended December 31,
	2022	2021
Diluted shares (as reported)	151,276	150,056
Share-based awards	2,158	1,282
Total	153,434	151,338

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,
	2022	2021	2020
2022 Notes	600	2,519	6,537
2023 Notes	3,168	3,168	9,391
2026 Notes	28,676	28,676	10,891

Note 13 — Employee Benefit Plans

Defined Contribution Plan

We sponsor a defined contribution 401(k) retirement plan. Our discretionary contributions are in the form of cash and consist of a 50% match of each participant’s contribution up to 5% of the participant’s salary. Our discretionary contributions were suspended for 2021 and re-activated beginning January 2022. For the years ended December 31, 2022 and 2020, we made discretionary employer contributions of $1.5 million and $1.6 million, respectively, to the 401(k) plan.

Employee Stock Purchase Plan

As of December 31, 2022, 1.4 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 of our Board (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.

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. The Compensation Committee also determines the type of award to be made to each participant and, as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The Compensation Committee may grant stock options, restricted stock, RSUs, PSUs and cash awards. 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.

The 2005 Incentive Plan currently has 17.3 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, 2022, there were approximately 4.0 million shares available for issuance under the 2005 Incentive Plan and no incentive stock options are currently outstanding.

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The following grants of share-based awards were made in 2022 under the 2005 Incentive Plan:

			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period
January 1, 2022 (1)	RSU	1,065,705	$	3.12	33% per year over three years
January 4, 2022 (1)	PSU	1,065,705	$	4.25	100% on January 4, 2025
January 4, 2022 (2)	Restricted stock	15,775	$	3.12	100% on January 1, 2024
April 1, 2022 (2)	Restricted stock	14,710	$	4.78	100% on January 1, 2024
July 1, 2022 (2)	Restricted stock	14,867	$	3.10	100% on January 1, 2024
September 22, 2022 (3)	Restricted stock	19,328	$	4.38	100% on September 22, 2023
October 1, 2022 (2)	Restricted stock	12,796	$	3.86	100% on January 1, 2024
December 7, 2022 (2)	Restricted stock	175,882	$	5.97	100% on December 7, 2023

(1) Reflects grants to our executive officers.

(2) Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash, of which 8,013 shares granted on January 4, 2022 and 5,230 shares granted on April 1, 2022 vested upon the approval of our Board’s Compensation Committee in connection with the departure of an independent director during the second quarter 2022.

(3) Reflects restricted stock grants made to two new independent members of our Board in connection with their appointment to our Board.

In January 2023, we granted certain officers 506,436 RSUs and 489,498 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $7.38 per unit or $3.7 million. The grant date fair value of the PSUs was $9.26 per unit or $4.5 million. PSUs and RSUs issued in 2023 are payable in either cash or stock at the discretion of the Compensation Committee. Also in January 2023, we granted $5.9 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,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Shares	Fair Value (1)		Shares	Fair Value (1)		Shares	Fair Value (1)
Awards outstanding at beginning of year	853,726	$	5.62	1,176,951	$	6.61	1,173,045	$	6.81
Granted	253,358		5.33	332,841		3.59	667,752		7.06
Vested (2)	(719,456)		4.94	(656,066)		6.35	(631,498)		7.52
Forfeited	—		—	—		—	(32,348)		5.41
Awards outstanding at end of year	387,628	$	6.70	853,726	$	5.62	1,176,951	$	6.61

(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) Total fair value of restricted stock that vested during the years ended December 31, 2022, 2021 and 2020 was $2.9 million, $2.6 million and $5.4 million, respectively.

For the years ended December 31, 2022, 2021 and 2020, $2.5 million, $3.3 million and $4.2 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost associated with unvested restricted stock at December 31, 2022 totaled approximately $1.2 million. The weighted average vesting period related to unvested restricted stock at December 31, 2022 was approximately 0.6 years.

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PSU Awards

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

The following table summarizes information about our PSU awards:

	Year Ended December 31,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)		Units	Fair Value (1)
PSU awards outstanding at beginning of year	1,381,469	$	8.34	1,297,126	$	9.99	1,565,044	$	10.17
Granted	1,065,705		4.25	452,381		5.33	369,938		13.15
Vested	(559,150)		7.60	(368,038)		10.44	(589,335)		12.64
Forfeited	—		—	—		—	(48,521)		7.60
PSU awards outstanding at end of year	1,888,024	$	6.25	1,381,469	$	8.34	1,297,126	$	9.99

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

For the years ended December 31, 2022, 2021 and 2020, $4.8 million, $4.1 million and $4.0 million, respectively, were recognized as share-based compensation related to PSUs. Future compensation cost associated with unvested PSU awards at December 31, 2022 totaled approximately $5.2 million. The weighted average vesting period related to unvested PSUs at December 31, 2022 was approximately 1.4 year. In January 2023, 369,938 PSUs granted in 2020 vested at 77%, representing 285,778 shares of our common stock with a total market value of $3.6 million. In January 2022, 559,150 PSUs granted in 2019 vested at 157%, representing 876,469 shares of our common stock with a total market value of $3.2 million. In January 2021, 368,038 PSUs granted in 2018 vested at 200%, representing 736,075 shares of our common stock with a total market value of $3.1 million.

RSU Awards

Our RSUs granted beginning 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and have been accounted for as liability awards.

The following table summarizes information about our RSU awards:

	Year Ended December 31,
	2022			2021
		Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)
RSU awards outstanding at beginning of year	452,381	$	4.20	—	$	—
Granted	1,065,705		3.12	452,381		4.20
Vested	(150,792)		4.20	—		—
RSU awards outstanding at end of year	1,367,294	$	3.36	452,381	$	4.20

(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.

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Compensation cost recognized for the years ended December 31, 2022 and 2021 was $3.7 million and $0.5 million, respectively, which is reflected in the liability balance at December 31, 2022 and 2021 for the fair value of RSUs that vested in January 2023 and 2022, respectively. Future compensation cost based on the fair value of unvested RSUs at December 31, 2022 totaled approximately $6.4 million. The weighted average vesting period related to unvested RSUs at December 31, 2022 was approximately 1.8 years.

Cash Awards

In 2022, 2021 and 2020, we granted $5.5 million, $3.5 million and $4.7 million, respectively, of fixed value cash awards 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, 2022, 2021 and 2020, we recognized compensation costs of $4.3 million and $4.0 million and $4.4 million, respectively, which reflected the cash payouts made in January 2023, 2022 and 2021, respectively.

Note 14 — Business Segment Information

Through the second quarter 2022, we have three reportable business segments: Well Intervention, Robotics and Production Facilities. Beginning in the third quarter 2022 as a result of the Alliance acquisition (Note 3), we formed a new reportable business segment: Shallow Water Abandonment, which includes the assets, liabilities and operating results of Helix Alliance. All material intercompany transactions between the segments have been eliminated.

Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention segment for financial reporting purposes. Our Well Intervention segment provides services enabling our customers to safely access offshore wells for the purpose of performing production enhancement or decommissioning operations primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa, with expansion into Asia Pacific. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and the Siem Helix 1 and Siem Helix 2 chartered vessels. Our well intervention equipment includes intervention systems, some of which we provide on a stand-alone basis.

Our Robotics segment provides trenching, seabed clearance, offshore construction and IRM services to both the oil and gas and the renewable energy markets globally. Additionally, our Robotics services are used in and complement our well intervention services. Our Robotics segment includes ROVs, trenchers, the IROV boulder grab and robotics support vessels under term charters as well as spot vessels as needed.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment operates a diversified fleet of marine assets including liftboats, OSVs, DSVs, a heavy lift derrick barge, a crew boat and P&A and coiled tubing systems.

Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties (Note 15).

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

	Year Ended December 31,
	2022		2021		2020
Net revenues —
Well Intervention	$	524,241	$	516,564	$	539,249
Robotics		191,921		137,295		178,018
Shallow Water Abandonment		124,810		—		—
Production Facilities		82,315		69,348		58,303
Intercompany eliminations		(50,187)		(48,479)		(42,015)
Total	$	873,100	$	674,728	$	733,555
Income (loss) from operations —
Well Intervention	$	(53,056)	$	(35,882)	$	26,855
Robotics		29,981		5,762		13,755
Shallow Water Abandonment		22,184		—		—
Production Facilities		27,201		22,906		15,975
Segment operating income (loss)		26,310		(7,214)		56,585
Goodwill impairment (1)		—		—		(6,689)
Change in fair value of contingent consideration		(16,054)		—		—
Corporate, eliminations and other		(55,111)		(41,473)		(36,871)
Total	$	(44,855)	$	(48,687)	$	13,025
Net interest expense		(18,950)		(23,201)		(28,531)
Other non-operating income (expense), net		(11,376)		1,246		16,889
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383
Capital expenditures —
Well Intervention	$	17,617	$	2,349	$	19,523
Robotics		15,603		120		257
Shallow Water Abandonment		532		—		—
Production Facilities		(1,424)		6,770		—
Corporate, eliminations and other		1,176		(917)		464
Total	$	33,504	$	8,322	$	20,244
Depreciation and amortization —
Well Intervention	$	103,952	$	107,551	$	101,756
Robotics		12,209		15,158		15,952
Shallow Water Abandonment		8,172		—		—
Production Facilities		18,520		19,465		15,652
Corporate and eliminations		(167)		(660)		349
Total	$	142,686	$	141,514	$	133,709

(1) Relates to the impairment of the entire STL goodwill balance (Note 3).

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,
	2022		2021		2020
Well Intervention	$	16,545	$	21,521	$	15,039
Robotics		33,642		26,958		26,976
Total	$	50,187	$	48,479	$	42,015

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

	Year Ended December 31,
	2022		2021		2020
U.S.	$	447,205	$	232,661	$	304,563
U.K.		166,980		100,154		133,005
Brazil		81,940		154,326		208,565
West Africa		87,488		126,856		41,840
Other		89,487		60,731		45,582
Total	$	873,100	$	674,728	$	733,555

Our operational assets work in various regions around the world such as the Gulf of Mexico, Brazil, the North Sea, Asia Pacific and West Africa. The following table provides our property and equipment, net of accumulated depreciation, by individually significant geographic location where those assets are based (in thousands):

	December 31,
	2022		2021
U.S.	$	780,803	$	693,062
U.K. (1)		625,001		713,385
Brazil (2)		235,811		251,194
Other		—		4
Total	$	1,641,615	$	1,657,645

(1) Includes the Q7000 and certain other assets that are based in the U.K. but have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

(2) Includes the equipment on the Siem Helix 1 chartered vessel and certain other assets that are based in Brazil but are have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

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

	December 31,
	2022		2021
Well Intervention	$	1,796,269	$	2,012,214
Robotics		192,694		96,249
Shallow Water Abandonment		206,944		—
Production Facilities		136,382		119,004
Corporate and other		57,049		98,561
Total	$	2,389,338	$	2,326,028

Note 15 — Asset Retirement Obligations

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

	2022		2021		2020
AROs at January 1,	$	29,658	$	30,913	$	28,258
Liability incurred during the period		23,601		—		—
Revisions in estimates		(3,285)		(2,631)		—
Accretion expense		1,982		1,376		2,655
AROs at December 31,	$	51,956	$	29,658	$	30,913

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Note 16 — Commitments and Contingencies and Other Matters

Commitments

We have long-term charter agreements with Siem Offshore AS for the Siem Helix 1 and Siem Helix 2 vessels. During the first quarter 2022, the charter agreements for the Siem Helix 1 and the Siem Helix 2 were extended to February 2025 and February 2027, respectively, with further options to extend. We have time charter agreements for the Grand Canyon II and Grand Canyon III vessels, which were extended during the third quarter 2022 to December 2027 and May 2028, respectively, with further options to renew. During the first quarter 2022, we executed short-term time charter agreements for the Horizon Enabler in the North Sea and the Shelia Bordelon in the Gulf of Mexico. During the third quarter 2022, the charter agreement for the Shelia Bordelon was extended to June 2024. In January 2023, we entered into a three-year charter agreement for the Glomar Wave in the North Sea with options to extend.

Contingencies and Claims

Our contingent consideration liability resulting from the Alliance acquisition is subject to risk as a result of changes in our probability weighted discounted cash flow model, which is based on internal forecasts, and changes in weighted average discount rate, which is derived from market data.

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

Litigation

We are involved in various legal proceedings, some involving claims under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as the Jones Act). In addition, from time to time we receive other claims, such as contract and employment-related disputes, in the normal course of business.

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

Note 17 — Statement of Cash Flow Information

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

	Year Ended December 31,
	2022		2021		2020
Interest paid	$	18,267	$	20,719	$	15,943
Income taxes paid (1)		9,516		8,310		7,434

(1) Exclusive of income tax refunds. During the years ended December 31, 2022 and 2021, we received refunds related to the CARES Act of $1.1 million and $18.9 million, respectively.

Our capital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, 2022 and 2021, these non-cash capital additions totaled $0.4 million and $0.3 million, respectively.

Non-cash investing activities for the year ended December 31, 2022 also included $26.7 million in estimated fair value of contingent earn-out consideration as of July 1, 2022, the date of the Alliance acquisition (Note 3).

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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, 2022 (in thousands):

	Allowance for		Deferred Tax Asset
	Credit Losses		Valuation Allowance
Balance at December 31, 2019	$	—	$	18,631
Additions (reductions) (1)		2,684		—
Adjustments (2)		785		1,091
Balance at December 31, 2020		3,469		19,722
Additions (reductions) (1)		(146)		—
Write-offs (3)		(1,846)
Adjustments (4)		—		(5,675)
Balance at December 31, 2021		1,477		14,047
Additions (reductions) (1)		800		—
Adjustments (5)		—		8,110
Balance at December 31, 2022	$	2,277	$	22,157

(1) Additions (reductions) in allowance for credit losses reflect credit loss reserves (releases) during the respective years, including a $1.7 million credit loss reserve in 2020 related to a receivable in our Robotics segment. Additions during 2022 primarily reflected adjustments to the allowance for credit losses due to increases in our expected credit losses as a result of the Alliance acquisition.

(2) The adjustment in allowance for credit losses reflects provision for current expected credit losses upon the adoption of ASU No. 2016-13 on January 1, 2020.

(3) The write-offs of allowance for credit losses reflect certain receivables related to our Robotics segment that were previously reserved and subsequently deemed to be uncollectible.

(4) The decrease in valuation allowance primarily relates to the valuation allowance release for certain of our U.K. operations.

(5) The increase in valuation allowance relates to current year activity and the related change in unrealizable net deferred tax assets.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for credit losses as well as the adoption of ASU No. 2016-13. 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.

The following table sets forth our assets and liabilities that are measured at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value at December 31, 2022
	Level 1		Level 2		Level 3		Total
Liabilities:
Contingent consideration		—		—		42,754		42,754

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Contingent consideration liability related to the Alliance acquisition (Note 3) is measured at fair value using Level 3 unobservable inputs at the end of each reporting period. The fair value of the estimated contingent consideration is determined based on our evaluation of the probability and amount of earnout that may be achieved based on expected future performance of Helix Alliance. The Monte Carlo simulation model is used to calculate the estimated earnout payment, which is then discounted to present value based on the expected payment date of the contingent consideration. The weighted-average volatility was 47.5% and the weighted average discount rate was estimated to be 8.0% at December 31, 2022. The changes in the fair value of contingent consideration are as follows:

	2022
Balance at July 1,	$	26,700
Change in fair value		16,054
Balance at December 31,	$	42,754

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

	December 31, 2022				December 31, 2021
	Principal		Fair		Principal		Fair
	Amount (1)		Value (2)		Amount (1)		Value (2)
MARAD Debt (matures February 2027)	$	40,913	$	40,940	$	48,850	$	52,481
2022 Notes (matured May 2022)		—		—		35,000		34,794
2023 Notes (mature September 2023)		30,000		31,149		30,000		29,054
2026 Notes (mature February 2026)		200,000		277,014		200,000		200,562
Total debt	$	270,913	$	349,103	$	313,850	$	316,891

(1) Principal amount includes current maturities and excludes any related unamortized debt issuance costs. See Note 7 for additional disclosures on our long-term debt.

(2) The estimated fair value of the 2022 Notes, the 2023 Notes and the 2026 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.

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, 2022 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.

84

As disclosed in Note 3 to the audited consolidated financial statements, we acquired Alliance on July 1, 2022. Helix Alliance’s total revenues constituted approximately 14.3% of total consolidated revenues as shown on our consolidated statement of operations for the year ended December 31, 2022. Helix Alliance’s total assets constituted approximately 8.7% of total consolidated assets as shown on our consolidated balance sheet as of December 31, 2022. We excluded Helix Alliance’s disclosure controls and procedures that are subsumed by its internal control over financial reporting from the scope of management's assessment of the effectiveness of our disclosure controls and procedures. This exclusion is in accordance with the guidance issued by the Staff of the Securities and Exchange Commission that an assessment of recent business combinations may be omitted from management's assessment of internal control over financial reporting for one year following the acquisition. We are in the process of implementing financial reporting controls and procedures at Helix Alliance as part of our ongoing integration activities. Helix Alliance currently maintains separate accounting systems and is expected to convert to Helix’s accounting systems no later than June 30, 2023. The consolidated financial statements presented in this Annual Report on Form 10-K were prepared using information obtained from these separate accounting systems.

(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, 2022. 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, 2022, our internal control over financial reporting was effective.

The effectiveness of our internal control over financial reporting as of December 31, 2022 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.

(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 2022 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

Not applicable.

85

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 2023 Annual Meeting of Shareholders to be held on May 17, 2023. 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 at our website www.helixesg.com under Corporate Governance (which can be accessed by clicking the “For the Investor” tab and then the “Governance” tab). 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

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 2023 Annual Meeting of Shareholders to be held on May 17, 2023.

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

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 2023 Annual Meeting of Shareholders to be held on May 17, 2023.

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

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 2023 Annual Meeting of Shareholders to be held on May 17, 2023.

Item 14. Principal Accounting Fees and Services

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 2023 Annual Meeting of Shareholders to be held on May 17, 2023.

86

PART IV

Item 15. Exhibit and Financial Statement Schedules

(1) Financial Statements

The following financial statements included on pages 47 through 84 in this Annual Report are for the fiscal year ended December 31, 2022.

● 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, 2022 and 2021

● Consolidated Statements of Operations for the Years Ended December 31, 2022, 2021 and 2020

● Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2022, 2021 and 2020

● Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2022, 2021 and 2020

● Consolidated Statements of Cash Flows for the Years Ended December 31, 2022, 2021 and 2020

● 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)
4.1	Description of Securities Registered Pursuant to Section 12(g) of the Exchange Act of 1934.	Exhibit 4.1 to the Annual Report on Form 10-K filed on February 25, 2021 (001-32936)
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)

87

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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	Credit Agreement dated June 19, 2013 by and among Helix Energy Solutions Group, Inc., as borrower, Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, and other lender parties named thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on June 19, 2013 (001-32936)
4.16	Amendment No. 1 to the Credit Agreement, dated as of May 13, 2015, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on May 14, 2015 (001-32936)
4.17	Amendment No. 2 to the Credit Agreement, dated as of January 19, 2016, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on January 25, 2016 (001-32936)
4.18	Amendment No. 3 to the Credit Agreement, dated as of February 9, 2016, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on February 11, 2016 (001-32936)

88

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.19	Amended and Restated Credit Agreement dated June 30, 2017, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on June 30, 2017 (001-32936)
4.20	Amendment No. 1 to the Amendment and Restated Credit Agreement, dated as of January 18, 2019, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on January 22, 2019 (001-32936)
4.21	Amendment No. 2 to Amended and Restated Credit Agreement, dated as of June 28, 2019, by and among Helix Energy Solutions Group, Inc., as borrower, the guarantors listed therein, and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on June 28, 2019 (001-32936)
4.22	Amendment No. 3 to Amended and Restated Credit Agreement, dated as of December 30, 2020, by and among Helix, certain of its subsidiaries as guarantors, the lenders thereunder, and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer.	Exhibit 4.1 to the Current Report on Form 8-K filed on December 31, 2020 (001-32936)
4.23	Credit Agreement dated September 26, 2014, by and among Helix Q5000 Holdings S.à r.l., Helix Vessel Finance S.à r.l. and Nordea Bank Finland PLC, London Branch as administrative agent and collateral agent, together with the other lenders party thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on September 30, 2014 (001-32936)
4.24	First Amendment to the Credit Agreement dated as of September 26, 2014, by and among Helix Q5000 Holdings S.à r.l., Helix Vessel Finance S.à r.l. and Nordea Bank ABP, New York Branch and the lender parties thereto.	Exhibit 4.1 to the Current Report on Form 8-K filed on March 12, 2020 (001-32936)
4.25	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)
4.26	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)
4.27	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)
4.28	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)

89

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.29	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)
4.30	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)
4.31	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)
4.32	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.	Filed herewith
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, 2019.	Annex A to the Definitive Proxy Statement filed on April 2, 2019 (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)

90

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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)
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 Purchase Agreement, dated as of May 16, 2022, by and among Helix Alliance Decom, LLC, Stephen J. Williams and Helix Energy Solutions Group, Inc. (solely for purposes of Sections 1.05(d) and 6.14).	Exhibit 2.1 to the Current Report on Form 8-K filed on July 1, 2022 (001-32936)

91

Exhibit Number	Description	Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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)
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
99.1	Unaudited Pro Forma Condensed Combined Financial Information of Helix for the year ended December 31, 2022.	Filed herewith
101.INS	XBRL Instance Document.	The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
101.SCH	Inline XBRL Taxonomy Extension Schema Document.	Filed herewith
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.	Filed herewith
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.	Filed herewith
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.	Filed herewith
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.	Filed herewith
104	Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).	Filed herewith

*Management contracts or compensatory plans or arrangements

Item 16. Form 10-K Summary

None.

92

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 23, 2023

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 23, 2023
Owen Kratz	(principal executive officer)
/s/  ERIK STAFFELDT	Executive Vice President and Chief Financial Officer	February 23, 2023
Erik Staffeldt	(principal financial officer)
/s/  BRENT ARRIAGA	Chief Accounting Officer and Corporate Controller	February 23, 2023
Brent Arriaga	(principal accounting officer)
/s/  AMERINO GATTI	Director	February 23, 2023
Amerino Gatti
/s/  DIANA GLASSMAN	Director	February 23, 2023
Diana Glassman
/s/  PAULA HARRIS	Director	February 23, 2023
Paula Harris
/s/  T. MITCH LITTLE	Director	February 23, 2023
T. Mitch Little
/s/  JOHN V. LOVOI	Director	February 23, 2023
John V. Lovoi
/s/  AMY H. NELSON	Director	February 23, 2023
Amy H. Nelson
/s/  WILLIAM L. TRANSIER	Director	February 23, 2023
William L. Transier

93

EX-4.32

EXHIBIT 4.32

January 25, 2023

Helix Energy Solutions Group, Inc.

3505 W. Sam Houston Pkwy N, Suite 400

Houston, Texas 77043

Attention: Erik Staffeldt

RE: LOAN, SECURITY AND GUARANTY AGREEMENT dated as of September 30, 2021 (as amended, modified or supplemented from time to time, the “Loan Agreement”), among HELIX ENERGY SOLUTIONS GROUP, INC., a Minnesota corporation (“Helix”), HELIX WELL OPS INC., a Texas corporation (“Well Ops”), HELIX ROBOTICS SOLUTIONS, INC., a Texas corporation (“Robotics”), DEEPWATER ABANDONMENT ALTERNATIVES, INC., a Texas corporation (“Deepwater”), ALLIANCE OFFSHORE, L.L.C., a Louisiana limited liability company (“Alliance Offshore”), TRITON DIVING SERVICES LLC, a Louisiana limited liability company (“Triton”), ALLIANCE ENERGY SERVICES LLC, a Louisiana limited liability company (“Alliance Energy” and together with Helix, Well Ops, Robotics, Alliance Offshore and Triton, each a “U.S. Borrower” and collectively, “U.S. Borrowers”), HELIX WELL OPS (U.K.) LIMITED, a company incorporated in Scotland with company number SC231293 and having its registered office address at 13 Queen’s Road, Aberdeen, AB15 4YL (“Well Ops U.K.”), HELIX ROBOTICS SOLUTIONS LIMITED, a company incorporated in Scotland with number SC210524 and having its registered office address at 13 Queen’s Road, Aberdeen, AB15 4YL (“Robotics U.K.”, and together with Well Ops U.K., each a “U.K. Borrower” and collectively, “U.K. Borrowers”; and the U.K. Borrowers and U.S. Borrowers collectively, the “Borrowers”), the Guarantors named therein, the financial institutions party to the Loan Agreement from time to time as Lenders, and BANK OF AMERICA, N.A., a national banking association (“Bank of America”), as agent and as security trustee for the Lenders (in such capacity, “Agent”).  Unless otherwise defined herein, all capitalized terms used herein shall have the respective meanings assigned to such terms in the Loan Agreement.

Ladies and Gentlemen:

Obligors have requested that the Issuing Banks reallocate their subdivision of the Letter of Credit Subline.  The Issuing Banks have agreed to such reallocation on the terms of this Letter Agreement.

1.Letter of Credit Subline.  Clause (a) of the definition of “Letter of Credit Subline” set forth in Section 1.1 of the Loan Agreement is hereby amended as follows:

“(a) $10,000,000 (which is subdivided $5,500,000 for Bank of America and $4,500,000 for Wells Fargo Bank, National Association) and”.

2.Conditions to Effectiveness.  This Letter Agreement shall become effective upon the Agent’s receipt of duly executed counterparts of this Letter Agreement from the Obligors, the Agent and the Required Lenders.

3.Ratification of Loan Documents and Collateral. Except as modified by this Letter Agreement, each Obligor hereby ratifies, reaffirms and agrees that each of the Loan Documents, and the

Liens and security interests created thereby in favor of the Agent, for the benefit of the Lenders, in the Collateral, are and will remain in full force and effect and binding on such Obligor, and are enforceable in accordance with their respective terms and applicable law.  Without limitation to the foregoing, the Borrowers hereby ratify and confirm the Loan Agreement and all of their debts and obligations to the Agent and the Lenders thereunder, and each Guarantor hereby ratifies and confirms its Guaranty and all of its debts and obligations to the Agent and the Lenders thereunder.

4.Miscellaneous.

(a)The Borrowers agree to pay promptly after demand all reasonable and documented fees and expenses incurred by the Agent (including reasonable fees and expenses of counsel to the Agent) in connection with the preparation, negotiation and execution of this Letter Agreement and all related documents in the manner set forth in the Loan Agreement.

(b)This Letter Agreement shall be governed by, and construed in accordance with, the laws of the State of NEW YORK.

(c)This Letter Agreement may be executed in counterparts, and all parties need not execute the same counterpart; however, no party shall be bound by this Letter Agreement unless and until a counterpart hereof has been executed by the Obligors, the Agent and the Required Lenders. Delivery of an executed signature page of this Letter Agreement by fax or other electronic transmission (e.g., “pdf”) shall be effective as delivery of a manually executed counterpart hereof.

(d)This Letter Agreement constitutes a “Loan Document” as such term is defined in the Loan Agreement, and all of the terms and provisions of the Loan Agreement relating to Loan Documents shall apply hereto.

Please evidence your agreement to this letter by executing a counterpart hereof where indicated and returning a fully executed counterpart.

[Signature Pages Follow]

AGENT AND LENDERS:
BANK OF AMERICA, N.A., as Agent, an Issuing Bank and a U.S. Lender
By:	/s/ Alexandra Mills
Name:	Alexandra Mills
Title:	Vice President

BANK OF AMERICA, N.A. (acting through its London Branch), as a U.K. Lender
By:	/s/ Alexandra Mills
Name:	Alexandra Mills
Title:	Vice President

Signature Page to Letter Agreement – Helix

WELLS FARGO BANK, NATIONAL ASSOCIATION, as an Issuing Bank and a U.S. Lender
By:	/s/ Kathryn Williams
Name:	Kathryn Williams
Title:	Director

WELLS FARGO BANK, NATIONAL ASSOCIATION (acting through its London Branch), as a U.K. Lender
By:	/s/ N. B. Hogg
Name:	N. B. Hogg
Title:	Authorised Signatory

Signature Page to Letter Agreement – Helix

BORROWERS:

HELIX ENERGY SOLUTIONS GROUP, INC.
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Executive Vice President and Chief Financial Officer

HELIX WELL OPS INC.
By:	/s/ Ken Neikirk
	Name:	Ken Neikirk
	Title:	Vice President and Secretary

HELIX ROBOTICS SOLUTIONS, INC.
By:	/s/ Ken Neikirk
	Name:	Ken Neikirk
	Title:	Vice President and Secretary

DEEPWATER ABANDONMENT ALTERNATIVES, INC.
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Vice President and Treasurer

HELIX WELL OPS (U.K.) LIMITED
By:	/s/ Ken Neikirk
	Name:	Ken Neikirk
	Title:	Director

Signature Page to Letter Agreement – Helix

HELIX ROBOTICS SOLUTIONS LIMITED
By:	/s/ Ken Neikirk
	Name:	Ken Neikirk
	Title:	Director

ALLIANCE OFFSHORE LLC
By:	Alliance ‎Maritime Holdings, LLC, its sole member
By:	Alliance-Triton GOM Holdings LLC, its sole member
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

TRITON DIVING SERVICES LLC
By:	Whitney Clare Holdings, LLC, its sole member
By:	Alliance ‎Special Ventures Holdings, LLC, its sole member
By:	Alliance-Triton GOM Holdings LLC, its sole member
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

ALLIANCE ENERGY SERVICES LLC
By:	Alliance Industry Holdings, LLC, its sole member
By:	Alliance-Triton GOM Holdings LLC, its sole member
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

Signature Page to Letter Agreement – Helix

GUARANTORS:

HELIX ROBOTICS SOLUTIONS INTERNATIONAL CORP.
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Vice President and Treasurer

HELIX ENERGY SOLUTIONS (U.K.) LIMITED
By:	/s/ Ken Neikirk
	Name:	Ken Neikirk
	Title:	Director

KOMMANDOR LLC
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Vice President and Treasurer

HH
HELIX SUBSEA CONSTRUCTION, INC.
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Vice President and Treasurer

HELIX ALLIANCE DECOM, LLC
By:	/s/ Erik Staffeldt
	Name:	Erik Staffeldt
	Title:	Vice President and Treasurer

Signature Page to Letter Agreement – Helix

ALLIANCE-TRITON GOM HOLDINGS LLC
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

ALLIANCE MARITIME HOLDINGS, LLC WHITNEY CLARE HOLDINGS, LLC ALLIANCE INDUSTRY HOLDINGS, LLC
By:	Alliance-Triton GOM Holdings LLC, its sole member
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

ALLIANCE SPECIAL VENTURES HOLDINGS LLC
By:	Whitney Clare Holdings, ‎LLC, its sole member
By:	Alliance-Triton GOM Holdings LLC, its sole member
By:	Helix Alliance Decom, LLC, its sole member
	By:	/s/ Erik Staffeldt
		Name:	Erik Staffeldt
		Title:	Vice President and Treasurer

Signature Page to Letter Agreement – Helix

EX-21.1

EXHIBIT 21.1

Name of Subsidiary	Jurisdiction of Formation
AES-EOT Equipment Holdings, LLC	Louisiana
Alliance Energy Services, LLC	Louisiana
Alliance Industry Holdings, LLC	Louisiana
Alliance LB Dallas Holdings, LLC	Louisiana
Alliance LB Miami Holdings, LLC	Louisiana
Alliance Liftboats, LLC	Louisiana
Alliance Maritime Holdings, LLC	Louisiana
Alliance Offshore, LLC	Louisiana
Alliance Special Ventures Holdings, LLC	Louisiana
Alliance-Triton GOM Holdings, LLC	Delaware
Alliance Vessel Leasing, LLC	Louisiana
Cal Dive I-Title XI, Inc.	Texas
Deepwater Abandonment Alternatives, Inc.	Texas
Dickson Road Investments, LLC	Louisiana
Energy Resource Technology (U.K.) Limited	Scotland
ERT Camelot Limited	Scotland
Explorer DSV Holdings, LLC	Louisiana
Heavy Lift Holdings, LLC	Louisiana
Hedron Holdings, LLC	Louisiana
Helix Alliance Decom, LLC	Delaware
Helix do Brasil Serviços de Petróleo Ltda.	Brazil
Helix Energy Solutions (Guyana) Inc.	Guyana
Helix Energy Solutions (U.K.) Limited	Scotland
Helix Offshore Crewing Services Limited	Scotland
Helix Offshore Crewing Services PTE. Ltd.	Singapore
Helix Offshore Energy Services (Australia) Pty Ltd.	Australia
Helix Offshore Holdings Ltd.	Delaware
Helix Offshore International Holdings S.à r.l.	Grand Duchy of Luxembourg
Helix Offshore International, Inc.	Texas
Helix Offshore Ltd.	Cayman Islands
Helix Offshore Services A.S.	Norway
Helix Offshore Services Limited	Scotland
Helix Oil & Gas (U.K.) Limited	Scotland
Helix Property Corp.	Texas
Helix Q5000 Holdings LLC	Delaware
Helix Robotics Solutions, Inc.	Texas
Helix Robotics Solutions International Corp.	Texas
Helix Robotics Solutions Limited	Scotland
Helix Subsea Construction, Inc.	Delaware
Helix Well Ops Inc.	Texas
Helix Well Ops (U.K.) Limited	Scotland
Independence Hub, LLC (20% owned)	Delaware
Kommandor LLC	Delaware
Offshore Well Services, S. de R.L. de C.V.	Mexico
Patriot DSV Holdings, LLC	Louisiana
Subsea Technologies Group Limited	Scotland
Triton Diving Services, LLC	Louisiana
Whitney Clare Holdings, LLC	Louisiana
Whitney Liftboats, LLC	Louisiana
Whitney Maritime Holdings, LLC	Louisiana

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statements (No. 333-268049) on Form S-3ASR and (Nos. 333-262174, 333-183532, 333-126248 and 333-58817) on Form S-8 of our reports dated February 23, 2023, with respect to the consolidated financial statements of Helix Energy Solutions Group, Inc. and the effectiveness of internal control over financial reporting.

/s/ KPMG LLP

Houston, Texas

February 23, 2023

EX-31.1

EXHIBIT 31.1

SECTION 302 CERTIFICATION

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

1. I have reviewed this Annual Report on Form 10-K of Helix Energy Solutions Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 23, 2023

/s/ Owen Kratz

Owen Kratz

President and Chief Executive Officer

EX-31.2

EXHBIT 31.2

SECTION 302 CERTIFICATION

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

1. I have reviewed this Annual Report on Form 10-K of Helix Energy Solutions Group, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

(a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

(a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:  February 23, 2023

/s/ Erik Staffeldt

Erik Staffeldt

Executive Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

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

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

In connection with the Annual Report of Helix Energy Solutions Group, Inc. (“Helix”) on Form 10-K for the year ended December 31, 2022, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), Owen Kratz, as President and Chief Executive Officer, and Erik Staffeldt, as Executive Vice President and Chief Financial Officer, each hereby certifies, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of Helix.

Date: February 23, 2023

/s/ Owen Kratz

Owen Kratz

President and Chief Executive Officer

Date: February 23, 2023

/s/ Erik Staffeldt

Erik Staffeldt

Executive Vice President and Chief Financial Officer

EX-99.1

EXHIBIT 99.1

UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

On July 1, 2022, Helix Energy Solutions Group, Inc. (“Helix”) completed the previously announced acquisition of the Alliance group of companies (collectively, “Alliance”), pursuant to which Helix purchased all of the equity interests of Alliance (the “Acquisition”). The Acquisition was made pursuant to an Equity Purchase Agreement (the “Purchase Agreement”), dated May 16, 2022, by and among Helix Alliance Decom, LLC, a Delaware ‎limited liability company (“Purchaser”), a wholly owned subsidiary of Helix, Stephen J. Williams, an individual resident of the State ‎of Louisiana (“Seller”), and Helix.

The unaudited pro forma combined financial information has been derived from:

● audited consolidated financial statements and related notes of Helix as of and for the year ended December 31, 2022, as included in Helix’s Annual Report on Form 10-K to which this Exhibit 99.1 is attached; and

● interim unaudited condensed combined consolidated financial statements and related notes of Alliance Maritime Holdings, LLC and related entities as of and for the six months ended June 30, 2022, included as Exhibit 99.2 in Helix’s Current Report on Form 8-K/A filed with the SEC on September 16, 2022.

The unaudited pro forma condensed combined financial information should be read in conjunction with the historical financial statements of Helix and Alliance as well as the accompanying notes to the unaudited pro forma condensed combined financial information.

The pro forma adjustments are based on available information and certain assumptions that management believes are reasonable. The unaudited pro forma condensed combined financial information 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 dates presented, nor should it be considered indicative of Helix’s future consolidated results of operations.

The unaudited pro forma condensed combined financial information does not reflect any cost savings, operating synergies or revenue enhancements that the combined entity may achieve as a result of the acquisition or the costs necessary to achieve any such cost savings, operating synergies or revenue enhancements.

UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF OPERATIONS

FOR THE YEAR ENDED DECEMBER 31, 2022

(in thousands, except per share amounts)

	Historical				Pro Forma
	Year Ended		Six Months Ended		Transaction
	December 31, 2022		June 30, 2022		Accounting			Pro Forma
	Helix		Alliance		Adjustments		Notes	Combined
Net revenues	$	873,100	$	79,737	$	—		$	952,837
Cost of sales		822,484		65,022		1,594	A		889,100
Gross profit (loss)		50,616		14,715		(1,594)			63,737
Gain on disposition of assets, net		—		15		—			15
Acquisition and integration costs		(2,664)		—		—			(2,664)
Change in fair value of contingent consideration		(16,054)		—		—			(16,054)
Selling, general and administrative expenses		(76,753)		(2,505)		—			(79,258)
Income (loss) from operations		(44,855)		12,225		(1,594)			(34,224)
Equity in earnings of investment		8,262		—		—			8,262
Net interest expense		(18,950)		(4,453)		4,453	B		(18,950)
Other expense, net		(23,330)		(104)		(145)	C		(23,579)
Royalty income and other		3,692		—		—			3,692
Income (loss) before income taxes		(75,181)		7,668		2,714			(64,799)
Income tax provision		12,603		—		2,284	D		14,887
Net income (loss)	$	(87,784)	$	7,668	$	430		$	(79,686)
Loss per share of common stock:
Basic	$	(0.58)						$	(0.53)
Diluted	$	(0.58)						$	(0.53)
Weighted average common shares outstanding:
Basic		151,276							151,276
Diluted		151,276							151,276

NOTES TO THE UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL INFORMATION

Note 1 — Basis of Presentation

The unaudited pro forma condensed combined financial information and related notes have been prepared in accordance with Article 11 of Regulation S-X as amended and are based on the historical consolidated financial statements of Helix and the historical combined financial statements of Alliance as adjusted to give effect to the Acquisition. An unaudited pro forma condensed combined balance sheet is not presented because the acquisition is reflected in Helix’s historical condensed consolidated balance sheet as of December 31,2022. The unaudited pro forma condensed combined statement of operations gives effect to the Acquisition as if it had been consummated on January 1, 2022 by combining Helix’s results of operations for the year ended December 31, 2022 and Alliance’s results of operations for the six months ended June 30, 2022. Alliance’s results of operations for the six months ended December 31, 2022 are reflected in Helix’s historical condensed consolidated statement of operations for the year ended December 31, 2022.

The unaudited pro forma condensed combined financial information has been prepared using the acquisition method of accounting in accordance with Accounting Standards Codification Topic 805, Business Combinations, (“ASC 805”). The purchase price allocation and related adjustments reflected in the unaudited pro forma condensed combined financial information are subject to revision as acquisition-date fair value analyses are completed and if additional information about facts and circumstances that existed at the acquisition date becomes available. The purchase price consideration, as well as the estimated fair values of the assets acquired and liabilities assumed, will be finalized as soon as practicable, but no later than one year from the closing of the Acquisition.

Management believes that the assumptions used provide a reasonable basis for presenting the significant effects of the Acquisition, and that the pro forma adjustments in the unaudited pro forma condensed combined financial information give appropriate effect to those assumptions.

Note 2 — Transaction Accounting Adjustments

The following describes the transaction accounting adjustments related to the Acquisition that are necessary to account for the adjustment and have been included in the unaudited pro forma condensed combined financial information. The pro forma adjustments are based on preliminary estimates and valuations that could change significantly as additional information is obtained.

A. Represents adjustments to increase depreciation and amortization related to the preliminary fair value estimates of acquired property and equipment and intangible assets and to accrue pre-acquisition repair costs for which the payment was made after the Acquisition (in thousands):

	Six Months Ended
	June 30, 2022
Depreciation expense based on preliminary fair value of acquired property and equipment	$	7,218
Less: historical depreciation expense of property and equipment of Alliance		(5,809)
Add: amortization expense based on preliminary fair value of acquired intangible assets		75
Add: post-acquisition payment for pre-acquisition repair costs		110
Transaction accounting adjustment	$	1,594

B. Represents the elimination of historical interest expense on long-term debt of Alliance that was paid off as part of the Acquisition.

C. Represents the write-off of various non-trade receivables.

D. Represents the income tax impact calculated at a statutory rate of 22% based on Alliance earnings for the six months ended June 30, 2022 and the transaction accounting adjustments.

XML

Document And Entity Information - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2022

Feb. 17, 2023

Jun. 30, 2022

Document And Entity Information [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2022

Document Transition Report

false

Entity File Number

001-32936

Entity Registrant Name

HELIX ENERGY SOLUTIONS GROUP, INC.

Entity Incorporation, State or Country Code

MN

Entity Tax Identification Number

95-3409686

Entity Address, Address Line One

3505 West Sam Houston Parkway North

Entity Address, Address Line Two

Suite 400

Entity Address, City or Town

Houston

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77043

City Area Code

281

Local Phone Number

618-0400

Title of 12(b) Security

Common Stock, no par value

Trading Symbol

HLX

Security Exchange Name

NYSE

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Public Float

$ 442.6

Entity Common Stock, Shares Outstanding

152,153,912

Auditor Name

KPMG LLP

Auditor Firm ID

185

Auditor Location

Houston, Texas

Entity Central Index Key

0000866829

Current Fiscal Year End Date

--12-31

Document Fiscal Year Focus

2022

Document Fiscal Period Focus

FY

Amendment Flag

false

Documents Incorporated by Reference [Text Block]

Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 17, 2023 are incorporated by reference into Part III hereof.

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 186,604	$ 253,515
Restricted cash	2,507	73,612
Accounts receivable, net of allowance for credit losses of $2,277 and $1,477, respectively	212,779	144,137
Other current assets	58,699	58,274
Total current assets	460,589	529,538
Property and equipment	3,016,312	2,938,154
Less accumulated depreciation	(1,374,697)	(1,280,509)
Property and equipment, net	1,641,615	1,657,645
Operating lease right-of-use assets	197,849	104,190
Deferred recertification and dry dock costs, net	38,778	16,291
Other assets, net	50,507	18,364
Total assets	2,389,338	2,326,028
Current liabilities:
Accounts payable	135,267	87,959
Accrued liabilities	73,574	91,712
Current maturities of long-term debt	38,200	42,873
Current operating lease liabilities	50,914	55,739
Total current liabilities	297,955	278,283
Long-term debt	225,875	262,137
Operating lease liabilities	154,686	50,198
Deferred tax liabilities	98,883	86,966
Other non-current liabilities	95,230	975
Total liabilities	872,629	678,559
Commitments and contingencies
Shareholders' equity:
Common stock, no par, 240,000 shares authorized, 151,935 and 151,124 shares issued, respectively	1,298,740	1,292,479
Retained earnings	323,288	411,072
Accumulated other comprehensive loss	(105,319)	(56,082)
Total shareholders' equity	1,516,709	1,647,469
Total liabilities and shareholders' equity	$ 2,389,338	$ 2,326,028

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Allowance for credit losses	$ 2,277	$ 1,477
Shareholders' equity:
Common stock, par value (USD per share)	$ 0	$ 0
Common stock, shares authorized	240,000,000	240,000,000
Common stock, shares issued	151,935,000	151,124,000

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Consolidated Statements Of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Statement [Abstract]
Net revenues	$ 873,100	$ 674,728	$ 733,555
Cost of sales	822,484	659,335	653,646
Gross profit	50,616	15,393	79,909
Gain (loss) on disposition of assets, net		(631)	889
Goodwill impairment			(6,689)
Acquisition and integration costs	(2,664)
Change in fair value of contingent consideration	(16,054)
Selling, general and administrative expenses	(76,753)	(63,449)	(61,084)
Income (loss) from operations	(44,855)	(48,687)	13,025
Equity in earnings (losses) of investment	8,262	(1)	216
Net interest expense	(18,950)	(23,201)	(28,531)
Gain (loss) on extinguishment of long-term debt		(136)	9,239
Other income (expense), net	(23,330)	(1,490)	4,724
Royalty income and other	3,692	2,873	2,710
Income (loss) before income taxes	(75,181)	(70,642)	1,383
Income tax provision (benefit)	12,603	(8,958)	(18,701)
Net income (loss)	(87,784)	(61,684)	20,084
Net loss attributable to redeemable noncontrolling interests	0	(146)	(2,090)
Net income (loss) attributable to common shareholders	$ (87,784)	$ (61,538)	$ 22,174
Earnings (loss) per share of common stock:
Basic	$ (0.58)	$ (0.41)	$ 0.13
Diluted	$ (0.58)	$ (0.41)	$ 0.13
Weighted average common shares outstanding (in shares)
Basic	151,276	150,056	148,993
Diluted	151,276	150,056	149,897

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Consolidated Statements Of Comprehensive Income (Loss) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ (87,784)	$ (61,684)	$ 20,084
Other comprehensive income (loss), net of tax:
Net unrealized loss on hedges arising during the period			(95)
Reclassifications into earnings			452
Income taxes on hedges			(72)
Net change in hedges, net of tax			285
Foreign currency translation gain (loss)	(49,237)	(4,462)	12,835
Other comprehensive income (loss), net of tax	(49,237)	(4,462)	13,120
Comprehensive income (loss)	(137,021)	(66,146)	33,204
Less comprehensive loss attributable to redeemable noncontrolling interests:
Net loss	0	(146)	(2,090)
Foreign currency translation gain	0	50	90
Comprehensive loss attributable to redeemable noncontrolling interests	0	(96)	(2,000)
Comprehensive income (loss) attributable to common shareholders	$ (137,021)	$ (66,050)	$ 35,204

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Consolidated Statements Of Shareholders' Equity - USD ($) shares in Thousands, $ in Thousands	Common Stock Cumulative Effect, Period of Adoption	Common Stock	Retained Earnings Cumulative Effect, Period of Adoption	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Cumulative Effect, Period of Adoption	Total
Balance, beginning of period (Accounting Standards Update 2016-13) at Dec. 31, 2019			$ (620)			$ (620)
Balance, beginning of period at Dec. 31, 2019		$ 1,318,961		$ 445,370	$ (64,740)		$ 1,699,591
Balance, beginning of period (in shares) at Dec. 31, 2019		148,888
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)				22,174			22,174
Foreign currency translation adjustments					12,835		12,835
Unrealized gain on hedges, net of tax					285		285
Accretion of redeemable noncontrolling interests				(2,400)			(2,400)
Equity component of convertible senior notes		$ 33,336					33,336
Re-acquisition of equity component of convertible senior notes		(18,006)					(18,006)
Capped call transactions		(10,625)					(10,625)
Activity in company stock plans, net and other		$ (4,345)					(4,345)
Activity in company stock plans, net and other (in shares)		1,453
Share-based compensation		$ 8,271					8,271
Balance, end of period (Accounting Standards Update 2020-06) at Dec. 31, 2020	$ (41,456)		$ 6,682			$ (34,774)
Balance, end of period at Dec. 31, 2020		$ 1,327,592		464,524	(51,620)		1,740,496
Balance, end of period (in shares) at Dec. 31, 2020		150,341
Balance, beginning of period at Dec. 31, 2019							3,455
Increase (Decrease) in Redeemable Noncontrolling Interests [Roll Forward]
Net income (loss)							(2,090)
Foreign currency translation adjustments related to redeemable noncontrolling interests							90
Accretion of redeemable noncontrolling interests							2,400
Balance, end of period at Dec. 31, 2020							3,855
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)				(61,538)			(61,538)
Foreign currency translation adjustments					(4,462)		(4,462)
Accretion of redeemable noncontrolling interests				1,404			1,404
Activity in company stock plans, net and other		$ (1,128)					(1,128)
Activity in company stock plans, net and other (in shares)		783
Share-based compensation		$ 7,471					7,471
Balance, end of period at Dec. 31, 2021		$ 1,292,479		411,072	(56,082)		1,647,469
Balance, end of period (in shares) at Dec. 31, 2021		151,124
Increase (Decrease) in Redeemable Noncontrolling Interests [Roll Forward]
Net income (loss)							(146)
Foreign currency translation adjustments related to redeemable noncontrolling interests							50
Accretion of redeemable noncontrolling interests							(1,404)
Acquisition of redeemable noncontrolling interests							(2,355)
Net income (loss)				(87,784)			(87,784)
Foreign currency translation adjustments					(49,237)		(49,237)
Activity in company stock plans, net and other		$ (991)					(991)
Activity in company stock plans, net and other (in shares)		811
Share-based compensation		$ 7,252					7,252
Balance, end of period at Dec. 31, 2022		$ 1,298,740		$ 323,288	$ (105,319)		$ 1,516,709
Balance, end of period (in shares) at Dec. 31, 2022		151,935

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Consolidated Statements Of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income (loss)	$ (87,784)	$ (61,684)	$ 20,084
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization	142,686	141,514	133,709
Goodwill impairment			6,689
Amortization of debt discounts			6,964
Amortization of debt issuance costs	2,334	3,179	3,177
Share-based compensation	7,451	7,689	8,568
Deferred income taxes	4,386	(15,202)	(3,883)
Equity in (earnings) losses of investment	(8,262)	1	(216)
(Gain) loss on disposition of assets, net		631	(889)
(Gain) loss on extinguishment of long-term debt		136	(9,239)
Unrealized gain on derivative contracts, net			(601)
Unrealized foreign currency (gain) loss	21,596	2,252	(2,665)
Change in fair value of contingent consideration	16,054
Changes in operating assets and liabilities:
Accounts receivable, net	(29,865)	(14,154)	(8,419)
Other current assets	7,593	22,973	(28,664)
Income tax payable, net of income tax receivable	(49)	18,610	(22,124)
Accounts payable and accrued liabilities	9,807	46,645	10,830
Deferred recertification and dry dock costs, net	(35,072)	(9,620)	(19,348)
Other, net	(233)	2,853	(4,827)
Net cash provided by operating activities	51,108	140,117	98,800
Cash flows from investing activities:
Alliance acquisition, net of cash acquired	(112,625)
Capital expenditures	(33,504)	(8,322)	(20,244)
Distribution from equity investment, net	7,840
Proceeds from sale of assets		51	963
Net cash used in investing activities	(138,289)	(8,271)	(19,281)
Cash flows from financing activities:
Proceeds from convertible senior notes			200,000
Repayment of convertible senior notes	(35,000)		(183,150)
Capped call transactions			(10,625)
Debt issuance costs	(580)	(1,337)	(7,747)
Acquisition of redeemable noncontrolling interests		(2,355)
Payments related to tax withholding for share-based compensation	(1,902)	(2,001)	(5,264)
Proceeds from issuance of ESPP shares	575	654	622
Net cash used in financing activities	(44,844)	(95,997)	(52,578)
Effect of exchange rate changes on cash and cash equivalents and restricted cash	(5,991)	(42)	1,818
Net increase (decrease) in cash and cash equivalents and restricted cash	(138,016)	35,807	28,759
Cash and cash equivalents and restricted cash:
Balance, beginning of year	327,127	291,320	262,561
Balance, end of year	189,111	327,127	291,320
Term Loan Repaid September 2021
Cash flows from financing activities:
Repayment of loan debt		(29,826)	(3,500)
Nordea Q5000 Loan Matured January 2021
Cash flows from financing activities:
Repayment of loan debt		(53,572)	(35,714)
MARAD Debt (matures February 2027)
Cash flows from financing activities:
Repayment of loan debt	$ (7,937)	$ (7,560)	$ (7,200)

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Organization

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization

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 full-field decommissioning operations. Our services are centered toward and well positioned to facilitate global energy transition by maximizing production of remaining oil and gas reserves, supporting renewable energy developments and decommissioning end-of-life oil and gas fields. We provide a range of services to the oil and gas and renewable energy markets primarily in the Gulf of Mexico, U.S. East Coast, Brazil, North Sea, Asia Pacific and West Africa regions. We have expanded our service capabilities to the Gulf of Mexico shelf with the acquisition of the Alliance group of companies (collectively “Alliance”) on July 1, 2022. Our North Sea operations and our Gulf of Mexico shelf operations related to our Alliance acquisition are subject to seasonal changes in demand, 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, Production Facilities and our new reporting segment, Shallow Water Abandonment, which was formed in the third quarter 2022 comprising the Helix Alliance business (Note 14).

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

Our Robotics segment provides trenching, seabed clearance, offshore construction and inspection, repair and maintenance (“IRM”) services to both the oil and gas and the renewable energy markets globally, thereby assisting the delivery of affordable and reliable energy and supporting the responsible transition away from a carbon-based economy. Additionally, our robotics services are used in and complement our well intervention services. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers, the IROV boulder grab and robotics support vessels under term charters as well as spot vessels as needed.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries predominantly in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment includes a diversified fleet of marine assets including liftboats, offshore supply vessels (“OSVs”), dive support vessels (“DSVs”), a heavy lift derrick barge, a crew boat and plug and abandonment (“P&A”) and coiled tubing systems.

Our Production Facilities segment includes the Helix Producer I (the “HP I”), the Helix Fast Response System (the “HFRS”), and our ownership of mature oil and gas properties. All of our current Production Facilities activities are located in the Gulf of Mexico.

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Summary Of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Summary Of Significant Accounting Policies

Note 2 — Summary of Significant Accounting Policies

Principles of Consolidation

Our consolidated financial statements include the accounts of our majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership but have the ability to exert significant influence. All material intercompany accounts and transactions have been eliminated.

Basis of Presentation

Our consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”) in U.S. dollars. 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.

Restricted Cash

We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. Our restricted cash as of December 31, 2022 consisted of $2.5 million pledged toward our asset-based credit agreement (the “ABL Facility”). Our restricted cash as of December 31, 2021 consisted of $71.1 million pledged as collateral for a letter of credit for a temporary importation permit for work offshore Nigeria and $2.5 million pledged toward the ABL Facility. These cash pledges increase the availability under the ABL Facility.

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 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, must be finalized as soon as practicable, but no later than one year from the closing of the acquisition.

Contingent consideration payable in cash, which is included in “Other non-current liabilities” in the accompanying consolidated balance sheet (Note 4), 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 earnings until the liability is settled.

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. Also presented separately are the changes in fair value of the contingent earn-out consideration (Note 19).

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.

Capitalized Interest

Interest from external borrowings is capitalized on major projects under development until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset. Capitalized interest is excluded from our interest expense (Note 7) and is included as an investing cash outflow in the consolidated statements of cash flows.

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.

Leases

Leases with a term greater than one year are recognized in the consolidated balance sheet as right-of-use (“ROU”) assets and lease liabilities. 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.

Goodwill

Goodwill impairment is evaluated using a two-step process. The first step involves comparing a reporting unit’s fair value with its carrying amount. We have the option to assess qualitative factors to determine if it is necessary to perform the first step. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we must perform the quantitative goodwill impairment test, which involves estimating the reporting unit’s fair value and comparing it to its carrying amount. If the reporting unit’s carrying amount exceeds its fair value, impairment loss is recognized in an amount equal to that excess, but not to exceed the goodwill’s carrying amount.

We perform an impairment analysis of goodwill at least annually as of November 1 or more frequently whenever events or circumstances occur indicating that goodwill might be impaired. Our goodwill balance attributable to the acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) was fully impaired during 2020 (Note 3).

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 dry dock. 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 if the appropriate permitting is obtained. A recertification process, including vessel dry dock, typically lasts between one to three months, 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.

During the years ended December 31, 2022, 2021 and 2020, amortization expense related to deferred recertification and dry dock costs was $14.0 million, $14.6 million and $14.3 million, respectively.

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 clearing for the oil and gas and the renewable energy markets and to provide offshore construction 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 new Shallow Water Abandonment segment by providing decommissioning and intervention services with P&A and coiled tubing 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 DSVs and personnel and with the heavy lift barge.

Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.

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 in which we provide 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.

The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We generally do not provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. 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.

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.

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 and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. 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.

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 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. At December 31, 2022, we believe that we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit has been recognized or are required to pay amounts exceeding the liability, our effective tax rate in a given financial statement period may be affected.

Share-Based Compensation

Share-based compensation is measured at the grant date based on the estimated fair value of an award. Share-based compensation based solely on service conditions is recognized on a straight-line basis over the vesting period of the related shares. Forfeitures are recognized as they occur.

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 performance share unit (“PSU”) awards that have a service and a market condition and 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 PSUs that have a service and a performance condition and 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.

Compensation cost for restricted stock unit (“RSU”) awards, which are accounted for as liability awards, is 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.

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, 2022, 2021 and 2020, our foreign currency transaction gains (losses) totaled $(23.4) million, $(1.5) million and $4.6 million, respectively.

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects of dilutive common stock equivalents, if any. 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 basic and diluted EPS under the two-class method in periods in which we have earnings. Under the two-class method, net income or loss attributable to common shareholders 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.

Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable 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 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) are as follows: 2022 — Shell (15%); 2021 — Petrobras (23%) and Shell (17%); and 2020 — Petrobras (28%) and BP (17%). Most of the concentration of revenues are in our Well Intervention segment.

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 June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Measurement of Credit Losses on Financial Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets (including trade receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. Upon adoption of ASU No. 2016-13 on January 1, 2020, we recognized $0.6 million (net of deferred taxes of $0.2 million) related to the provision for current expected credit losses on our accounts receivable through a cumulative effect offset to retained earnings. The credit loss standard also resulted in the recognition of an additional $0.7 million in credit loss reserves on our accounts receivable for the year ended December 31, 2020. See Note 18 for additional information regarding allowance for credit losses on our accounts receivable.

In August 2020, the FASB issued ASU No. 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity's Own Equity,” which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Among other changes, this ASU removes from GAAP the requirement to separate certain convertible instruments, such as our Convertible Senior Notes Due 2022 (the “2022 Notes”), Convertible Senior Notes Due 2023 (the “2023 Notes”) and Convertible Senior Notes Due 2026 (the “2026 Notes”) (Note 7), into liability and equity components. Consequently, those convertible instruments will be accounted for in their entirety as liabilities measured at their amortized cost. We elected to early adopt ASU No. 2020-06 on a modified retrospective basis beginning January 1, 2021. The adoption of this ASU increased our long-term debt and decreased the reported value of our common stock by $44.1 million and $41.5 million, respectively, as we reclassified the conversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of this ASU also increased our retained earnings and decreased deferred tax liabilities by $6.7 million and $9.3 million, respectively. As a result of our adoption of ASU No. 2020-06, interest expense associated with our outstanding convertible senior notes decreased by $7.6 million in 2021 as there were no longer any debt discounts to amortize.

New accounting standards issued but not yet effective

We do not expect any 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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Business Combinations

12 Months Ended

Dec. 31, 2022

Business Combinations

Business Combinations

Note 3 — Business Combinations

Alliance Acquisition

On July 1, 2022, we completed our acquisition of all of the equity interests of Alliance. The Alliance acquisition extends our energy transition strategy by adding shallow water capabilities into what we expect to be a growing offshore decommissioning market.

The aggregate preliminary purchase price of the Alliance acquisition was $145.7 million, consisting of $119.0 million with cash on hand and the estimated fair value of $26.7 million of contingent consideration related to the post-closing earn-out consideration. The earn-out is payable in 2024 to the seller in the Alliance transaction in either cash or shares of our common stock pursuant to the terms of the Equity Purchase Agreement (the “Equity Purchase Agreement”) dated May 16, 2022. The earn-out is not capped and is calculated based on certain financial metrics of the Helix Alliance business for 2022 and 2023 relative to amounts as set forth in the Equity Purchase Agreement.

The following table summarizes the purchase consideration and the preliminary purchase price allocation to estimated fair values of the identifiable assets acquired and liabilities assumed as of July 1, 2022 (in thousands):

	As Originally				As
	Reported		Adjustments (1)		Adjusted
Cash consideration	$	118,961	$	—	$	118,961
Contingent consideration		26,700		—		26,700
Total fair value of consideration transferred	$	145,661		—	$	145,661
Assets acquired:
Cash and cash equivalents	$	6,336		—	$	6,336
Accounts receivable (2)		43,378		—		43,378
Other current assets		4,879		1,198		6,077
Property and equipment		118,619		(1,298)		117,321
Operating lease right-of-use assets		1,205		—		1,205
Intangible assets		1,400		100		1,500
Other assets		2,133		—		2,133
Total assets acquired		177,950		—		177,950
Liabilities assumed:
Accounts payable		20,480		—		20,480
Accrued liabilities		3,073		—		3,073
Operating lease liabilities		1,205		—		1,205
Deferred tax liabilities		7,531		—		7,531
Total liabilities assumed		32,289		—		32,289
Net assets acquired	$	145,661	$	—	$	145,661

(1) Adjustments to the preliminary purchase price allocation stem mainly from additional information obtained in between the closing of the Alliance acquisition on July 1, 2022 and December 31, 2022 about facts and circumstances that existed as of the acquisition date.

(2) The gross contractual accounts receivable totaled $44.2 million. The fair value of accounts receivable reflects our best estimate at the acquisition date of contractual cash flows expected to be collected.

The pro forma summary below presents the results of operations as if the Alliance acquisition had occurred on January 1, 2021 and includes transaction accounting adjustments such as incremental depreciation and amortization expense from acquired tangible and intangible assets, elimination of interest expense on Alliance’s long-term debt that was paid off in conjunction with the acquisition, and tax-related effects. The pro forma summary uses estimates and assumptions based on information available at the time. Management believes the estimates and assumptions to be reasonable; however, actual results may differ significantly from this pro forma financial information. The pro forma information does not reflect any cost savings, operating synergies or revenue enhancements that might have been achieved from combining the operations. The unaudited pro forma summary is provided for illustrative purposes only and does not purport to represent Helix’s actual consolidated results of operations had the acquisition been completed as of the date presented, nor should it be considered indicative of Helix’s future consolidated results of operations.

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

	Year Ended December 31,
	2022		2021
Revenues	$	952,837	$	789,051
Net loss		(79,686)		(56,203)

STL Acquisition

In May 2019, we acquired a 70% controlling interest in STL, a subsea engineering firm based in Aberdeen, Scotland. The acquisition resulted in goodwill of $6.9 million. Oil prices as well as energy and energy services valuations experienced significant decline during the first quarter 2020 and as a result, we impaired all of our goodwill, which consisted entirely of goodwill attributable to STL. In June 2021, we acquired the remaining 30% interest in STL, which had been recognized as temporary equity. STL is included in our Well Intervention segment and its revenue and earnings are immaterial to our consolidated results.

The changes in the carrying amount of goodwill are as follows (in thousands):

	Well Intervention
Balance at December 31, 2019	$	7,157
Impairment loss		(6,689)
Foreign currency adjustments		(468)
Balance at December 31, 2020	$	—

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Details Of Certain Accounts

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Details Of Certain Accounts

Note 4 — Details of Certain Accounts

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

	December 31,
	2022		2021
Prepaids	$	26,609	$	18,228
Income tax receivable		—		1,116
Contract assets (Note 11)		6,295		639
Deferred costs (Note 11)		13,969		2,967
Other receivable (1)		—		28,805
Other		11,826		6,519
Total other current assets	$	58,699	$	58,274

(1) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil in 2019; classified as current as the P&A work was expected to be performed within 12 months from December 31, 2021.

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

	December 31,
	2022		2021
Prepaid charter (1)	$	12,544	$	12,544
Deferred costs (Note 11)		6,432		381
Other receivable (2)		24,827		—
Intangible assets with finite lives, net		4,465		3,472
Other		2,239		1,967
Total other assets, net	$	50,507	$	18,364

(1) Represents prepayments to the owner of the Siem Helix 1 and the Siem Helix 2 to offset certain payment obligations associated with the vessels at the end of their respective charter term.

(2) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil; reclassified to non-current as we expect the remaining P&A work to be performed beyond 12 months from December 31, 2022.

Accrued liabilities consist of the following (in thousands):

	December 31,
	2022		2021
Accrued payroll and related benefits	$	41,339	$	28,657
Accrued interest		6,306		6,746
Income tax payable		479		—
Deferred revenue (Note 11)		9,961		8,272
Asset retirement obligations (Note 15)		—		29,658
Other		15,489		18,379
Total accrued liabilities	$	73,574	$	91,712

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

	December 31,
	2022		2021
Deferred revenue (Note 11)	$	—	$	476
Asset retirement obligations (Note 15)		51,956		—
Contingent consideration (Note 19)		42,754		—
Other		520		499
Total other non-current liabilities	$	95,230	$	975

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Property And Equipment

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Property And Equipment

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	2022		2021
Vessels	15 to 30 years	$	2,371,084	$	2,343,162
ROVs and trenchers	5 to 10 years		262,763		257,274
Machinery, equipment, buildings and other	5 to 39 years		382,465		337,718
Total property and equipment		$	3,016,312	$	2,938,154

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Leases

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Leases

Note 6 — Leases

We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. The majority of the increases in our operating leases during the year ended December 31, 2022 are related to the vessel charter extensions for the Siem Helix 1, the Siem Helix 2, the Grand Canyon II, the Grand Canyon III and the Shelia Bordelon (Note 16). We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, 2022, the minimum sublease income to be received in the future totaled $1.3 million.

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

	Year Ended December 31,
	2022		2021		2020
Operating lease cost	$	61,067	$	60,636	$	64,742
Variable lease cost		20,562		16,711		15,021
Short-term lease cost		29,487		20,590		37,524
Sublease income		(1,275)		(1,303)		(1,286)
Net lease cost	$	109,841	$	96,634	$	116,001

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

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	58,063	$	6,603	$	64,666
One to two years		55,515		5,697		61,212
Two to three years		43,400		2,797		46,197
Three to four years		35,200		959		36,159
Four to five years		26,244		959		27,203
Over five years		3,041		2,783		5,824
Total lease payments	$	221,463	$	19,798	$	241,261
Less: imputed interest		(32,986)		(2,675)		(35,661)
Total operating lease liabilities	$	188,477	$	17,123	$	205,600
Current operating lease liabilities	$	45,131	$	5,783	$	50,914
Non-current operating lease liabilities		143,346		11,340		154,686
Total operating lease liabilities	$	188,477	$	17,123	$	205,600

Maturities of our operating lease liabilities as of December 31, 2021 are as follows (in thousands):

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	55,573	$	5,601	$	61,174
One to two years		34,580		4,844		39,424
Two to three years		2,470		4,514		6,984
Three to four years		—		2,462		2,462
Four to five years		—		1,074		1,074
Over five years		—		4,193		4,193
Total lease payments	$	92,623	$	22,688	$	115,311
Less: imputed interest		(5,633)		(3,741)		(9,374)
Total operating lease liabilities	$	86,990	$	18,947	$	105,937
Current operating lease liabilities	$	51,035	$	4,704	$	55,739
Non-current operating lease liabilities		35,955		14,243		50,198
Total operating lease liabilities	$	86,990	$	18,947	$	105,937

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

	December 31,
	2022		2021		2020
Weighted average remaining lease term	4.0	years	2.4	years	3.1	years
Weighted average discount rate	7.84	%	7.57	%	7.53	%

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

	Year Ended December 31,
	2022		2021		2020
Cash paid for operating lease liabilities	$	58,129	$	61,826	$	66,026
Right-of-use assets obtained in exchange for new operating lease obligations		144,134		5,992		516

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Long-Term Debt

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Long-term Debt

Note 7 — Long-Term Debt

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

	December 31,
	2022		2021
2022 Notes (matured May 2022)	$	—	$	35,000
2023 Notes (mature September 2023)		30,000		30,000
2026 Notes (mature February 2026)		200,000		200,000
MARAD Debt (matures February 2027)		40,913		48,850
Unamortized debt issuance costs		(6,838)		(8,840)
Total debt		264,075		305,010
Less current maturities		(38,200)		(42,873)
Long-term debt	$	225,875	$	262,137

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 on July 1, 2022 we entered into a first amendment to the credit agreement (collectively, the “Amended ABL Facility”). The Amended ABL Facility provides for a $100 million asset-based revolving credit facility, which matures on September 30, 2026, with a springing maturity 91 days prior to the maturity of any outstanding indebtedness with a principal amount in excess of $50 million. The Amended ABL Facility also permits us to request an increase of the facility by up to $50 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 $65 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 $10 million sub-limit for the issuance of letters of credit. As of December 31, 2022, we had no borrowings under the Amended ABL Facility, and our available borrowing capacity under that facility, based on the borrowing base, totaled $98.1 million, net of $1.9 million of letters of credit issued under that facility.

We and certain of our U.S. and U.K. subsidiaries including Helix Alliance 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 (also known as CME Term SOFR as administered by CME Group, Inc.) rate 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 $10 million. The Amended ABL Facility also requires us to maintain a pro forma minimum excess availability of $20 million for the 91 days prior to the maturity of each of our outstanding convertible senior notes.

The Amended ABL Facility also (i) limits the amount of permitted debt for the deferred purchase price of property not to exceed $50 million, (ii) establishes an excess availability requirement for the portion of any post-closing earn-out consideration related to our acquisition of Alliance that will be paid in cash (Note 3), and (iii) provides for potential 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, related to environmental, social and governance (“ESG”) changes implemented by us in our business.

2022 Notes

We fully redeemed the $35 million remaining principal amount of the 2022 Notes plus accrued interest by delivering cash upon maturity as of May 1, 2022. The effective interest rate for the 2022 Notes was 4.8%. For the years ended December 31, 2022 and 2021, total interest expense related to the 2022 Notes was $0.6 million and $1.7 million, respectively, primarily from coupon interest expense. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). During 2020, we repurchased $90 million in aggregate principal amount of the 2022 Notes, and for the year ended December 31, 2020, total interest expense related to the 2022 Notes was $6.6 million, with coupon interest expense of $3.9 million and the amortization of debt discount and issuance costs of $2.7 million.

2023 Notes

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

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

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

The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2023 Notes together with any accrued interest will become immediately due and payable.

The effective interest rate for the 2023 Notes is 4.8%. For each of the years ended December 31, 2022 and 2021, total interest expense related to the 2023 Notes was $1.4 million primarily from coupon interest expense. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). During 2020, we repurchased $95 million in aggregate principal amount of the 2023 Notes, and for the year ended December 31, 2020, total interest expense related to the 2023 Notes was $6.6 million, with coupon interest expense of $3.7 million and the amortization of debt discount and issuance costs of $2.9 million.

2026 Notes

The 2026 Notes bear interest at a coupon interest rate of 6.75% per annum payable semi-annually in arrears on February 15 and August 15 of each year, beginning on February 15, 2021 until maturity. The 2026 Notes mature on February 15, 2026 unless earlier converted, redeemed or repurchased by us. The 2026 Notes are convertible by their holders at any time beginning November 17, 2025 at an initial conversion rate of 143.3795 shares of our common stock per $1,000 principal amount, which currently represents 28,675,900 potentially convertible shares at an initial conversion price of approximately $6.97 per share of common stock. Upon conversion, we have the right to satisfy our conversion obligation by delivering cash, shares of our common stock or any combination thereof. In order to reduce the potential dilution of the 2026 Notes to shareholders’ equity, we entered into capped call transactions (the “2026 Capped Calls”) in August 2020 concurrent with the 2026 Notes offering (Note 9). The 2026 Capped Calls effectively increase the conversion price of the 2026 Notes to approximately $8.42 per share. However, the 2026 Capped Calls are separate transactions from the 2026 Notes and do not change the holders’ rights under the 2026 Notes, and holders of the 2026 Notes do not have any rights with respect to the 2026 Capped Calls.

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

Prior to August 15, 2023, the 2026 Notes are not redeemable. On or after August 15, 2023, we may redeem all or any portion of the 2026 Notes if the price of our common stock has been at least 130% of the conversion price for at least 20 trading days during any 30 consecutive trading day period preceding our redemption notice. Any redemption would be payable in cash equal to 100% of the principal amount plus accrued and unpaid interest and a “make-whole premium” calculated as the present value of all remaining scheduled interest payments. Holders of the 2026 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2026 Notes may also require us to repurchase the notes following a “fundamental change,” which includes a change of control or a termination of trading of our common stock (as defined in the indenture governing the 2026 Notes).

The indenture governing the 2026 Notes contains customary terms and covenants, including that upon certain events of default, the entire principal amount of and any accrued interest on the notes may be declared immediately due and payable. In the case of certain events of bankruptcy, insolvency or reorganization relating to us or a significant subsidiary, the principal amount of the 2026 Notes together with any accrued interest will become immediately due and payable.

The effective interest rate for the 2026 Notes is 7.6%. For the years ended December 31, 2022 and 2021, total interest expense related to the 2026 Notes was $14.8 million and $14.7 million, respectively, with coupon interest expense of $13.5 million each, and the amortization of debt issuance costs of $1.3 million and $1.2 million, respectively. As a result of our adoption of ASU No. 2020-06, there were no longer any debt discounts to amortize in 2022 and 2021 (Note 2). For the year ended December 31, 2020, total interest expense related to the 2026 Notes was $7.5 million, with coupon interest expense of $5.1 million and the amortization of debt discount and issuance costs of $2.4 million.

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

Other

In accordance with the Amended ABL Facility, the 2023 Notes, the 2026 Notes and the MARAD Debt, 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, 2022, we were in compliance with these covenants.

We previously had a credit agreement (and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America. The Credit Agreement was comprised of a term loan (the “Term Loan”) and a revolving credit facility (the “Revolving Credit Facility”) with a maximum availability of $175 million and had a maturity date of December 31, 2021. Concurrent with our entering into the ABL Facility on September 30, 2021, the Credit Agreement was terminated, the $28 million remaining balance of the Term Loan was repaid in full and the letters of credit issued under the Revolving Credit Facility were transferred to the ABL Facility. We had no borrowings under the Revolving Credit Facility.

We previously had a credit agreement with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) to finance the construction of the Q5000. The loan was secured by the Q5000 and its charter earnings. In January 2021, we repaid the remaining principal amount of $53.6 million.

Scheduled maturities of our long-term debt outstanding as of December 31, 2022 are as follows (in thousands):

	2023		2026		MARAD
	Notes		Notes		Debt		Total
Less than one year	$	30,000	$	—	$	8,333	$	38,333
One to two years		—		—		8,749		8,749
Two to three years		—		—		9,186		9,186
Three to four years		—		200,000		9,644		209,644
Four to five years		—		—		5,001		5,001
Gross debt		30,000		200,000		40,913		270,913
Unamortized debt issuance costs (1)		(133)		(4,632)		(2,073)		(6,838)
Total debt		29,867		195,368		38,840		264,075
Less current maturities		(29,867)		—		(8,333)		(38,200)
Long-term debt	$	—	$	195,368	$	30,507	$	225,875

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

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

	Year Ended December 31,
	2022		2021		2020
Interest expense	$	20,176	$	23,489	$	30,538
Capitalized interest		—		—		(1,182)
Interest income		(1,226)		(288)		(825)
Net interest expense	$	18,950	$	23,201	$	28,531

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Income Taxes

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Income Taxes

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

	Year Ended December 31,
	2022		2021		2020
Current tax provision (benefit):
Domestic	$	—	$	(1,103)	$	(18,927)
Foreign		8,217		7,347		4,109
Total current	$	8,217	$	6,244	$	(14,818)
Deferred tax provision (benefit):
Domestic	$	1,167	$	(5,756)	$	3,853
Foreign		3,219		(9,446)		(7,736)
Total deferred	$	4,386	$	(15,202)	$	(3,883)
Total income tax provision (benefit)	$	12,603	$	(8,958)	$	(18,701)

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

	Year Ended December 31,
	2022		2021		2020
Domestic	$	(13,745)	$	(53,989)	$	(3,406)
Foreign		(61,436)		(16,653)		4,789
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383

The primary differences between the income tax provision (benefit) at the U.S. statutory rate and our actual income tax provision (benefit) are as follows (dollars in thousands):

	Year Ended December 31,
	2022				2021				2020
Taxes at U.S. statutory rate	$	(15,788)	21.0	%	$	(14,835)	21.0	%	$	290	21.0	%
Foreign tax provision (benefit)		18,011	(24.0)			10,326	(14.6)			(4,517)	(326.7)
CARES Act		—	—			—	—			(7,596)	(549.2)
Subsidiary restructuring		—	—			—	—			(8,333)	(602.5)
Change in valuation allowance		8,110	(10.8)			(5,675)	8.0			1,091	78.9
Non-deductible expenses		2,366	(3.1)			1,487	(2.1)			1,184	85.6
Other		(96)	0.1			(261)	0.4			(820)	(59.3)
Income tax provision (benefit)	$	12,603	(16.8)	%	$	(8,958)	12.7	%	$	(18,701)	(1,352.2)	%

During 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.

During the year ended December 31, 2021, we released a non-U.S. valuation allowance of $5.0 million for deferred tax assets as it is more likely than not that they will be fully utilized.

On March 27, 2020, the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) was enacted, extending the U.S. tax loss carryback period from three years to five years. As a result, we recognized a $7.6 million net tax benefit for the year ended December 31, 2020, consisting of an $18.9 million current tax benefit (refund received) and an $11.3 million deferred tax expense (reduction in U.S. net operating loss). Also during the year ended December 31, 2020, we migrated two of our foreign subsidiaries into our U.S. consolidated tax group. As a result, these subsidiaries are not subject to future U.S. branch profits tax and a net deferred tax benefit of $8.3 million was recognized.

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,
	2022		2021
Deferred tax liabilities:
Depreciation	$	147,302	$	137,898
Prepaid and other		1,868		1,088
Total deferred tax liabilities	$	149,170	$	138,986
Deferred tax assets:
Net operating losses	$	(53,136)	$	(56,369)
Reserves, accrued liabilities and other		(19,308)		(9,698)
Total deferred tax assets		(72,444)		(66,067)
Valuation allowance		22,157		14,047
Net deferred tax liabilities	$	98,883	$	86,966

At December 31, 2022, our U.S. net operating losses available for carryforward totaled $163.1 million, of which $74.5 million will begin to expire between 2036 and 2037, with the remaining $88.6 million not subject to expiration. Management believes it is more likely than not that these tax losses will be utilized prior to their expiration. At December 31, 2022, we had $4.2 million in gross U.S. tax credits, which included $3.0 million of foreign tax credits subject to a full valuation allowance. At December 31, 2022, our non-U.S. net operating losses totaled $69.7 million, which do not expire under local tax law.

At December 31, 2022, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries of approximately $78.9 million, which management intends to indefinitely reinvest in our international operations. Due to the enactment of the U.S. Tax Cuts and Jobs Act, repatriations of foreign earnings will generally be free of U.S. federal tax but may be subject to changes in future tax legislation that may result in taxation. It is not practicable to calculate deferred income taxes associated with these undistributed earnings given the complexities in tax laws and the manner and timing of repatriation.

At December 31, 2022, we had unrecognized tax benefits of $0.1 million related to uncertain tax positions, which, if recognized, would have an insignificant effect on the annual effective tax rate. Due to the expiration of the statute of limitations as well as effective settlements in 2021 we released the full $0.6 million reserve related to uncertain tax positions recorded in 2020. We account for tax-related interest in interest expense and tax penalties in selling, general and administrative expenses. However, no interest has been recorded for these positions as the amount was immaterial.

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 2018 through 2022 are open to review and examination by the U.S. Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2014 through 2022.

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Shareholders' Equity

12 Months Ended

Dec. 31, 2022

Stockholders' Equity Note [Abstract]

Shareholders' Equity

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

The 2026 Capped Calls are subject to either adjustment or termination upon the occurrence of specified extraordinary events affecting Helix, including a merger, tender offer, nationalization, insolvency or delisting. In addition, certain events may result in a termination of the 2026 Capped Calls, including changes in law, insolvency filings and hedging disruptions. The 2026 Capped Calls are recorded at their aggregate cost of $10.6 million as a reduction to common stock in the shareholders’ equity section of our consolidated balance sheets are not recognized as either asset or liability at fair value.

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Share Repurchase Programs

12 Months Ended

Dec. 31, 2022

Equity [Abstract]

Share Repurchase Programs

Note 10 — Share Repurchase Programs

Our Board of Directors (our “Board”) previously granted us the authority 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). As of December 31, 2022, 9,547,027 shares of our common stock were available for repurchase under the program. Concurrent with the authorization of a new share repurchase program as discussed below, our Board revoked the prior authorization relating to this repurchase program.

On February 20, 2023, we announced that our Board authorized a new share repurchase program under which we are authorized to repurchase up to $200 million issued and outstanding shares of our common stock. The repurchase program has no set expiration date. Repurchases under the program would be made through open market purchases in compliance with Rule 10b-18 under the Exchange Act, privately negotiated transactions or plans, instructions or contracts established under Rule 10b5-1 under the Exchange Act. The manner, timing and amount of any purchase will be determined by management based on an evaluation of market conditions, stock price, liquidity and other factors. The program does not obligate us to acquire any particular amount of common stock and may be modified or superseded at any time at our discretion. The purchase of shares by us under the program is at our discretion and subject to prevailing financial and market conditions. Any repurchased shares are expected to be cancelled. No repurchases have been made pursuant to this program at the time of this filing.

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Revenue From Contracts With Customers

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue From Contracts With Customers

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, 2022
Short-term	$	395,867	$	97,533	$	124,810	$	—	$	(635)	$	617,575
Long-term		128,374		94,388		—		82,315		(49,552)		255,525
Total	$	524,241	$	191,921	$	124,810	$	82,315	$	(50,187)	$	873,100
Year ended December 31, 2021
Short-term	$	308,734	$	89,668	$	—	$	—	$	(627)	$	397,775
Long-term		207,830		47,627		—		69,348		(47,852)		276,953
Total	$	516,564	$	137,295	$	—	$	69,348	$	(48,479)	$	674,728
Year ended December 31, 2020
Short-term	$	206,812	$	117,439	$	—	$	—	$	—	$	324,251
Long-term		332,437		60,579		—		58,303		(42,015)		409,304
Total	$	539,249	$	178,018	$	—	$	58,303	$	(42,015)	$	733,555

Contract Balances

Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i) demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii) revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 4). Contract assets as of December 31, 2022 and 2021 were $6.3 million and $0.6 million, respectively. We had no credit losses on our contract assets for the years ended December 31, 2022, 2021 and 2020.

Contract liabilities are obligations to provide future services to a customer for which we have already received, or have the unconditional right to receive, the consideration for those services from the customer. Contract liabilities may consist of (i) advance payments received from customers, including upfront mobilization fees allocated to a single performance obligation and recognized ratably over the contract term and/or (ii) amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 4). Contract liabilities as of December 31, 2022 and 2021 totaled $10.0 million and $8.7 million, respectively. Revenue recognized for the years ended December 31, 2022, 2021 and 2020 included $7.4 million, $7.9 million and $11.6 million, respectively, that were included in the contract liability balance as the beginning of each period.

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

Performance Obligations

As of December 31, 2022, $846.7 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $532.6 million and $314.1 million in 2023 and 2024, 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, 2022.

For the years 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. For the years ended December 31, 2021 and 2020, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial.

Contract Fulfillment Costs

Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 4). Our deferred contract costs as of December 31, 2022 and 2021 totaled $20.4 million and $3.3 million, respectively. For the years ended December 31, 2022, 2021 and 2020, we recorded $29.7 million, $39.1 million and $35.8 million, respectively, related to amortization of deferred contract costs. There were no associated impairment losses for any period presented.

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Earnings Per Share

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Earnings Per Share

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):

	Year Ended December 31,
	2022			2021			2020
	Income		Shares	Income		Shares	Income		Shares
Basic:
Net income (loss) attributable to common shareholders	$	(87,784)		$	(61,538)		$	22,174
Less: Undistributed earnings allocated to participating securities		—			—			(140)
Less: Accretion of redeemable noncontrolling interests		—			(241)			(2,400)
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Diluted:
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Effect of dilutive securities:
Share-based awards other than participating securities		—	—		—	—		—	904
Undistributed earnings reallocated to participating securities		—	—		—	—		1	—
Net income (loss) available to common shareholders, diluted	$	(87,784)	151,276	$	(61,779)	150,056	$	19,635	149,897

We had net losses for the years ended December 31, 2022 and 2021. Accordingly, our diluted EPS calculation for these periods excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):

	Year Ended December 31,
	2022	2021
Diluted shares (as reported)	151,276	150,056
Share-based awards	2,158	1,282
Total	153,434	151,338

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,
	2022	2021	2020
2022 Notes	600	2,519	6,537
2023 Notes	3,168	3,168	9,391
2026 Notes	28,676	28,676	10,891

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2022

Share-based Payment Arrangement [Abstract]

Employee Benefit Plans

Note 13 — Employee Benefit Plans

Defined Contribution Plan

We sponsor a defined contribution 401(k) retirement plan. Our discretionary contributions are in the form of cash and consist of a 50% match of each participant’s contribution up to 5% of the participant’s salary. Our discretionary contributions were suspended for 2021 and re-activated beginning January 2022. For the years ended December 31, 2022 and 2020, we made discretionary employer contributions of $1.5 million and $1.6 million, respectively, to the 401(k) plan.

Employee Stock Purchase Plan

As of December 31, 2022, 1.4 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 of our Board (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.

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. The Compensation Committee also determines the type of award to be made to each participant and, as set forth in the related award agreement, the terms, conditions and limitations applicable to each award. The Compensation Committee may grant stock options, restricted stock, RSUs, PSUs and cash awards. 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.

The 2005 Incentive Plan currently has 17.3 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, 2022, there were approximately 4.0 million shares available for issuance under the 2005 Incentive Plan and no incentive stock options are currently outstanding.

The following grants of share-based awards were made in 2022 under the 2005 Incentive Plan:

			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period
January 1, 2022 (1)	RSU	1,065,705	$	3.12	33% per year over three years
January 4, 2022 (1)	PSU	1,065,705	$	4.25	100% on January 4, 2025
January 4, 2022 (2)	Restricted stock	15,775	$	3.12	100% on January 1, 2024
April 1, 2022 (2)	Restricted stock	14,710	$	4.78	100% on January 1, 2024
July 1, 2022 (2)	Restricted stock	14,867	$	3.10	100% on January 1, 2024
September 22, 2022 (3)	Restricted stock	19,328	$	4.38	100% on September 22, 2023
October 1, 2022 (2)	Restricted stock	12,796	$	3.86	100% on January 1, 2024
December 7, 2022 (2)	Restricted stock	175,882	$	5.97	100% on December 7, 2023

(1) Reflects grants to our executive officers.

(2) Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash, of which 8,013 shares granted on January 4, 2022 and 5,230 shares granted on April 1, 2022 vested upon the approval of our Board’s Compensation Committee in connection with the departure of an independent director during the second quarter 2022.

(3) Reflects restricted stock grants made to two new independent members of our Board in connection with their appointment to our Board.

In January 2023, we granted certain officers 506,436 RSUs and 489,498 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $7.38 per unit or $3.7 million. The grant date fair value of the PSUs was $9.26 per unit or $4.5 million. PSUs and RSUs issued in 2023 are payable in either cash or stock at the discretion of the Compensation Committee. Also in January 2023, we granted $5.9 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,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Shares	Fair Value (1)		Shares	Fair Value (1)		Shares	Fair Value (1)
Awards outstanding at beginning of year	853,726	$	5.62	1,176,951	$	6.61	1,173,045	$	6.81
Granted	253,358		5.33	332,841		3.59	667,752		7.06
Vested (2)	(719,456)		4.94	(656,066)		6.35	(631,498)		7.52
Forfeited	—		—	—		—	(32,348)		5.41
Awards outstanding at end of year	387,628	$	6.70	853,726	$	5.62	1,176,951	$	6.61

(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) Total fair value of restricted stock that vested during the years ended December 31, 2022, 2021 and 2020 was $2.9 million, $2.6 million and $5.4 million, respectively.

For the years ended December 31, 2022, 2021 and 2020, $2.5 million, $3.3 million and $4.2 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost associated with unvested restricted stock at December 31, 2022 totaled approximately $1.2 million. The weighted average vesting period related to unvested restricted stock at December 31, 2022 was approximately 0.6 years.

PSU Awards

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

The following table summarizes information about our PSU awards:

	Year Ended December 31,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)		Units	Fair Value (1)
PSU awards outstanding at beginning of year	1,381,469	$	8.34	1,297,126	$	9.99	1,565,044	$	10.17
Granted	1,065,705		4.25	452,381		5.33	369,938		13.15
Vested	(559,150)		7.60	(368,038)		10.44	(589,335)		12.64
Forfeited	—		—	—		—	(48,521)		7.60
PSU awards outstanding at end of year	1,888,024	$	6.25	1,381,469	$	8.34	1,297,126	$	9.99

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

For the years ended December 31, 2022, 2021 and 2020, $4.8 million, $4.1 million and $4.0 million, respectively, were recognized as share-based compensation related to PSUs. Future compensation cost associated with unvested PSU awards at December 31, 2022 totaled approximately $5.2 million. The weighted average vesting period related to unvested PSUs at December 31, 2022 was approximately 1.4 year. In January 2023, 369,938 PSUs granted in 2020 vested at 77%, representing 285,778 shares of our common stock with a total market value of $3.6 million. In January 2022, 559,150 PSUs granted in 2019 vested at 157%, representing 876,469 shares of our common stock with a total market value of $3.2 million. In January 2021, 368,038 PSUs granted in 2018 vested at 200%, representing 736,075 shares of our common stock with a total market value of $3.1 million.

RSU Awards

Our RSUs granted beginning 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and have been accounted for as liability awards.

The following table summarizes information about our RSU awards:

	Year Ended December 31,
	2022			2021
		Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)
RSU awards outstanding at beginning of year	452,381	$	4.20	—	$	—
Granted	1,065,705		3.12	452,381		4.20
Vested	(150,792)		4.20	—		—
RSU awards outstanding at end of year	1,367,294	$	3.36	452,381	$	4.20

(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, 2022 and 2021 was $3.7 million and $0.5 million, respectively, which is reflected in the liability balance at December 31, 2022 and 2021 for the fair value of RSUs that vested in January 2023 and 2022, respectively. Future compensation cost based on the fair value of unvested RSUs at December 31, 2022 totaled approximately $6.4 million. The weighted average vesting period related to unvested RSUs at December 31, 2022 was approximately 1.8 years.

Cash Awards

In 2022, 2021 and 2020, we granted $5.5 million, $3.5 million and $4.7 million, respectively, of fixed value cash awards 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, 2022, 2021 and 2020, we recognized compensation costs of $4.3 million and $4.0 million and $4.4 million, respectively, which reflected the cash payouts made in January 2023, 2022 and 2021, respectively.

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Business Segment Information

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Business Segment Information

Note 14 — Business Segment Information

Through the second quarter 2022, we have three reportable business segments: Well Intervention, Robotics and Production Facilities. Beginning in the third quarter 2022 as a result of the Alliance acquisition (Note 3), we formed a new reportable business segment: Shallow Water Abandonment, which includes the assets, liabilities and operating results of Helix Alliance. All material intercompany transactions between the segments have been eliminated.

Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention segment for financial reporting purposes. Our Well Intervention segment provides services enabling our customers to safely access offshore wells for the purpose of performing production enhancement or decommissioning operations primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa, with expansion into Asia Pacific. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and the Siem Helix 1 and Siem Helix 2 chartered vessels. Our well intervention equipment includes intervention systems, some of which we provide on a stand-alone basis.

Our Robotics segment provides trenching, seabed clearance, offshore construction and IRM services to both the oil and gas and the renewable energy markets globally. Additionally, our Robotics services are used in and complement our well intervention services. Our Robotics segment includes ROVs, trenchers, the IROV boulder grab and robotics support vessels under term charters as well as spot vessels as needed.

Our Shallow Water Abandonment segment provides services in support of the upstream and midstream ‎industries in the Gulf of Mexico shelf, including offshore oilfield decommissioning and ‎reclamation, project management, engineered solutions, intervention, maintenance, repair, heavy lift and commercial diving services. Our Shallow Water Abandonment segment operates a diversified fleet of marine assets including liftboats, OSVs, DSVs, a heavy lift derrick barge, a crew boat and P&A and coiled tubing systems.

Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties (Note 15).

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

	Year Ended December 31,
	2022		2021		2020
Net revenues —
Well Intervention	$	524,241	$	516,564	$	539,249
Robotics		191,921		137,295		178,018
Shallow Water Abandonment		124,810		—		—
Production Facilities		82,315		69,348		58,303
Intercompany eliminations		(50,187)		(48,479)		(42,015)
Total	$	873,100	$	674,728	$	733,555
Income (loss) from operations —
Well Intervention	$	(53,056)	$	(35,882)	$	26,855
Robotics		29,981		5,762		13,755
Shallow Water Abandonment		22,184		—		—
Production Facilities		27,201		22,906		15,975
Segment operating income (loss)		26,310		(7,214)		56,585
Goodwill impairment (1)		—		—		(6,689)
Change in fair value of contingent consideration		(16,054)		—		—
Corporate, eliminations and other		(55,111)		(41,473)		(36,871)
Total	$	(44,855)	$	(48,687)	$	13,025
Net interest expense		(18,950)		(23,201)		(28,531)
Other non-operating income (expense), net		(11,376)		1,246		16,889
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383
Capital expenditures —
Well Intervention	$	17,617	$	2,349	$	19,523
Robotics		15,603		120		257
Shallow Water Abandonment		532		—		—
Production Facilities		(1,424)		6,770		—
Corporate, eliminations and other		1,176		(917)		464
Total	$	33,504	$	8,322	$	20,244
Depreciation and amortization —
Well Intervention	$	103,952	$	107,551	$	101,756
Robotics		12,209		15,158		15,952
Shallow Water Abandonment		8,172		—		—
Production Facilities		18,520		19,465		15,652
Corporate and eliminations		(167)		(660)		349
Total	$	142,686	$	141,514	$	133,709

(1) Relates to the impairment of the entire STL goodwill balance (Note 3).

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,
	2022		2021		2020
Well Intervention	$	16,545	$	21,521	$	15,039
Robotics		33,642		26,958		26,976
Total	$	50,187	$	48,479	$	42,015

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

	Year Ended December 31,
	2022		2021		2020
U.S.	$	447,205	$	232,661	$	304,563
U.K.		166,980		100,154		133,005
Brazil		81,940		154,326		208,565
West Africa		87,488		126,856		41,840
Other		89,487		60,731		45,582
Total	$	873,100	$	674,728	$	733,555

Our operational assets work in various regions around the world such as the Gulf of Mexico, Brazil, the North Sea, Asia Pacific and West Africa. The following table provides our property and equipment, net of accumulated depreciation, by individually significant geographic location where those assets are based (in thousands):

	December 31,
	2022		2021
U.S.	$	780,803	$	693,062
U.K. (1)		625,001		713,385
Brazil (2)		235,811		251,194
Other		—		4
Total	$	1,641,615	$	1,657,645

(1) Includes the Q7000 and certain other assets that are based in the U.K. but have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

(2) Includes the equipment on the Siem Helix 1 chartered vessel and certain other assets that are based in Brazil but are have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

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

	December 31,
	2022		2021
Well Intervention	$	1,796,269	$	2,012,214
Robotics		192,694		96,249
Shallow Water Abandonment		206,944		—
Production Facilities		136,382		119,004
Corporate and other		57,049		98,561
Total	$	2,389,338	$	2,326,028

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Note 15 — Asset Retirement Obligations

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

	2022		2021		2020
AROs at January 1,	$	29,658	$	30,913	$	28,258
Liability incurred during the period		23,601		—		—
Revisions in estimates		(3,285)		(2,631)		—
Accretion expense		1,982		1,376		2,655
AROs at December 31,	$	51,956	$	29,658	$	30,913

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Commitments And Contingencies And Other Matters

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments And Contingencies And Other Matters

Note 16 — Commitments and Contingencies and Other Matters

Commitments

We have long-term charter agreements with Siem Offshore AS for the Siem Helix 1 and Siem Helix 2 vessels. During the first quarter 2022, the charter agreements for the Siem Helix 1 and the Siem Helix 2 were extended to February 2025 and February 2027, respectively, with further options to extend. We have time charter agreements for the Grand Canyon II and Grand Canyon III vessels, which were extended during the third quarter 2022 to December 2027 and May 2028, respectively, with further options to renew. During the first quarter 2022, we executed short-term time charter agreements for the Horizon Enabler in the North Sea and the Shelia Bordelon in the Gulf of Mexico. During the third quarter 2022, the charter agreement for the Shelia Bordelon was extended to June 2024. In January 2023, we entered into a three-year charter agreement for the Glomar Wave in the North Sea with options to extend.

Contingencies and Claims

Our contingent consideration liability resulting from the Alliance acquisition is subject to risk as a result of changes in our probability weighted discounted cash flow model, which is based on internal forecasts, and changes in weighted average discount rate, which is derived from market data.

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

Litigation

We are involved in various legal proceedings, some involving claims under the General Maritime Laws of the United States and the Merchant Marine Act of 1920 (commonly referred to as the Jones Act). In addition, from time to time we receive other claims, such as contract and employment-related disputes, in the normal course of business.

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

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Statement Of Cash Flow Information

12 Months Ended

Dec. 31, 2022

Supplemental Cash Flow Information [Abstract]

Statement Of Cash Flow Information

Note 17 — Statement of Cash Flow Information

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

	Year Ended December 31,
	2022		2021		2020
Interest paid	$	18,267	$	20,719	$	15,943
Income taxes paid (1)		9,516		8,310		7,434

(1) Exclusive of income tax refunds. During the years ended December 31, 2022 and 2021, we received refunds related to the CARES Act of $1.1 million and $18.9 million, respectively.

Our capital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, 2022 and 2021, these non-cash capital additions totaled $0.4 million and $0.3 million, respectively.

Non-cash investing activities for the year ended December 31, 2022 also included $26.7 million in estimated fair value of contingent earn-out consideration as of July 1, 2022, the date of the Alliance acquisition (Note 3).

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Allowance Accounts

12 Months Ended

Dec. 31, 2022

Credit Loss [Abstract]

Allowance Accounts

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, 2022 (in thousands):

	Allowance for		Deferred Tax Asset
	Credit Losses		Valuation Allowance
Balance at December 31, 2019	$	—	$	18,631
Additions (reductions) (1)		2,684		—
Adjustments (2)		785		1,091
Balance at December 31, 2020		3,469		19,722
Additions (reductions) (1)		(146)		—
Write-offs (3)		(1,846)
Adjustments (4)		—		(5,675)
Balance at December 31, 2021		1,477		14,047
Additions (reductions) (1)		800		—
Adjustments (5)		—		8,110
Balance at December 31, 2022	$	2,277	$	22,157

(1) Additions (reductions) in allowance for credit losses reflect credit loss reserves (releases) during the respective years, including a $1.7 million credit loss reserve in 2020 related to a receivable in our Robotics segment. Additions during 2022 primarily reflected adjustments to the allowance for credit losses due to increases in our expected credit losses as a result of the Alliance acquisition.

(2) The adjustment in allowance for credit losses reflects provision for current expected credit losses upon the adoption of ASU No. 2016-13 on January 1, 2020.

(3) The write-offs of allowance for credit losses reflect certain receivables related to our Robotics segment that were previously reserved and subsequently deemed to be uncollectible.

(4) The decrease in valuation allowance primarily relates to the valuation allowance release for certain of our U.K. operations.

(5) The increase in valuation allowance relates to current year activity and the related change in unrealizable net deferred tax assets.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for credit losses as well as the adoption of ASU No. 2016-13. See Note 8 for a detailed discussion of the valuation allowance related to our deferred tax assets.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value Measurements

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.

The following table sets forth our assets and liabilities that are measured at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value at December 31, 2022
	Level 1		Level 2		Level 3		Total
Liabilities:
Contingent consideration		—		—		42,754		42,754

Contingent consideration liability related to the Alliance acquisition (Note 3) is measured at fair value using Level 3 unobservable inputs at the end of each reporting period. The fair value of the estimated contingent consideration is determined based on our evaluation of the probability and amount of earnout that may be achieved based on expected future performance of Helix Alliance. The Monte Carlo simulation model is used to calculate the estimated earnout payment, which is then discounted to present value based on the expected payment date of the contingent consideration. The weighted-average volatility was 47.5% and the weighted average discount rate was estimated to be 8.0% at December 31, 2022. The changes in the fair value of contingent consideration are as follows:

	2022
Balance at July 1,	$	26,700
Change in fair value		16,054
Balance at December 31,	$	42,754

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

	December 31, 2022				December 31, 2021
	Principal		Fair		Principal		Fair
	Amount (1)		Value (2)		Amount (1)		Value (2)
MARAD Debt (matures February 2027)	$	40,913	$	40,940	$	48,850	$	52,481
2022 Notes (matured May 2022)		—		—		35,000		34,794
2023 Notes (mature September 2023)		30,000		31,149		30,000		29,054
2026 Notes (mature February 2026)		200,000		277,014		200,000		200,562
Total debt	$	270,913	$	349,103	$	313,850	$	316,891

(1) Principal amount includes current maturities and excludes any related unamortized debt issuance costs. See Note 7 for additional disclosures on our long-term debt.

(2) The estimated fair value of the 2022 Notes, the 2023 Notes and the 2026 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.

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Summary Of Significant Accounting Policies (Policy)

12 Months Ended

Dec. 31, 2022

Accounting Policies [Abstract]

Principles of Consolidation

Principles of Consolidation

Our consolidated financial statements include the accounts of our majority-owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership but have the ability to exert significant influence. All material intercompany accounts and transactions have been eliminated.

Basis Of Presentation

Basis of Presentation

Our consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“GAAP”) in U.S. dollars. 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

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

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.

Restricted Cash

Restricted Cash

We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. Our restricted cash as of December 31, 2022 consisted of $2.5 million pledged toward our asset-based credit agreement (the “ABL Facility”). Our restricted cash as of December 31, 2021 consisted of $71.1 million pledged as collateral for a letter of credit for a temporary importation permit for work offshore Nigeria and $2.5 million pledged toward the ABL Facility. These cash pledges increase the availability under the ABL Facility.

Accounts Receivable and Allowance for Credit Losses

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 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

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, must be finalized as soon as practicable, but no later than one year from the closing of the acquisition.

Contingent consideration payable in cash, which is included in “Other non-current liabilities” in the accompanying consolidated balance sheet (Note 4), 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 earnings until the liability is settled.

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. Also presented separately are the changes in fair value of the contingent earn-out consideration (Note 19).

Property and Equipment

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.

Capitalized Interest

Capitalized Interest

Interest from external borrowings is capitalized on major projects under development until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset. Capitalized interest is excluded from our interest expense (Note 7) and is included as an investing cash outflow in the consolidated statements of cash flows.

Equity Investment

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.

Leases

Leases

Leases with a term greater than one year are recognized in the consolidated balance sheet as right-of-use (“ROU”) assets and lease liabilities. 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.

Goodwill

Goodwill

Goodwill impairment is evaluated using a two-step process. The first step involves comparing a reporting unit’s fair value with its carrying amount. We have the option to assess qualitative factors to determine if it is necessary to perform the first step. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we must perform the quantitative goodwill impairment test, which involves estimating the reporting unit’s fair value and comparing it to its carrying amount. If the reporting unit’s carrying amount exceeds its fair value, impairment loss is recognized in an amount equal to that excess, but not to exceed the goodwill’s carrying amount.

We perform an impairment analysis of goodwill at least annually as of November 1 or more frequently whenever events or circumstances occur indicating that goodwill might be impaired. Our goodwill balance attributable to the acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) was fully impaired during 2020 (Note 3).

Deferred Recertification and Dry Dock Costs

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 dry dock. 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 if the appropriate permitting is obtained. A recertification process, including vessel dry dock, typically lasts between one to three months, 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.

During the years ended December 31, 2022, 2021 and 2020, amortization expense related to deferred recertification and dry dock costs was $14.0 million, $14.6 million and $14.3 million, respectively.

Revenue Recognition

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 clearing for the oil and gas and the renewable energy markets and to provide offshore construction 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 new Shallow Water Abandonment segment by providing decommissioning and intervention services with P&A and coiled tubing 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 DSVs and personnel and with the heavy lift barge.

Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.

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 in which we provide 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.

The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We generally do not provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. 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.

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.

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 and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. 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.

Income Taxes

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 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. At December 31, 2022, we believe that we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit has been recognized or are required to pay amounts exceeding the liability, our effective tax rate in a given financial statement period may be affected.

Share-Based Compensation

Share-Based Compensation

Share-based compensation is measured at the grant date based on the estimated fair value of an award. Share-based compensation based solely on service conditions is recognized on a straight-line basis over the vesting period of the related shares. Forfeitures are recognized as they occur.

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 performance share unit (“PSU”) awards that have a service and a market condition and 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 PSUs that have a service and a performance condition and 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.

Compensation cost for restricted stock unit (“RSU”) awards, which are accounted for as liability awards, is 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

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.

Foreign Currency

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, 2022, 2021 and 2020, our foreign currency transaction gains (losses) totaled $(23.4) million, $(1.5) million and $4.6 million, respectively.

Earnings Per Share

Earnings Per Share

Basic earnings per share (“EPS”) is computed by dividing net income or loss available to common shareholders by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects of dilutive common stock equivalents, if any. 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 basic and diluted EPS under the two-class method in periods in which we have earnings. Under the two-class method, net income or loss attributable to common shareholders 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.

Major Customers and Concentration of Risk

Major Customers and Concentration of Risk

We offer our products and services primarily in the offshore oil and gas and renewable 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 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) are as follows: 2022 — Shell (15%); 2021 — Petrobras (23%) and Shell (17%); and 2020 — Petrobras (28%) and BP (17%). Most of the concentration of revenues are in our Well Intervention segment.

Fair Value Measurements

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

New accounting standards adopted

In June 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-13, “Measurement of Credit Losses on Financial Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets (including trade receivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. Upon adoption of ASU No. 2016-13 on January 1, 2020, we recognized $0.6 million (net of deferred taxes of $0.2 million) related to the provision for current expected credit losses on our accounts receivable through a cumulative effect offset to retained earnings. The credit loss standard also resulted in the recognition of an additional $0.7 million in credit loss reserves on our accounts receivable for the year ended December 31, 2020. See Note 18 for additional information regarding allowance for credit losses on our accounts receivable.

In August 2020, the FASB issued ASU No. 2020-06, “Accounting for Convertible Instruments and Contracts in an Entity's Own Equity,” which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Among other changes, this ASU removes from GAAP the requirement to separate certain convertible instruments, such as our Convertible Senior Notes Due 2022 (the “2022 Notes”), Convertible Senior Notes Due 2023 (the “2023 Notes”) and Convertible Senior Notes Due 2026 (the “2026 Notes”) (Note 7), into liability and equity components. Consequently, those convertible instruments will be accounted for in their entirety as liabilities measured at their amortized cost. We elected to early adopt ASU No. 2020-06 on a modified retrospective basis beginning January 1, 2021. The adoption of this ASU increased our long-term debt and decreased the reported value of our common stock by $44.1 million and $41.5 million, respectively, as we reclassified the conversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of this ASU also increased our retained earnings and decreased deferred tax liabilities by $6.7 million and $9.3 million, respectively. As a result of our adoption of ASU No. 2020-06, interest expense associated with our outstanding convertible senior notes decreased by $7.6 million in 2021 as there were no longer any debt discounts to amortize.

New accounting standards issued but not yet effective

We do not expect any 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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Business Combinations (Tables)

12 Months Ended

Dec. 31, 2022

Business Combinations

Schedule of purchase price allocation to estimated fair values of the identifiable assets acquired and liabilities

The following table summarizes the purchase consideration and the preliminary purchase price allocation to estimated fair values of the identifiable assets acquired and liabilities assumed as of July 1, 2022 (in thousands):

	As Originally				As
	Reported		Adjustments (1)		Adjusted
Cash consideration	$	118,961	$	—	$	118,961
Contingent consideration		26,700		—		26,700
Total fair value of consideration transferred	$	145,661		—	$	145,661
Assets acquired:
Cash and cash equivalents	$	6,336		—	$	6,336
Accounts receivable (2)		43,378		—		43,378
Other current assets		4,879		1,198		6,077
Property and equipment		118,619		(1,298)		117,321
Operating lease right-of-use assets		1,205		—		1,205
Intangible assets		1,400		100		1,500
Other assets		2,133		—		2,133
Total assets acquired		177,950		—		177,950
Liabilities assumed:
Accounts payable		20,480		—		20,480
Accrued liabilities		3,073		—		3,073
Operating lease liabilities		1,205		—		1,205
Deferred tax liabilities		7,531		—		7,531
Total liabilities assumed		32,289		—		32,289
Net assets acquired	$	145,661	$	—	$	145,661

(1) Adjustments to the preliminary purchase price allocation stem mainly from additional information obtained in between the closing of the Alliance acquisition on July 1, 2022 and December 31, 2022 about facts and circumstances that existed as of the acquisition date.

(2) The gross contractual accounts receivable totaled $44.2 million. The fair value of accounts receivable reflects our best estimate at the acquisition date of contractual cash flows expected to be collected.

Schedule of pro forma information

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

	Year Ended December 31,
	2022		2021
Revenues	$	952,837	$	789,051
Net loss		(79,686)		(56,203)

Schedule of changes in carrying amount of goodwill

The changes in the carrying amount of goodwill are as follows (in thousands):

	Well Intervention
Balance at December 31, 2019	$	7,157
Impairment loss		(6,689)
Foreign currency adjustments		(468)
Balance at December 31, 2020	$	—

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Details Of Certain Accounts (Tables)

12 Months Ended

Dec. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of other current assets

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

	December 31,
	2022		2021
Prepaids	$	26,609	$	18,228
Income tax receivable		—		1,116
Contract assets (Note 11)		6,295		639
Deferred costs (Note 11)		13,969		2,967
Other receivable (1)		—		28,805
Other		11,826		6,519
Total other current assets	$	58,699	$	58,274

(1) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil Corporation (“Marathon Oil”) for remaining P&A work to be performed by us on Droshky oil and gas properties we acquired from Marathon Oil in 2019; classified as current as the P&A work was expected to be performed within 12 months from December 31, 2021.

Schedule of other assets, net

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

	December 31,
	2022		2021
Prepaid charter (1)	$	12,544	$	12,544
Deferred costs (Note 11)		6,432		381
Other receivable (2)		24,827		—
Intangible assets with finite lives, net		4,465		3,472
Other		2,239		1,967
Total other assets, net	$	50,507	$	18,364

(1) Represents prepayments to the owner of the Siem Helix 1 and the Siem Helix 2 to offset certain payment obligations associated with the vessels at the end of their respective charter term.

(2) Represents agreed-upon amounts that we are entitled to receive from Marathon Oil; reclassified to non-current as we expect the remaining P&A work to be performed beyond 12 months from December 31, 2022.

Schedule of accrued liabilities

Accrued liabilities consist of the following (in thousands):

	December 31,
	2022		2021
Accrued payroll and related benefits	$	41,339	$	28,657
Accrued interest		6,306		6,746
Income tax payable		479		—
Deferred revenue (Note 11)		9,961		8,272
Asset retirement obligations (Note 15)		—		29,658
Other		15,489		18,379
Total accrued liabilities	$	73,574	$	91,712

Schedule of other non-current liabilities

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

	December 31,
	2022		2021
Deferred revenue (Note 11)	$	—	$	476
Asset retirement obligations (Note 15)		51,956		—
Contingent consideration (Note 19)		42,754		—
Other		520		499
Total other non-current liabilities	$	95,230	$	975

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Property And Equipment (Tables)

12 Months Ended

Dec. 31, 2022

Property, Plant and Equipment [Abstract]

Summary of gross components of property and equipment

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

		December 31,
	Estimated Useful Life	2022		2021
Vessels	15 to 30 years	$	2,371,084	$	2,343,162
ROVs and trenchers	5 to 10 years		262,763		257,274
Machinery, equipment, buildings and other	5 to 39 years		382,465		337,718
Total property and equipment		$	3,016,312	$	2,938,154

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Leases (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Schedule of components of lease cost

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

	Year Ended December 31,
	2022		2021		2020
Operating lease cost	$	61,067	$	60,636	$	64,742
Variable lease cost		20,562		16,711		15,021
Short-term lease cost		29,487		20,590		37,524
Sublease income		(1,275)		(1,303)		(1,286)
Net lease cost	$	109,841	$	96,634	$	116,001

Schedule of maturities of operating lease liabilities

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

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	58,063	$	6,603	$	64,666
One to two years		55,515		5,697		61,212
Two to three years		43,400		2,797		46,197
Three to four years		35,200		959		36,159
Four to five years		26,244		959		27,203
Over five years		3,041		2,783		5,824
Total lease payments	$	221,463	$	19,798	$	241,261
Less: imputed interest		(32,986)		(2,675)		(35,661)
Total operating lease liabilities	$	188,477	$	17,123	$	205,600
Current operating lease liabilities	$	45,131	$	5,783	$	50,914
Non-current operating lease liabilities		143,346		11,340		154,686
Total operating lease liabilities	$	188,477	$	17,123	$	205,600

Maturities of our operating lease liabilities as of December 31, 2021 are as follows (in thousands):

			Facilities and
	Vessels		Equipment		Total
Less than one year	$	55,573	$	5,601	$	61,174
One to two years		34,580		4,844		39,424
Two to three years		2,470		4,514		6,984
Three to four years		—		2,462		2,462
Four to five years		—		1,074		1,074
Over five years		—		4,193		4,193
Total lease payments	$	92,623	$	22,688	$	115,311
Less: imputed interest		(5,633)		(3,741)		(9,374)
Total operating lease liabilities	$	86,990	$	18,947	$	105,937
Current operating lease liabilities	$	51,035	$	4,704	$	55,739
Non-current operating lease liabilities		35,955		14,243		50,198
Total operating lease liabilities	$	86,990	$	18,947	$	105,937

Schedule of weighted average remaining lease term and discount rate

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

	December 31,
	2022		2021		2020
Weighted average remaining lease term	4.0	years	2.4	years	3.1	years
Weighted average discount rate	7.84	%	7.57	%	7.53	%

Schedule of other information related to operating leases

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

	Year Ended December 31,
	2022		2021		2020
Cash paid for operating lease liabilities	$	58,129	$	61,826	$	66,026
Right-of-use assets obtained in exchange for new operating lease obligations		144,134		5,992		516

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2022

Debt Disclosure [Abstract]

Schedule of long-term debt

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

	December 31,
	2022		2021
2022 Notes (matured May 2022)	$	—	$	35,000
2023 Notes (mature September 2023)		30,000		30,000
2026 Notes (mature February 2026)		200,000		200,000
MARAD Debt (matures February 2027)		40,913		48,850
Unamortized debt issuance costs		(6,838)		(8,840)
Total debt		264,075		305,010
Less current maturities		(38,200)		(42,873)
Long-term debt	$	225,875	$	262,137

Schedule of maturities of long-term debt outstanding

Scheduled maturities of our long-term debt outstanding as of December 31, 2022 are as follows (in thousands):

	2023		2026		MARAD
	Notes		Notes		Debt		Total
Less than one year	$	30,000	$	—	$	8,333	$	38,333
One to two years		—		—		8,749		8,749
Two to three years		—		—		9,186		9,186
Three to four years		—		200,000		9,644		209,644
Four to five years		—		—		5,001		5,001
Gross debt		30,000		200,000		40,913		270,913
Unamortized debt issuance costs (1)		(133)		(4,632)		(2,073)		(6,838)
Total debt		29,867		195,368		38,840		264,075
Less current maturities		(29,867)		—		(8,333)		(38,200)
Long-term debt	$	—	$	195,368	$	30,507	$	225,875

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

Schedule of components of net interest expense

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

	Year Ended December 31,
	2022		2021		2020
Interest expense	$	20,176	$	23,489	$	30,538
Capitalized interest		—		—		(1,182)
Interest income		(1,226)		(288)		(825)
Net interest expense	$	18,950	$	23,201	$	28,531

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Tax Disclosure [Abstract]

Schedule of components of income tax provision (benefit)

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

	Year Ended December 31,
	2022		2021		2020
Current tax provision (benefit):
Domestic	$	—	$	(1,103)	$	(18,927)
Foreign		8,217		7,347		4,109
Total current	$	8,217	$	6,244	$	(14,818)
Deferred tax provision (benefit):
Domestic	$	1,167	$	(5,756)	$	3,853
Foreign		3,219		(9,446)		(7,736)
Total deferred	$	4,386	$	(15,202)	$	(3,883)
Total income tax provision (benefit)	$	12,603	$	(8,958)	$	(18,701)

Schedule of components of income (loss) before income taxes

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

	Year Ended December 31,
	2022		2021		2020
Domestic	$	(13,745)	$	(53,989)	$	(3,406)
Foreign		(61,436)		(16,653)		4,789
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383

Schedule of differences between income tax provision (benefit) at U.S. statutory rate and actual income tax provision (benefit)

The primary differences between the income tax provision (benefit) at the U.S. statutory rate and our actual income tax provision (benefit) are as follows (dollars in thousands):

	Year Ended December 31,
	2022				2021				2020
Taxes at U.S. statutory rate	$	(15,788)	21.0	%	$	(14,835)	21.0	%	$	290	21.0	%
Foreign tax provision (benefit)		18,011	(24.0)			10,326	(14.6)			(4,517)	(326.7)
CARES Act		—	—			—	—			(7,596)	(549.2)
Subsidiary restructuring		—	—			—	—			(8,333)	(602.5)
Change in valuation allowance		8,110	(10.8)			(5,675)	8.0			1,091	78.9
Non-deductible expenses		2,366	(3.1)			1,487	(2.1)			1,184	85.6
Other		(96)	0.1			(261)	0.4			(820)	(59.3)
Income tax provision (benefit)	$	12,603	(16.8)	%	$	(8,958)	12.7	%	$	(18,701)	(1,352.2)	%

Schedule of deferred income taxes

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,
	2022		2021
Deferred tax liabilities:
Depreciation	$	147,302	$	137,898
Prepaid and other		1,868		1,088
Total deferred tax liabilities	$	149,170	$	138,986
Deferred tax assets:
Net operating losses	$	(53,136)	$	(56,369)
Reserves, accrued liabilities and other		(19,308)		(9,698)
Total deferred tax assets		(72,444)		(66,067)
Valuation allowance		22,157		14,047
Net deferred tax liabilities	$	98,883	$	86,966

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Revenue From Contracts With Customers (Tables)

12 Months Ended

Dec. 31, 2022

Revenue from Contract with Customer [Abstract]

Schedule of 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, 2022
Short-term	$	395,867	$	97,533	$	124,810	$	—	$	(635)	$	617,575
Long-term		128,374		94,388		—		82,315		(49,552)		255,525
Total	$	524,241	$	191,921	$	124,810	$	82,315	$	(50,187)	$	873,100
Year ended December 31, 2021
Short-term	$	308,734	$	89,668	$	—	$	—	$	(627)	$	397,775
Long-term		207,830		47,627		—		69,348		(47,852)		276,953
Total	$	516,564	$	137,295	$	—	$	69,348	$	(48,479)	$	674,728
Year ended December 31, 2020
Short-term	$	206,812	$	117,439	$	—	$	—	$	—	$	324,251
Long-term		332,437		60,579		—		58,303		(42,015)		409,304
Total	$	539,249	$	178,018	$	—	$	58,303	$	(42,015)	$	733,555

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Schedule of computations of basic and diluted EPS

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):

	Year Ended December 31,
	2022			2021			2020
	Income		Shares	Income		Shares	Income		Shares
Basic:
Net income (loss) attributable to common shareholders	$	(87,784)		$	(61,538)		$	22,174
Less: Undistributed earnings allocated to participating securities		—			—			(140)
Less: Accretion of redeemable noncontrolling interests		—			(241)			(2,400)
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Diluted:
Net income (loss) available to common shareholders, basic	$	(87,784)	151,276	$	(61,779)	150,056	$	19,634	148,993
Effect of dilutive securities:
Share-based awards other than participating securities		—	—		—	—		—	904
Undistributed earnings reallocated to participating securities		—	—		—	—		1	—
Net income (loss) available to common shareholders, diluted	$	(87,784)	151,276	$	(61,779)	150,056	$	19,635	149,897

Schedule of shares excluded from diluted EPS calculation

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,
	2022	2021
Diluted shares (as reported)	151,276	150,056
Share-based awards	2,158	1,282
Total	153,434	151,338

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,
	2022	2021	2020
2022 Notes	600	2,519	6,537
2023 Notes	3,168	3,168	9,391
2026 Notes	28,676	28,676	10,891

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2022

Share-based Payment Arrangement [Abstract]

Schedule of grants of share-based awards

The following grants of share-based awards were made in 2022 under the 2005 Incentive Plan:

			Grant Date
			Fair Value
Date of Grant	Award Type	Shares/Units	Per Share/Unit		Vesting Period
January 1, 2022 (1)	RSU	1,065,705	$	3.12	33% per year over three years
January 4, 2022 (1)	PSU	1,065,705	$	4.25	100% on January 4, 2025
January 4, 2022 (2)	Restricted stock	15,775	$	3.12	100% on January 1, 2024
April 1, 2022 (2)	Restricted stock	14,710	$	4.78	100% on January 1, 2024
July 1, 2022 (2)	Restricted stock	14,867	$	3.10	100% on January 1, 2024
September 22, 2022 (3)	Restricted stock	19,328	$	4.38	100% on September 22, 2023
October 1, 2022 (2)	Restricted stock	12,796	$	3.86	100% on January 1, 2024
December 7, 2022 (2)	Restricted stock	175,882	$	5.97	100% on December 7, 2023

(1) Reflects grants to our executive officers.

(2) Reflects grants to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash, of which 8,013 shares granted on January 4, 2022 and 5,230 shares granted on April 1, 2022 vested upon the approval of our Board’s Compensation Committee in connection with the departure of an independent director during the second quarter 2022.

(3) Reflects restricted stock grants made to two new independent members of our Board in connection with their appointment to our Board.

Summary of information about restricted stock

The following table summarizes information about our restricted stock:

	Year Ended December 31,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Shares	Fair Value (1)		Shares	Fair Value (1)		Shares	Fair Value (1)
Awards outstanding at beginning of year	853,726	$	5.62	1,176,951	$	6.61	1,173,045	$	6.81
Granted	253,358		5.33	332,841		3.59	667,752		7.06
Vested (2)	(719,456)		4.94	(656,066)		6.35	(631,498)		7.52
Forfeited	—		—	—		—	(32,348)		5.41
Awards outstanding at end of year	387,628	$	6.70	853,726	$	5.62	1,176,951	$	6.61

(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) Total fair value of restricted stock that vested during the years ended December 31, 2022, 2021 and 2020 was $2.9 million, $2.6 million and $5.4 million, respectively.

Summary of information about PSU awards

The following table summarizes information about our PSU awards:

	Year Ended December 31,
	2022			2021			2020
		Grant Date			Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)		Units	Fair Value (1)
PSU awards outstanding at beginning of year	1,381,469	$	8.34	1,297,126	$	9.99	1,565,044	$	10.17
Granted	1,065,705		4.25	452,381		5.33	369,938		13.15
Vested	(559,150)		7.60	(368,038)		10.44	(589,335)		12.64
Forfeited	—		—	—		—	(48,521)		7.60
PSU awards outstanding at end of year	1,888,024	$	6.25	1,381,469	$	8.34	1,297,126	$	9.99

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

Summary of information about RSU awards

The following table summarizes information about our RSU awards:

	Year Ended December 31,
	2022			2021
		Grant Date			Grant Date
	Units	Fair Value (1)		Units	Fair Value (1)
RSU awards outstanding at beginning of year	452,381	$	4.20	—	$	—
Granted	1,065,705		3.12	452,381		4.20
Vested	(150,792)		4.20	—		—
RSU awards outstanding at end of year	1,367,294	$	3.36	452,381	$	4.20

(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.

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Business Segment Information (Tables)

12 Months Ended

Dec. 31, 2022

Segment Reporting [Abstract]

Schedule of financial data by reportable segment

Certain financial data by reportable segment are summarized as follows (in thousands):

	Year Ended December 31,
	2022		2021		2020
Net revenues —
Well Intervention	$	524,241	$	516,564	$	539,249
Robotics		191,921		137,295		178,018
Shallow Water Abandonment		124,810		—		—
Production Facilities		82,315		69,348		58,303
Intercompany eliminations		(50,187)		(48,479)		(42,015)
Total	$	873,100	$	674,728	$	733,555
Income (loss) from operations —
Well Intervention	$	(53,056)	$	(35,882)	$	26,855
Robotics		29,981		5,762		13,755
Shallow Water Abandonment		22,184		—		—
Production Facilities		27,201		22,906		15,975
Segment operating income (loss)		26,310		(7,214)		56,585
Goodwill impairment (1)		—		—		(6,689)
Change in fair value of contingent consideration		(16,054)		—		—
Corporate, eliminations and other		(55,111)		(41,473)		(36,871)
Total	$	(44,855)	$	(48,687)	$	13,025
Net interest expense		(18,950)		(23,201)		(28,531)
Other non-operating income (expense), net		(11,376)		1,246		16,889
Income (loss) before income taxes	$	(75,181)	$	(70,642)	$	1,383
Capital expenditures —
Well Intervention	$	17,617	$	2,349	$	19,523
Robotics		15,603		120		257
Shallow Water Abandonment		532		—		—
Production Facilities		(1,424)		6,770		—
Corporate, eliminations and other		1,176		(917)		464
Total	$	33,504	$	8,322	$	20,244
Depreciation and amortization —
Well Intervention	$	103,952	$	107,551	$	101,756
Robotics		12,209		15,158		15,952
Shallow Water Abandonment		8,172		—		—
Production Facilities		18,520		19,465		15,652
Corporate and eliminations		(167)		(660)		349
Total	$	142,686	$	141,514	$	133,709

(1) Relates to the impairment of the entire STL goodwill balance (Note 3).

Schedule of intercompany segment revenues

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,
	2022		2021		2020
Well Intervention	$	16,545	$	21,521	$	15,039
Robotics		33,642		26,958		26,976
Total	$	50,187	$	48,479	$	42,015

Schedule of revenue by individually significant geographic location

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

	Year Ended December 31,
	2022		2021		2020
U.S.	$	447,205	$	232,661	$	304,563
U.K.		166,980		100,154		133,005
Brazil		81,940		154,326		208,565
West Africa		87,488		126,856		41,840
Other		89,487		60,731		45,582
Total	$	873,100	$	674,728	$	733,555

Schedule of property and equipment, net of accumulated depreciation, by individually significant geographic location

The following table provides our property and equipment, net of accumulated depreciation, by individually significant geographic location where those assets are based (in thousands):

	December 31,
	2022		2021
U.S.	$	780,803	$	693,062
U.K. (1)		625,001		713,385
Brazil (2)		235,811		251,194
Other		—		4
Total	$	1,641,615	$	1,657,645

(1) Includes the Q7000 and certain other assets that are based in the U.K. but have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

(2) Includes the equipment on the Siem Helix 1 chartered vessel and certain other assets that are based in Brazil but are have operated in West Africa and may also operate in the North Sea, Asia Pacific and other regions.

Schedule of total assets by reportable segment

The following table reflects total assets by reportable segment (in thousands):

	December 31,
	2022		2021
Well Intervention	$	1,796,269	$	2,012,214
Robotics		192,694		96,249
Shallow Water Abandonment		206,944		—
Production Facilities		136,382		119,004
Corporate and other		57,049		98,561
Total	$	2,389,338	$	2,326,028

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation Disclosure [Abstract]

Schedule of asset retirement obligations

The following table describes the changes in our AROs (in thousands):

	2022		2021		2020
AROs at January 1,	$	29,658	$	30,913	$	28,258
Liability incurred during the period		23,601		—		—
Revisions in estimates		(3,285)		(2,631)		—
Accretion expense		1,982		1,376		2,655
AROs at December 31,	$	51,956	$	29,658	$	30,913

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Statement Of Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2022

Supplemental Cash Flow Information [Abstract]

Schedule of supplemental cash flow information

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

	Year Ended December 31,
	2022		2021		2020
Interest paid	$	18,267	$	20,719	$	15,943
Income taxes paid (1)		9,516		8,310		7,434

(1) Exclusive of income tax refunds. During the years ended December 31, 2022 and 2021, we received refunds related to the CARES Act of $1.1 million and $18.9 million, respectively.

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Allowance Accounts (Tables)

12 Months Ended

Dec. 31, 2022

Credit Loss [Abstract]

Schedule of activities in allowance for credit losses and deferred tax assets

The following table sets forth the activity in our valuation accounts for each of the three years in the period ended December 31, 2022 (in thousands):

	Allowance for		Deferred Tax Asset
	Credit Losses		Valuation Allowance
Balance at December 31, 2019	$	—	$	18,631
Additions (reductions) (1)		2,684		—
Adjustments (2)		785		1,091
Balance at December 31, 2020		3,469		19,722
Additions (reductions) (1)		(146)		—
Write-offs (3)		(1,846)
Adjustments (4)		—		(5,675)
Balance at December 31, 2021		1,477		14,047
Additions (reductions) (1)		800		—
Adjustments (5)		—		8,110
Balance at December 31, 2022	$	2,277	$	22,157

(1) Additions (reductions) in allowance for credit losses reflect credit loss reserves (releases) during the respective years, including a $1.7 million credit loss reserve in 2020 related to a receivable in our Robotics segment. Additions during 2022 primarily reflected adjustments to the allowance for credit losses due to increases in our expected credit losses as a result of the Alliance acquisition.

(2) The adjustment in allowance for credit losses reflects provision for current expected credit losses upon the adoption of ASU No. 2016-13 on January 1, 2020.

(3) The write-offs of allowance for credit losses reflect certain receivables related to our Robotics segment that were previously reserved and subsequently deemed to be uncollectible.

(4) The decrease in valuation allowance primarily relates to the valuation allowance release for certain of our U.K. operations.

(5) The increase in valuation allowance relates to current year activity and the related change in unrealizable net deferred tax assets.

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of financial instruments measured at fair value on a recurring basis

The following table sets forth our assets and liabilities that are measured at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value at December 31, 2022
	Level 1		Level 2		Level 3		Total
Liabilities:
Contingent consideration		—		—		42,754		42,754

Schedule of changes in the fair value of contingent consideration

The changes in the fair value of contingent consideration are as follows:

	2022
Balance at July 1,	$	26,700
Change in fair value		16,054
Balance at December 31,	$	42,754

Schedule of principal amount and estimated fair value of long-term debt

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

	December 31, 2022				December 31, 2021
	Principal		Fair		Principal		Fair
	Amount (1)		Value (2)		Amount (1)		Value (2)
MARAD Debt (matures February 2027)	$	40,913	$	40,940	$	48,850	$	52,481
2022 Notes (matured May 2022)		—		—		35,000		34,794
2023 Notes (mature September 2023)		30,000		31,149		30,000		29,054
2026 Notes (mature February 2026)		200,000		277,014		200,000		200,562
Total debt	$	270,913	$	349,103	$	313,850	$	316,891

(1) Principal amount includes current maturities and excludes any related unamortized debt issuance costs. See Note 7 for additional disclosures on our long-term debt.

(2) The estimated fair value of the 2022 Notes, the 2023 Notes and the 2026 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.

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Organization - Company Overview (Details)	6 Months Ended
	Dec. 31, 2022 item segment	Jun. 30, 2022 segment
Business Segment Information
Number of reportable segments | segment	4	3
Well Intervention
Business Segment Information
Number of long-term chartered vessels | item	2

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Summary Of Significant Accounting Policies - Restricted Cash (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 2,507	$ 73,612
Letter of Credit
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash		71,100
ABL Facility Maturing September 2026
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash	$ 2,500	$ 2,500

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Summary Of Significant Accounting Policies - Equity Investment (Details) - Independence Hub, LLC - USD ($) $ in Millions	1 Months Ended
	May 31, 2022	Dec. 31, 2022
Schedule of Equity Method Investments [Line Items]
Distribution from equity investment, net	$ 7.8
Production Facilities
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest		20.00%

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Summary Of Significant Accounting Policies - Deferred Recertification And Dry Dock Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Recertification and dry dock amortization expense	$ 14.0	$ 14.6	$ 14.3
Minimum
Finite-Lived Intangible Assets [Line Items]
Recertification and dry dock amortization period	24 months
Recertification process period	1 month
Maximum
Finite-Lived Intangible Assets [Line Items]
Recertification and dry dock amortization period	60 months
Recertification process period	3 months

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Summary Of Significant Accounting Policies - Foreign Currency (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Foreign currency transaction gains (losses)	$ (23.4)	$ (1.5)	$ 4.6

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Summary Of Significant Accounting Policies - Major Customers And Concentration Of Risk (Details) - Customer Concentration Risk - Revenue Benchmark	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Petrobras
Revenue, Major Customer [Line Items]
Percentage of concentration risk		23.00%	28.00%
BP
Revenue, Major Customer [Line Items]
Percentage of concentration risk			17.00%
Shell
Revenue, Major Customer [Line Items]
Percentage of concentration risk	15.00%	17.00%

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Summary Of Significant Accounting Policies - New Accounting Standards (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Long-term debt	$ 264,075	$ 305,010
Common stock	1,298,740	1,292,479
Retained earnings	323,288	411,072
Allowance for credit losses	2,277	1,477	$ 3,469
Deferred tax liabilities	98,883	86,966
Net interest expense	$ (18,950)	(23,201)	(28,531)
Accounting Standards Update 2016-13 | Cumulative Effect, Period of Adoption
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings				$ (600)
Tax effect of credit losses				(200)
Allowance for credit losses				$ 700
Accounting Standards Update 2020-06
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Net interest expense		$ (7,600)
Accounting Standards Update 2020-06 | Cumulative Effect, Period of Adoption
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Long-term debt			44,100
Common stock			(41,500)
Retained earnings			6,700
Deferred tax liabilities			$ (9,300)

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Business Combinations (Details) - Alliance Acquisition (Details) - Alliance $ in Thousands	Jul. 01, 2022 USD ($)
Business Acquisition [Line Items]
Total consideration for business acquisition	$ 145,661
Cash paid to acquire companies	118,961
Post-closing earn-out consideration payable	26,700
Estimated fair values of the identifiable assets acquired and liabilities assumed
Cash consideration	118,961
Contingent consideration	26,700
Total fair value of consideration transferred	145,661
Assets acquired:
Cash and cash equivalents	6,336
Accounts receivable	43,378
Other current assets	6,077
Property and equipment	117,321
Operating lease right-of-use assets	1,205
Intangible assets	1,500
Other assets	2,133
Total assets acquired	177,950
Liabilities assumed:
Accounts payable	20,480
Accrued liabilities	3,073
Operating lease liabilities	1,205
Deferred tax liabilities	7,531
Total liabilities assumed	32,289
Net assets acquired	145,661
Gross contractual accounts receivable	44,200
As Originally Reported
Business Acquisition [Line Items]
Total consideration for business acquisition	145,661
Cash paid to acquire companies	118,961
Post-closing earn-out consideration payable	26,700
Estimated fair values of the identifiable assets acquired and liabilities assumed
Cash consideration	118,961
Contingent consideration	26,700
Total fair value of consideration transferred	145,661
Assets acquired:
Cash and cash equivalents	6,336
Accounts receivable	43,378
Other current assets	4,879
Property and equipment	118,619
Operating lease right-of-use assets	1,205
Intangible assets	1,400
Other assets	2,133
Total assets acquired	177,950
Liabilities assumed:
Accounts payable	20,480
Accrued liabilities	3,073
Operating lease liabilities	1,205
Deferred tax liabilities	7,531
Total liabilities assumed	32,289
Net assets acquired	145,661
Adjustments
Assets acquired:
Other current assets	1,198
Property and equipment	(1,298)
Intangible assets	$ 100

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Business Combinations (Details) - Pro forma information (Details) - Alliance - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Revenues	$ 952,837	$ 789,051
Net loss	$ (79,686)	$ (56,203)

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Business Combinations - STL Acquisition (Details) - STL - USD ($) $ in Millions	1 Months Ended
	Jun. 30, 2021	May 31, 2019
Business Acquisition [Line Items]
Ownership interest acquired (as a percent)		70.00%
Goodwill acquired		$ 6.9
Controlling interest acquired, ownership percentage	30.00%

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Business Combinations - Changes In Carrying Amount Of Goodwill (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)
Changes in the Carrying Amount of Goodwill
Impairment loss	$ (6,689)
Well Intervention
Changes in the Carrying Amount of Goodwill
Balance at beginning of year	7,157
Impairment loss	(6,689)
Foreign currency adjustments	$ (468)

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Details Of Certain Accounts - Other Current Assets (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaids	$ 26,609	$ 18,228
Income tax receivable		1,116
Contract assets	6,295	639
Deferred costs	13,969	2,967
Other receivable		28,805
Other	11,826	6,519
Total other current assets	$ 58,699	$ 58,274

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Details Of Certain Accounts - Other Assets, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid charter	$ 12,544	$ 12,544
Deferred costs	6,432	381
Other receivable	24,827
Intangible assets with finite lives, net	4,465	3,472
Other	2,239	1,967
Total other assets, net	$ 50,507	$ 18,364

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Details Of Certain Accounts - Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Accrued payroll and related benefits	$ 41,339	$ 28,657
Accrued interest	6,306	6,746
Income tax payable	479
Deferred revenue	9,961	8,272
Asset retirement obligations		29,658
Other	15,489	18,379
Total accrued liabilities	$ 73,574	$ 91,712

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Details Of Certain Accounts - Other Non-Current Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Deferred revenue		$ 476
Asset retirement obligations	$ 51,956
Contingent consideration	42,754
Other	520	499
Total other non-current liabilities	$ 95,230	$ 975

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Property And Equipment - Gross Components Of Property And Equipment (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Property and equipment	$ 3,016,312	$ 2,938,154
Vessels
Property, Plant and Equipment [Line Items]
Property and equipment	$ 2,371,084	2,343,162
Vessels | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	15 years
Vessels | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	30 years
ROVs and Trenchers
Property, Plant and Equipment [Line Items]
Property and equipment	$ 262,763	257,274
ROVs and Trenchers | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
ROVs and Trenchers | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	10 years
Machinery, Equipment, Buildings and Other
Property, Plant and Equipment [Line Items]
Property and equipment	$ 382,465	$ 337,718
Machinery, Equipment, Buildings and Other | Minimum
Property, Plant and Equipment [Line Items]
Estimated useful life	5 years
Machinery, Equipment, Buildings and Other | Maximum
Property, Plant and Equipment [Line Items]
Estimated useful life	39 years

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Leases - Narrative (Details) $ in Millions	Dec. 31, 2022 USD ($)
Leases [Abstract]
Minimum sublease income to be received in the future	$ 1.3

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Leases - Components Of Lease Cost (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Lease, Cost [Abstract]
Operating lease cost	$ 61,067	$ 60,636	$ 64,742
Variable lease cost	20,562	16,711	15,021
Short-term lease cost	29,487	20,590	37,524
Sublease income	(1,275)	(1,303)	(1,286)
Net lease cost	$ 109,841	$ 96,634	$ 116,001

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Leases - Maturities Of Operating Lease Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Lessee, Operating Lease, Liability, Payment, Due, Rolling Maturity [Abstract]
Less than one year	$ 64,666	$ 61,174
One to two years	61,212	39,424
Two to three years	46,197	6,984
Three to four years	36,159	2,462
Four to five years	27,203	1,074
Over five years	5,824	4,193
Total lease payments	241,261	115,311
Less: imputed interest	(35,661)	(9,374)
Total operating lease liabilities	205,600	105,937
Current operating lease liabilities	50,914	55,739
Non-current operating lease liabilities	154,686	50,198
Vessels
Lessee, Operating Lease, Liability, Payment, Due, Rolling Maturity [Abstract]
Less than one year	58,063	55,573
One to two years	55,515	34,580
Two to three years	43,400	2,470
Three to four years	35,200
Four to five years	26,244
Over five years	3,041
Total lease payments	221,463	92,623
Less: imputed interest	(32,986)	(5,633)
Total operating lease liabilities	188,477	86,990
Current operating lease liabilities	45,131	51,035
Non-current operating lease liabilities	143,346	35,955
Facilities and Equipment
Lessee, Operating Lease, Liability, Payment, Due, Rolling Maturity [Abstract]
Less than one year	6,603	5,601
One to two years	5,697	4,844
Two to three years	2,797	4,514
Three to four years	959	2,462
Four to five years	959	1,074
Over five years	2,783	4,193
Total lease payments	19,798	22,688
Less: imputed interest	(2,675)	(3,741)
Total operating lease liabilities	17,123	18,947
Current operating lease liabilities	5,783	4,704
Non-current operating lease liabilities	$ 11,340	$ 14,243

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Leases - Weighted Average Remaining Lease Term And Discount Rate (Details)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Weighted average remaining lease term (in years)	4 years	2 years 4 months 24 days	3 years 1 month 6 days
Weighted average discount rate (as a percent)	7.84%	7.57%	7.53%

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Leases - Other Information Related To Operating Leases (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Cash paid for operating lease liabilities	$ 58,129	$ 61,826	$ 66,026
Right-of-use assets obtained in exchange for new operating lease obligations	$ 144,134	$ 5,992	$ 516

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Long-Term Debt - Schedule Of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Principal Amount	$ 270,913
Unamortized debt issuance costs	(6,838)	$ (8,840)
Total debt	264,075	305,010
Less: current maturities	(38,200)	(42,873)
Long-term debt	225,875	262,137
2022 Notes (matured May 2022)
Debt Instrument [Line Items]
Principal Amount		35,000
2023 Notes (mature September 2023)
Debt Instrument [Line Items]
Principal Amount	30,000	30,000
Unamortized debt issuance costs	(133)
Total debt	29,867
Less: current maturities	(29,867)
2026 Notes (mature February 2026)
Debt Instrument [Line Items]
Principal Amount	200,000	200,000
Unamortized debt issuance costs	(4,632)
Total debt	195,368
Long-term debt	195,368
MARAD Debt (matures February 2027)
Debt Instrument [Line Items]
Principal Amount	40,913	$ 48,850
Unamortized debt issuance costs	(2,073)
Total debt	38,840
Less: current maturities	(8,333)
Long-term debt	$ 30,507

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Long-Term Debt - Credit Agreement (Details) - ABL Facility Maturing September 2026 $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Borrowing capacity	$ 100.0
Maturity date	Sep. 30, 2026
Springing maturity period	91 days
Outstanding principal amount with a springing maturity	$ 50.0
Additional commitments (up to)	50.0
Sub-limit for the issuance of letters of credit	10.0
Borrowings under ABL Facility	0.0
Available borrowing capacity	98.1
Letters of credit issued	1.9
Pro Forma
Debt Instrument [Line Items]
Available borrowing capacity	$ 20.0
Available borrowing capacity (as a percent of borrowing base)	10.00%
Permitted debt for the deferred purchase price of property	$ 50.0
Availability of the borrowing base to satisfy and maintain fixed charge ratio	$ 10.0
Period prior to maturity to maintain a pro forma minimum excess availability	91 days
Minimum
Debt Instrument [Line Items]
Commitment fee percentage	0.375%
Fixed charge coverage ratio	1.0
Maximum
Debt Instrument [Line Items]
Commitment fee percentage	0.50%
United States
Debt Instrument [Line Items]
Borrowing capacity	$ 65.0
United States | SOFR | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.50%
United States | SOFR | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.00%
United States | Base Rate | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	0.50%
United States | Base Rate | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.00%
United Kingdom
Debt Instrument [Line Items]
Borrowing capacity	$ 35.0
United Kingdom | SOFR
Debt Instrument [Line Items]
Adjustment on variable rate (as a percent)	0.10%
United Kingdom | SONIA | Minimum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	1.50%
United Kingdom | SONIA | Maximum
Debt Instrument [Line Items]
Basis spread on variable rate (as a percent)	2.00%

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Long-Term Debt - Convertible Senior Notes Due 2022 (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	May 01, 2022
Debt Instrument [Line Items]
Interest expense	$ 20,176	$ 23,489	$ 30,538
Amortization of debt issuance costs	2,334	3,179	3,177
2022 Notes (matured May 2022)
Debt Instrument [Line Items]
Repurchased principal amount				$ 35,000
Effective interest rate (as a percent)				4.80%
Repurchase amount			90,000
Interest expense	$ 600	$ 1,700	6,600
Coupon interest expense			3,900
Amortization of debt discount and issuance costs			$ 2,700

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Long-Term Debt - Convertible Senior Notes Due 2023 (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Debt Instrument [Line Items]
Interest expense	$ 20,176,000	$ 23,489,000	$ 30,538,000
Amortization of debt issuance costs	$ 2,334,000	3,179,000	3,177,000
2023 Notes (mature September 2023)
Debt Instrument [Line Items]
Interest rate (as a percent)	4.125%
Frequency of periodic payment	semi-annually
Maturity date	Sep. 15, 2023
Initial conversion ratio	0.1056133
Aggregate number of shares | shares	3,168,399
Initial conversion price per share (USD per share) | $ / shares	$ 9.47
Increase in the conversion rate	0.0475260
Redemption price as a percentage of principal amount	100.00%
Repurchase amount			95,000,000
Effective interest rate (as a percent)	4.80%
Interest expense	$ 1,400,000	$ 1,400,000	6,600,000
Coupon interest expense			3,700,000
Amortization of debt discount and issuance costs			$ 2,900,000
2023 Notes (mature September 2023) | Maximum
Debt Instrument [Line Items]
Percentage of closing price of common stock to conversion price	130.00%
Number of trading days	20
Number of consecutive trading days	30
2023 Notes (mature September 2023) | Minimum
Debt Instrument [Line Items]
Percentage of closing price of common stock to conversion price	97.00%
Number of trading days	5
Number of consecutive trading days	10

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Long-Term Debt - Convertible Senior Notes Due 2026 (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) $ / shares
Debt Instrument [Line Items]
Interest expense	$ 20,176,000	$ 23,489,000	$ 30,538,000
Amortization of debt issuance costs	$ 2,334,000	3,179,000	$ 3,177,000
2026 Capped Calls
Debt Instrument [Line Items]
Initial cap price | $ / shares	$ 8.42		$ 8.42
2026 Notes (mature February 2026)
Debt Instrument [Line Items]
Interest rate (as a percent)	6.75%
Maturity date	Feb. 15, 2026
Frequency of periodic payment	semi-annually
Initial conversion ratio	0.1433795
Aggregate number of shares | shares	28,675,900
Initial conversion price per share (USD per share) | $ / shares	$ 6.97
Increase in the conversion rate	0.0645207
Redemption price as a percentage of principal amount	100.00%
Effective interest rate (as a percent)	7.60%
Interest expense	$ 14,800,000	14,700,000	$ 7,500,000
Coupon interest expense	13,500,000	13,500,000	5,100,000
Amortization of debt issuance costs	$ 1,300,000	$ 1,200,000
Amortization of debt discount and issuance costs			$ 2,400,000
2026 Notes (mature February 2026) | Maximum
Debt Instrument [Line Items]
Percentage of closing price of common stock to conversion price	130.00%
Number of trading days	20
Number of consecutive trading days	30
2026 Notes (mature February 2026) | Minimum
Debt Instrument [Line Items]
Percentage of closing price of common stock to conversion price	97.00%
Number of trading days	5
Number of consecutive trading days	10

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Long-Term Debt - MARAD Debt (Details) - MARAD Debt (matures February 2027)	12 Months Ended
	Dec. 31, 2022
Debt Instrument [Line Items]
Guarantor obligations (as a percent)	50.00%
Frequency of periodic payment	semi-annual
Maturity date	February 2027
Interest rate (as a percent)	4.93%

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Long-Term Debt - Other (Details) - USD ($) $ in Millions	1 Months Ended
	Sep. 30, 2021	Jan. 31, 2021
Revolving Credit Facility Previously Maturing December 2021
Debt Instrument [Line Items]
Borrowing capacity	$ 175.0
Maturity date	Dec. 31, 2021
Borrowings under Revolving Credit Facility	$ 0.0
Term Loan Repaid September 2021
Debt Instrument [Line Items]
Remaining principal amount repaid	$ 28.0
Nordea Q5000 Loan Matured January 2021
Debt Instrument [Line Items]
Balloon payment		$ 53.6

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Long-Term Debt - Maturities Of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Less than one year	$ 38,333
One to two years	8,749
Two to three years	9,186
Three to four years	209,644
Four to five years	5,001
Gross debt	270,913
Unamortized debt issuance costs	(6,838)	$ (8,840)
Total debt	264,075	305,010
Less: current maturities	(38,200)	(42,873)
Long-term debt	225,875	262,137
2023 Notes (mature September 2023)
Debt Instrument [Line Items]
Less than one year	30,000
Gross debt	30,000	30,000
Unamortized debt issuance costs	(133)
Total debt	29,867
Less: current maturities	(29,867)
2026 Notes (mature February 2026)
Debt Instrument [Line Items]
Three to four years	200,000
Gross debt	200,000	200,000
Unamortized debt issuance costs	(4,632)
Total debt	195,368
Long-term debt	195,368
MARAD Debt (matures February 2027)
Debt Instrument [Line Items]
Less than one year	8,333
One to two years	8,749
Two to three years	9,186
Three to four years	9,644
Four to five years	5,001
Gross debt	40,913	$ 48,850
Unamortized debt issuance costs	(2,073)
Total debt	38,840
Less: current maturities	(8,333)
Long-term debt	$ 30,507

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Long-Term Debt - Components Of Net Interest Expense (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Debt Disclosure [Abstract]
Interest expense	$ 20,176	$ 23,489	$ 30,538
Capitalized interest			(1,182)
Interest income	(1,226)	(288)	(825)
Net interest expense	$ 18,950	$ 23,201	$ 28,531

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Income Taxes - Schedule Of Components Of Income Tax Provision (Benefit) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current tax provision (benefit):
Domestic		$ (1,103)	$ (18,927)
Foreign	$ 8,217	7,347	4,109
Total current	8,217	6,244	(14,818)
Deferred tax provision (benefit):
Domestic	1,167	(5,756)	3,853
Foreign	3,219	(9,446)	(7,736)
Total deferred	4,386	(15,202)	(3,883)
Income tax provision (benefit)	$ 12,603	$ (8,958)	$ (18,701)

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Income Taxes - Schedule Of Components Of Income (Loss) Before Income Taxes (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Domestic	$ (13,745)	$ (53,989)	$ (3,406)
Foreign	(61,436)	(16,653)	4,789
Income (loss) before income taxes	$ (75,181)	$ (70,642)	$ 1,383

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Income Taxes - Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Effective Income Tax Rate Reconciliation, Amount [Abstract]
Taxes at U.S. statutory rate	$ (15,788)	$ (14,835)	$ 290
Foreign tax provision (benefit)	18,011	10,326	(4,517)
CARES Act			(7,596)
Subsidiary restructuring			(8,333)
Change in valuation allowance	8,110	(5,675)	1,091
Non-deductible expenses	2,366	1,487	1,184
Other	(96)	(261)	(820)
Income tax provision (benefit)	$ 12,603	$ (8,958)	$ (18,701)
Effective Income Tax Rate Reconciliation, Percent [Abstract]
Taxes at U.S. statutory rate	21.00%	21.00%	21.00%
Foreign taxes	(24.00%)	(14.60%)	(326.70%)
CARES Act			(549.20%)
Subsidiary restructuring			(602.50%)
Change in valuation allowance	(10.80%)	8.00%	78.90%
Non-deductible expenses	(3.10%)	(2.10%)	85.60%
Other	0.10%	0.40%	(59.30%)
Effective tax rate	(16.80%)	12.70%	(1352.20%)

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Income Taxes - Narrative (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) subsidiary
Income Tax Disclosure [Abstract]
Tax loss carryback period prior to CARES Act.			3 years
Tax loss carryback period after CARES Act enacted.			5 years
Net tax benefit from CARES Act			$ 7,600
Current tax benefit from CARES Act			18,900
Deferred tax expense from CARES Act			$ 11,300
Number of foreign subsidiaries | subsidiary			2
Net deferred tax benefit from foreign subsidiary restructuring			$ 8,300
Undistributed earnings of foreign subsidiaries	$ 78,900
Unrecognized tax benefits related to uncertain tax positions	100
Expiration of uncertain tax positions			600
Operating Loss Carryforwards [Line Items]
Valuation allowance increase (release)	8,110	$ (5,675)	$ 1,091
Tax credits	4,200
U.S.
Operating Loss Carryforwards [Line Items]
Net operating loss carryforward	163,100
Net operating loss carryforwards subject to expiration	74,500
Net operating loss carryforwards not subject to expiration	88,600
Foreign
Operating Loss Carryforwards [Line Items]
Valuation allowance increase (release)		$ (5,000)
Net operating loss carryforward	69,700
Tax credits	$ 3,000

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Income Taxes - Schedule Of Deferred Tax Assets And Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Deferred tax liabilities:
Depreciation	$ 147,302	$ 137,898
Prepaid and other	1,868	1,088
Total deferred tax liabilities	149,170	138,986
Deferred tax assets:
Net operating losses	(53,136)	(56,369)
Reserves, accrued liabilities and other	(19,308)	(9,698)
Total deferred tax assets	(72,444)	(66,067)
Valuation allowance	22,157	14,047	$ 19,722	$ 18,631
Net deferred tax liabilities	$ 98,883	$ 86,966

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Shareholders' Equity - Narrative (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2020	Dec. 31, 2021
Stockholders' Equity Note [Abstract]
Common stock, shares authorized	240,000,000		240,000,000
Common stock, par value (USD per share)	$ 0		$ 0
Preferred stock, shares authorized	5,000,000
Preferred stock, par value per share (in dollars per share)	$ 0.01
Option Indexed to Issuer's Equity [Line Items]
Aggregate cost of capped call transactions		$ 10,625
2026 Capped Calls
Option Indexed to Issuer's Equity [Line Items]
Aggregate number of common shares subject to capped calls		28,675,900
Initial strike price		$ 6.97
Initial cap price	$ 8.42	$ 8.42
Aggregate cost of capped call transactions		$ 10,600

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Share Repurchase Programs (Details) - USD ($) $ in Millions	Feb. 20, 2023	Dec. 31, 2022
Previously Authorized Share Repurchase Program
Share Repurchase Programs
Remaining number of shares available to be repurchased (in shares)		9,547,027
New Share Repurchase Program | Subsequent Event
Share Repurchase Programs
Authorized repurchase amount	$ 200

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Revenue From Contracts With Customers - Disaggregation Of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue From Contracts With Customers
Net revenues	$ 873,100	$ 674,728	$ 733,555
Intercompany Eliminations
Revenue From Contracts With Customers
Net revenues	(50,187)	(48,479)	(42,015)
Well Intervention
Revenue From Contracts With Customers
Net revenues	524,241	516,564	539,249
Well Intervention | Intercompany Eliminations
Revenue From Contracts With Customers
Net revenues	(16,545)	(21,521)	(15,039)
Robotics
Revenue From Contracts With Customers
Net revenues	191,921	137,295	178,018
Robotics | Intercompany Eliminations
Revenue From Contracts With Customers
Net revenues	(33,642)	(26,958)	(26,976)
Shallow Water Abandonment
Revenue From Contracts With Customers
Net revenues	124,810
Production Facilities
Revenue From Contracts With Customers
Net revenues	82,315	69,348	58,303
Short-term
Revenue From Contracts With Customers
Net revenues	617,575	397,775	324,251
Short-term | Intercompany Eliminations
Revenue From Contracts With Customers
Net revenues	(635)	(627)
Short-term | Well Intervention
Revenue From Contracts With Customers
Net revenues	395,867	308,734	206,812
Short-term | Robotics
Revenue From Contracts With Customers
Net revenues	97,533	89,668	117,439
Short-term | Shallow Water Abandonment
Revenue From Contracts With Customers
Net revenues	124,810
Long-term
Revenue From Contracts With Customers
Net revenues	255,525	276,953	409,304
Long-term | Intercompany Eliminations
Revenue From Contracts With Customers
Net revenues	(49,552)	(47,852)	(42,015)
Long-term | Well Intervention
Revenue From Contracts With Customers
Net revenues	128,374	207,830	332,437
Long-term | Robotics
Revenue From Contracts With Customers
Net revenues	94,388	47,627	60,579
Long-term | Production Facilities
Revenue From Contracts With Customers
Net revenues	$ 82,315	$ 69,348	$ 58,303

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Revenue From Contracts With Customers - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Contract assets	$ 6.3	$ 0.6
Credit losses on contract assets	0.0	0.0	$ 0.0
Contract liabilities	10.0	8.7
Revenue recognized	7.4	7.9	11.6
Deferred contract costs	20.4	3.3
Amortization of deferred contract costs	29.7	39.1	35.8
Impairment losses on deferred contract costs	0.0	$ 0.0	$ 0.0
Revenue From Contracts With Customers
Unsatisfied performance obligations	846.7
Revenue related to performance obligation satisfied in previous years	1.0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue From Contracts With Customers
Unsatisfied performance obligations	$ 532.6
Expected timing of satisfaction	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue From Contracts With Customers
Unsatisfied performance obligations	$ 314.1
Expected timing of satisfaction	1 year

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Earnings Per Share - Computations Of Basic And Diluted EPS (Details) - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Basic:
Net loss attributable to common shareholders	$ (87,784)	$ (61,538)	$ 22,174
Less: Undistributed earnings allocated to participating securities			(140)
Less: Accretion of redeemable noncontrolling interests		(241)	(2,400)
Net loss available to common shareholders, basic	$ (87,784)	$ (61,779)	$ 19,634
Weighted average number of shares outstanding, basic (in shares)	151,276	150,056	148,993
Effect of dilutive securities:
Share-based awards other than participating securities (in shares)			904
Undistributed earnings reallocated to participating securities			$ 1
Net loss available to common shareholders, diluted	$ (87,784)	$ (61,779)	$ 19,635
Weighted average number of shares outstanding, diluted (in shares)	151,276	150,056	149,897

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Earnings Per Share - Shares Included in Diluted Calculations Assuming Earnings (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share [Abstract]
Diluted shares (as reported)	151,276	150,056	149,897
Share-based awards	2,158	1,282
Total	153,434	151,338

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Earnings Per Share - Potentially Dilutive Shares Excluded From Diluted EPS Calculation (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
2022 Notes
Earnings Per Share
Antidilutive securities (in shares)	600	2,519	6,537
2023 Notes
Earnings Per Share
Antidilutive securities (in shares)	3,168	3,168	9,391
2026 Notes
Earnings Per Share
Antidilutive securities (in shares)	28,676	28,676	10,891

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Employee Benefit Plans - Defined Contribution Plan (Details) - 401(k) Plan - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employer matching contribution (as a percent)	50.00%
Employer matching contribution percent of employees' salary (up to)	5.00%
Plan cost recognized	$ 1.5	$ 1.6

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Employee Benefit Plans - Employee Stock Purchase Plan (Details) - ESPP	12 Months Ended
	Dec. 31, 2022 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares available for issuance (in shares)	1,400,000
Period common stock may be purchased through payroll deductions	4 months
Percentage of share of non-vested stock considered as call option	85.00%
Purchase limit per employee (in shares)	260

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Employee Benefit Plans - Long-Term Incentive Plan (Details) shares in Millions	12 Months Ended
	Dec. 31, 2022 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Active Incentive Plans	1
2005 Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Period	3 years
Award vesting percentage	33.00%
Shares authorized for issuance (in shares)	17.3
Shares available for issuance (in shares)	4.0
2005 Incentive Plan | Stock Options
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Incentive shares outstanding	0.0
2005 Incentive Plan | Stock Options | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized for issuance (in shares)	2.0

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Employee Benefit Plans - Grants of Share-based Awards (Details) $ / shares in Units, $ in Millions								1 Months Ended			3 Months Ended	12 Months Ended
	Dec. 07, 2022 $ / shares shares	Oct. 01, 2022 $ / shares shares	Sep. 22, 2022 director $ / shares shares	Jul. 01, 2022 $ / shares shares	Apr. 01, 2022 $ / shares shares	Jan. 04, 2022 $ / shares shares	Jan. 01, 2022 $ / shares shares	Jan. 31, 2023 USD ($) $ / shares shares	Jan. 31, 2022 shares	Jan. 31, 2021 shares	Jun. 30, 2022 shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2020 USD ($) $ / shares shares
RSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units												1,065,705	452,381
Grant Date Fair Value Per Share/Unit | $ / shares												$ 3.12	$ 4.20
Share-based payment awards vested (in shares)												150,792
RSUs | Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Date of Grant							Jan. 01, 2022
Shares/Units							1,065,705
Grant Date Fair Value Per Share/Unit | $ / shares							$ 3.12
Vesting Percentage							33.00%
Vesting Period							3 years
RSUs | Officers | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units								506,436
Grant Date Fair Value Per Share/Unit | $ / shares								$ 7.38
Total market value granted | $								$ 3.7
PSUs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units												1,065,705	452,381	369,938
Grant Date Fair Value Per Share/Unit | $ / shares												$ 4.25	$ 5.33	$ 13.15
Vesting Period					3 years
Share-based payment awards vested (in shares)									559,150	368,038		559,150	368,038	589,335
PSUs | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment awards vested (in shares)								369,938
PSUs | Officers
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Date of Grant						Jan. 04, 2022
Shares/Units						1,065,705
Grant Date Fair Value Per Share/Unit | $ / shares						$ 4.25
Vesting Percentage						100.00%
Vesting Date						Jan. 04, 2025
PSUs | Officers | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units								489,498
Grant Date Fair Value Per Share/Unit | $ / shares								$ 9.26
Total market value granted | $								$ 4.5
Restricted Stock
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares/Units												253,358	332,841	667,752
Grant Date Fair Value Per Share/Unit | $ / shares												$ 5.33	$ 3.59	$ 7.06
Share-based payment awards vested (in shares)												719,456	656,066	631,498
Restricted Stock | Board of Directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Date of Grant	Dec. 07, 2022	Oct. 01, 2022	Sep. 22, 2022	Jul. 01, 2022	Apr. 01, 2022	Jan. 04, 2022
Shares/Units	175,882	12,796	19,328	14,867	14,710	15,775
Grant Date Fair Value Per Share/Unit | $ / shares	$ 5.97	$ 3.86	$ 4.38	$ 3.10	$ 4.78	$ 3.12
Vesting Percentage	100.00%	100.00%	100.00%	100.00%	100.00%	100.00%
Vesting Date	Dec. 07, 2023	Jan. 01, 2024	Sep. 22, 2023	Jan. 01, 2024	Jan. 01, 2024	Jan. 01, 2024
New members of the Board of Directors | director			2
Restricted Stock | Board of Directors | Shares granted on January 4, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment awards vested (in shares)											8,013
Restricted Stock | Board of Directors | Shares granted on April 1, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based payment awards vested (in shares)											5,230
Fixed Value Cash Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Long-term incentive cash awards granted | $												$ 5.5	$ 3.5	$ 4.7
Fixed Value Cash Awards | Management and Employee | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Long-term incentive cash awards granted | $								$ 5.9

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Employee Benefit Plans - Restricted Stock Awards (Details) - Restricted Stock - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Shares
Awards outstanding at beginning of year (in shares)	853,726	1,176,951	1,173,045
Granted (in shares)	253,358	332,841	667,752
Vested (in shares)	(719,456)	(656,066)	(631,498)
Forfeited (in shares)			(32,348)
Awards outstanding at end of year (in shares)	387,628	853,726	1,176,951
Grant Date Fair Value
Awards outstanding at beginning of year (in dollars per share)	$ 5.62	$ 6.61	$ 6.81
Granted (in dollars per share)	5.33	3.59	7.06
Vested (in dollars per share)	4.94	6.35	7.52
Forfeited (in dollars per share)			5.41
Awards outstanding at end of year (in dollars per share)	$ 6.70	$ 5.62	$ 6.61
Fair value of awards vested	$ 2.9	$ 2.6	$ 5.4
Compensation cost	2.5	$ 3.3	$ 4.2
Future share-based compensation	$ 1.2
Weighted average vesting period (in years)	7 months 6 days

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Employee Benefit Plans - PSU Awards (Details) - PSUs $ / shares in Units, $ in Millions		1 Months Ended			12 Months Ended
	Apr. 01, 2022 item	Jan. 31, 2023 USD ($) $ / shares shares	Jan. 31, 2022 USD ($) $ / shares shares	Jan. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) $ / shares shares	Dec. 31, 2020 USD ($) $ / shares shares
Employee Benefit Plans
Number of components of PSUs granted | item	2
Awards granted based on the performance of our common stock against peer group companies (as a percent)	50.00%
Awards granted based on cumulative total Free Cash Flow (as a percent)	50.00%
Vesting Period	3 years
Payout at vesting (as a percent)			157.00%	200.00%
Units
Awards outstanding at beginning of year (in shares)		1,888,024	1,381,469	1,297,126	1,381,469	1,297,126	1,565,044
Granted (in shares)					1,065,705	452,381	369,938
Vested (in shares)			(559,150)	(368,038)	(559,150)	(368,038)	(589,335)
Forfeited (in shares)							(48,521)
Awards outstanding at end of year (in shares)					1,888,024	1,381,469	1,297,126
Grant Date Fair Value
Awards outstanding at beginning of year (in dollars per share) | $ / shares		$ 6.25	$ 8.34	$ 9.99	$ 8.34	$ 9.99	$ 10.17
Granted (in dollars per share) | $ / shares					4.25	5.33	13.15
Vested (in dollars per share) | $ / shares					7.60	10.44	12.64
Forfeited (in dollars per share) | $ / shares							7.60
Awards outstanding at end of year (in dollars per share) | $ / shares					$ 6.25	$ 8.34	$ 9.99
Compensation cost | $					$ 4.8	$ 4.1	$ 4.0
Future share-based compensation | $					$ 5.2
Weighted average vesting period (in years)					1 year 4 months 24 days
Shares issued upon vesting			876,469	736,075
Fair value of awards vested | $			$ 3.2	$ 3.1
Subsequent Event
Employee Benefit Plans
Payout at vesting (as a percent)		77.00%
Units
Vested (in shares)		(369,938)
Grant Date Fair Value
Shares issued upon vesting		285,778
Fair value of awards vested | $		$ 3.6
Minimum
Employee Benefit Plans
Payout at vesting (as a percent)	0.00%
Maximum
Employee Benefit Plans
Payout at vesting (as a percent)	200.00%

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Employee Benefit Plans - RSU Awards (Details) - RSUs - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Units
Awards outstanding at beginning of year (in shares)	452,381
Granted (in shares)	1,065,705	452,381
Vested (in shares)	(150,792)
Awards outstanding at end of year (in shares)	1,367,294	452,381
Grant Date Fair Value
Awards outstanding at beginning of year (in dollars per share)	$ 4.20
Granted (in dollars per share)	3.12	$ 4.20
Vested (in dollars per share)	4.20
Awards outstanding at end of year (in dollars per share)	$ 3.36	$ 4.20
Compensation cost	$ 3.7	$ 0.5
Future share-based compensation	$ 6.4
Weighted average vesting period (in years)	1 year 9 months 18 days

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Employee Benefit Plans - Cash Awards (Details) - Fixed Value Cash Awards - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Long-term incentive cash awards granted	$ 5.5	$ 3.5	$ 4.7
Vesting period	3 years
Deferred compensation cost	$ 4.3	$ 4.0	$ 4.4

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Business Segment Information - Narrative (Details) - segment	6 Months Ended
	Dec. 31, 2022	Jun. 30, 2022
Segment Reporting [Abstract]
Number of reportable segments	4	3

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Business Segment Information - Summary Of Financial Data By Segment (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Segment Information
Net revenues		$ 873,100	$ 674,728	$ 733,555
Income (loss) from operations		(44,855)	(48,687)	13,025
Change in fair value of contingent consideration	$ (16,054)	(16,054)
Goodwill impairment				(6,689)
Net interest expense		(18,950)	(23,201)	(28,531)
Other non-operating income (expense), net		(11,376)	1,246	16,889
Income (loss) before income taxes		(75,181)	(70,642)	1,383
Capital expenditures		33,504	8,322	20,244
Depreciation and amortization		142,686	141,514	133,709
Reportable Segments
Business Segment Information
Income (loss) from operations		26,310	(7,214)	56,585
Change in fair value of contingent consideration		(16,054)
Goodwill impairment				(6,689)
Intercompany Eliminations
Business Segment Information
Net revenues		(50,187)	(48,479)	(42,015)
Corporate, Eliminations and Other
Business Segment Information
Income (loss) from operations		(55,111)	(41,473)	(36,871)
Capital expenditures		1,176	(917)	464
Depreciation and amortization		(167)	(660)	349
Well Intervention
Business Segment Information
Net revenues		524,241	516,564	539,249
Goodwill impairment				(6,689)
Well Intervention | Reportable Segments
Business Segment Information
Net revenues		524,241	516,564	539,249
Income (loss) from operations		(53,056)	(35,882)	26,855
Capital expenditures		17,617	2,349	19,523
Depreciation and amortization		103,952	107,551	101,756
Well Intervention | Intercompany Eliminations
Business Segment Information
Net revenues		(16,545)	(21,521)	(15,039)
Robotics
Business Segment Information
Net revenues		191,921	137,295	178,018
Robotics | Reportable Segments
Business Segment Information
Net revenues		191,921	137,295	178,018
Income (loss) from operations		29,981	5,762	13,755
Capital expenditures		15,603	120	257
Depreciation and amortization		12,209	15,158	15,952
Robotics | Intercompany Eliminations
Business Segment Information
Net revenues		(33,642)	(26,958)	(26,976)
Shallow Water Abandonment
Business Segment Information
Net revenues		124,810
Shallow Water Abandonment | Reportable Segments
Business Segment Information
Net revenues		124,810
Income (loss) from operations		22,184
Capital expenditures		532
Depreciation and amortization		8,172
Production Facilities
Business Segment Information
Net revenues		82,315	69,348	58,303
Production Facilities | Reportable Segments
Business Segment Information
Net revenues		82,315	69,348	58,303
Income (loss) from operations		27,201	22,906	15,975
Capital expenditures		(1,424)	6,770
Depreciation and amortization		$ 18,520	$ 19,465	$ 15,652

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Business Segment Information - Intercompany Segment Revenues (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Segment Information
Net revenues	$ (873,100)	$ (674,728)	$ (733,555)
Well Intervention
Business Segment Information
Net revenues	(524,241)	(516,564)	(539,249)
Robotics
Business Segment Information
Net revenues	(191,921)	(137,295)	(178,018)
Intercompany Eliminations
Business Segment Information
Net revenues	50,187	48,479	42,015
Intercompany Eliminations | Well Intervention
Business Segment Information
Net revenues	16,545	21,521	15,039
Intercompany Eliminations | Robotics
Business Segment Information
Net revenues	$ 33,642	$ 26,958	$ 26,976

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Business Segment Information - Revenue By Geographic Location (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Business Segment Information
Net revenues	$ 873,100	$ 674,728	$ 733,555
United States
Business Segment Information
Net revenues	447,205	232,661	304,563
United Kingdom
Business Segment Information
Net revenues	166,980	100,154	133,005
Brazil
Business Segment Information
Net revenues	81,940	154,326	208,565
West Africa
Business Segment Information
Net revenues	87,488	126,856	41,840
Other
Business Segment Information
Net revenues	$ 89,487	$ 60,731	$ 45,582

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Business Segment Information - Property And Equipment Net Of Accumulated Depreciation By Geographic Location (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Business Segment Information
Property and equipment, net	$ 1,641,615	$ 1,657,645
United States
Business Segment Information
Property and equipment, net	780,803	693,062
United Kingdom
Business Segment Information
Property and equipment, net	625,001	713,385
Brazil
Business Segment Information
Property and equipment, net	$ 235,811	251,194
Other
Business Segment Information
Property and equipment, net		$ 4

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Business Segment Information - Total Assets By Reportable Segment (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Business Segment Information
Total assets	$ 2,389,338	$ 2,326,028
Corporate, Eliminations and Other
Business Segment Information
Total assets	57,049	98,561
Well Intervention | Reportable Segments
Business Segment Information
Total assets	1,796,269	2,012,214
Robotics | Reportable Segments
Business Segment Information
Total assets	192,694	96,249
Shallow Water Abandonment | Reportable Segments
Business Segment Information
Total assets	206,944
Production Facilities | Reportable Segments
Business Segment Information
Total assets	$ 136,382	$ 119,004

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Asset Retirement Obligations - Acquisitions (Details) - USD ($) $ in Thousands	1 Months Ended
	Aug. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligations
Asset retirement obligation		$ 51,956	$ 29,658	$ 30,913	$ 28,258
Production Facilities | Thunder Hawk Field
Asset Retirement Obligations
Ownership percentage	62.50%
Asset retirement obligation	$ 23,600

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Asset Retirement Obligations - Changes in AROs (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Changes in our AROs:
AROs at beginning of year	$ 29,658	$ 30,913	$ 28,258
Liability incurred during the period	23,601
Revisions in estimates	(3,285)	(2,631)
Accretion expense	1,982	1,376	2,655
AROs at end of period	$ 51,956	$ 29,658	$ 30,913

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Commitments And Contingencies And Other Matters - Narrative (Details)	1 Months Ended
	Jan. 31, 2023
Glomar Wave | Subsequent Event
Commitments And Contingencies [Line Items]
Term of charter agreement	3 years

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Statement Of Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Cash Flow Information [Abstract]
Interest paid	$ 18,267	$ 20,719	$ 15,943
Income taxes paid	9,516	8,310	$ 7,434
Tax refunds related to the CARES Act	$ 1,100	$ 18,900

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Statement Of Cash Flow Information - Narrative (Details) - USD ($) $ in Thousands		12 Months Ended
	Jul. 01, 2022	Dec. 31, 2022	Dec. 31, 2021
Non-cash capital additions		$ 400	$ 300
Alliance
Post-closing earn-out consideration payable	$ 26,700

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Allowance Accounts - Activities In Allowance For Credit Losses (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Allowance for credit losses
Balance at beginning of year	$ 1,477	$ 3,469
Additions (reductions)	800	(146)	$ 2,684
Write-offs		(1,846)
Adjustments			785
Balance at end of period	2,277	1,477	3,469
Deferred tax asset valuation allowance
Balance at beginning of year	14,047	19,722	18,631
Adjustments	8,110	(5,675)	1,091
Balance at end of period	$ 22,157	$ 14,047	19,722
Allowance for Credit Losses | Robotics
Allowance for credit losses
Additions (reductions)			$ 1,700

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Fair Value Measurements - Assets And Liabilities At Fair Value On Recurring Basis (Details) - Recurring $ in Thousands	Dec. 31, 2022 USD ($)
Fair Value Measurements
Contingent consideration	$ 42,754
Level 3
Fair Value Measurements
Contingent consideration	$ 42,754

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Fair Value Measurements - Inputs Used in Valuation (Details)	Dec. 31, 2022
Weighted-average volatility
Fair Value Measurements
Contingent consideration, measurement input	0.475
Weighted average discount rate
Fair Value Measurements
Contingent consideration, measurement input	0.080

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Fair Value Measurements - Change in Fair Value of Contingent Consideration (Details) - USD ($) $ in Thousands	6 Months Ended	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2022
Change in the fair value of contingent consideration:
Balance at July 1,	$ 26,700
Change in fair value	16,054	$ 16,054
Balance at end of period	$ 42,754	$ 42,754

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Fair Value Measurements - Principal Amount And Estimated Fair Value Of Long-Term Debt (Details) - USD ($) $ in Thousands	Dec. 31, 2022	Dec. 31, 2021
Fair Value Measurements
Principal Amount	$ 270,913
MARAD Debt (matures February 2027)
Fair Value Measurements
Principal Amount	40,913	$ 48,850
Fair Value	40,940	52,481
2022 Notes (matured May 2022)
Fair Value Measurements
Principal Amount		35,000
Fair Value		34,794
2023 Notes (mature September 2023)
Fair Value Measurements
Principal Amount	30,000	30,000
Fair Value	31,149	29,054
2026 Notes (mature February 2026)
Fair Value Measurements
Principal Amount	200,000	200,000
Fair Value	277,014	200,562
Total Debt
Fair Value Measurements
Principal Amount	270,913	313,850
Fair Value	$ 349,103	$ 316,891