EDGAR 10-K Filing

Company CIK: 866829
Filing Year: 2022
Filename: 866829_10-K_2022_0000866829-22-000005.json

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ITEM 1. BUSINESS
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 and robotics operations. Traditionally, our services have covered the lifecycle of an offshore oil or gas field. In recent years, we have seen an increasing demand for our services from the offshore renewable energy market. 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 2021 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 15 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 have three reportable business segments: Well Intervention, Robotics and Production Facilities. We provide a range of services to the oil and gas and renewable energy markets primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. 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 preventing uncontrolled releases of oil and gas. 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. Our Robotics segment provides offshore construction, trenching, seabed clearance, 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 and robotics support vessels under long-term charter as well as spot vessels as needed. 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. See Note 15 for financial results related to our business segments.
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; IRM of production structures, trees, jumpers, risers, pipelines and subsea equipment; and related support services.
● Decommissioning. Reclamation and remediation services; well plug and abandonment (“P&A”) services; pipeline 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, underwater unexploded ordnance identification and disposal and boulder relocation.
● Trenching. Cable protection via jetting and/or cutting by self-propelled trenching ROVs.
● 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 well intervention vessels serve as work platforms for well intervention services at costs that generally have been less than those of offshore drilling rigs. Our purpose-built vessels 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.
Our well intervention business currently operates seven vessels, 10 intervention systems and various equipment, providing services primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa.
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 and completed its five-year contract with BP in April 2021. Both vessels are currently working in the spot market.
In Brazil, we provided well intervention services with the Siem Helix 1 and Siem Helix 2 vessels under contracts with Petróleo Brasileiro S.A. (“Petrobras”) with options to extend. The Siem Helix 1 commenced operations in April 2017 and completed its four-year contract in August 2021. After completing its regulatory dry dock in October 2021, the Siem Helix 1 transited from Brazil to Ghana in December 2021 for a short-term accommodations project. The Siem Helix 2 commenced operations in December 2017 and following the completion of its four-year contract in December 2021, the Petrobras contract was extended at reduced rates for one year until December 2022. We charter the Siem Helix 1 and Siem Helix 2 vessels from Siem Offshore AS (“Siem”) under an initial term of seven years with options to extend.
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 to be capable of working globally, commenced operations in January 2020 and is currently performing integrated well intervention operations offshore Nigeria.
Our Subsea Services Alliance with Schlumberger 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 Schlumberger 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 Gulf of Mexico, North Sea, West Africa and Asia Pacific 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, 2021, our robotics assets included 43 work-class ROVs and four trenchers. 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 Northern Europe where offshore wind farming is currently concentrated. We provide burial services related to subsea power cable installations as well as seabed clearing services around the world using our chartered vessels, ROVs and trenchers. In 2021, revenues derived from offshore renewable energy contracts accounted for 23% 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.
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 a fixed fee agreement through at least June 1, 2023.
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, 2023 with various operators to provide access to the HFRS for well control purposes.
Our Production Facilities segment includes two remaining wells acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019. These oil and gas properties are associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244. As part of the transaction, Marathon Oil agreed to pay us certain amounts as we complete the P&A of these wells.
GEOGRAPHIC AREAS
We primarily operate in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations are subject to seasonal changes in demand, which generally peaks in the summer months and declines in the winter months. See Note 15 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: 2021 - Petrobras (23%) and Shell (17%); 2020 - Petrobras (28%) and BP (17%); and 2019 - Petrobras (29%), BP (15%) and Shell (13%). We provided services to over 60 customers in 2021.
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, TIOS 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 competitors may have more or differing financial, personnel, technological and other resources available to them.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
ESG initiatives and disclosures are embedded in our core business values and priorities of safety, sustainability and value creation 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 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. 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. 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 constant improvement by establishing goals to reduce our environmental impact, improve our safety record and increase transparency for our stakeholders. In 2021, we disclosed our GHG Emissions metrics for 2019 and 2020 and our reduction targets for GHG Emissions over a five-year period. We understand that establishing these targets provides value to us as a company and is valued by those who support us, and we are committed to providing transparency with respect to our GHG Emissions. In tandem with such disclosures and targets, we continued to expand our business with renewable energy customers. Our business supports 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 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, 2021, we had 1,327 employees. Of our total employees, we had 310 non-U.S. 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.
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 spot 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. The management systems of our business units have been independently assessed and registered compliant with ISO 9001 (Quality Management Systems) and ISO 14001 (Environmental Management Systems). Our safety management systems were created in accordance with OHSAS 45001.
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. The ongoing COVID-19 pandemic continues to present challenges, and in response we have implemented numerous health and safety protocols, including a vaccine requirement for offshore personnel where legally permissible and practical, isolation and health screenings prior to offshore travel and crew changes, limiting or altogether eliminating certain common areas aboard our vessels, mandatory face coverings, social distancing, extending the duration of certain offshore shifts to reduce travel and turnover, and immediate quarantine and definitive response protocols in the event any personnel are showing or reporting any potential symptoms. While many jurisdictions have substantially lifted restrictions in response to mass vaccination, we continue to closely monitor the COVID-19 pandemic and its evolving variants, and adjust our protocols based on the rate of spread in the communities where we operate and the COVID-19 vaccination status of our employees, customers, and vendors. 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 strategy. In 2021, 63% of our workforce had been with the Company for five years or longer, and our global voluntary turnover rate was 12.4%. While these numbers provide valuable insight, the context surrounding these numbers provide an even clearer picture into our global workforce. The Siem Helix 1, the Siem Helix 2 and the Q7000 commenced operations in April 2017, December 2017 and January 2020, respectively. The initial mobilization of these vessels required hiring of new crew and individuals, which directly impacts the tenure percentages above and skews a greater number of employees into the zero-to-four years category.
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.
Diversity and Inclusion
We are committed to diversity and inclusion throughout our workforce. In 2021, our worldwide workforce represented 32 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. we have 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 most recent statistics showing the breakdown of how our employees self-identify their ethnicity is available in our Corporate Sustainability Report, a copy of which is available on our website at www.helixesg.com/about-helix/our-company/corporate-sustainability.
GOVERNMENT REGULATION
Overview
We provide services primarily in deepwater in the Gulf of Mexico, 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 end of life 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.
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 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.
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.
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.
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. The deductibles are $1 million on the Q4000, the Q5000, the Q7000, the HP I and the Well Enhancer, and $500,000 on the Seawell. In addition to the primary deductibles, the vessels are subject to an annual aggregate deductible of $5 million. 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. Our current deductible on the P&I Liability is $100,000 per occurrence and $250,000 per occurrence on the General Liability. 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 and currently includes a deductible of $250,000 per occurrence. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability for total limits of $500 million in excess of primary limits as well as OPA insurance for our offshore oil and gas properties with $35 million of coverage as required by BOEM. Our self-insured retention on our medical and health benefits program for employees is $300,000 per participant.
We maintain Operator Extra Expense coverage that provides up to $150 million of coverage per each loss occurrence for a well control issue on oil and gas properties where we are the operator. Separately, we also maintain $500 million of liability insurance. For any given oil spill event we maintain up to $650 million of insurance coverage.
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 for an amount up to $100 million 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.
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, 2021, 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.
From time to time, we also provide information about Helix on social media, including on Facebook (www.facebook.com/HelixEnergySolutionsGroup), Instagram (www.instagram.com/helixenergysolutions), LinkedIn (www.linkedin.com/company/helix-energy-solutions-group), Twitter (@Helix_ESG) and YouTube (www.youtube.com/user/HelixEnergySolutions).
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.
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.
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.
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).
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.
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.
Spot vessels: Vessels not owned or under long-term charter 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.

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ITEM 1A. RISK FACTORS
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 lifecycle 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 price war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”) during the first quarter 2020 and global storage considerations significantly contributed to the slowdown and uncertainty in the global economy. The ongoing COVID-19 pandemic has caused uncertainty and volatility in oil prices, which has led to reduced operating and capital spending by our oil and gas production customers. Continued oil and gas volatility and the responses thereto will continue to adversely impact our financial condition and results of operations.
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 OPEC and/or OPEC+;
● the availability and discovery rate of new oil and natural gas reserves in offshore areas;
● the exploration and production of onshore shale oil and natural gas;
● the cost of offshore exploration for and production and transportation of oil and natural gas;
● the level of excess production capacity;
● the ability of oil and gas companies to generate funds or otherwise obtain 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;
● technological advances affecting energy exploration, production, transportation and consumption;
● potential acceleration of the development of alternative fuels;
● shifts in end-customer preferences toward fuel efficiency and the use of natural gas or renewable energy alternatives;
● weather conditions, natural disasters, and epidemic and pandemic diseases, including the ongoing 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
● tax laws, regulations and policies.
A prolonged period of low level of activity by offshore oil and gas operators may continue to 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, especially the willingness of oil and gas companies to make capital and other expenditures for offshore exploration, development, drilling and production operations, the persistence of such conditions would negatively impact those companies’ willingness and ability to make those expenditures. Additionally, our customers, in reaction to negative market conditions, may continue to 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 length and severity of an unfavorable industry environment and the potential decreased demand for our services.
The ongoing 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, 2021, despite the rollout of vaccines and the successes of mitigation efforts, the global pandemic remains ongoing. 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 throughout these Risk Factors. 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 ongoing nature of the pandemic will continue to create market disruption and uncertainty 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.
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.
We are subject to the effects of changing prices.
Inflation rates have been relatively low and stable over the previous three decades; however, in 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic, inflation rates began to rise significantly. 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 are 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.
Business and Operational Risks
Our backlog may not be ultimately realized for various reasons, and our contracts may be terminated early.
As of December 31, 2021, backlog for our services supported by written agreements or contracts totaled $348 million, of which $246 million is expected to be performed in 2022.
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 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 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 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, including the five-year contract with BP for work in the Gulf of Mexico, the four-year contracts with Petrobras for well intervention services offshore Brazil and the seven-year contract for the HP I. We completed the contracts with BP and with Petrobras for the Siem Helix 1 during 2021 and extended the contract with Petrobras for the Siem Helix 2 at reduced rates for one year until December 2022. As of December 31, 2021, the Petrobras contract for the Siem Helix 2 and the contract for the HP I represented approximately 44% of our total backlog. 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.
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 ongoing 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 ongoing 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 business unit tends 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.
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.
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.
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.
Our North Sea business typically declines in the winter, and weather can adversely affect our operations.
Marine operations conducted in the North Sea 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. As is common in our industry, 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.
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; 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, such as local content requirements. 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 ongoing 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.
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, 2021, we had consolidated indebtedness of $305 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 continued 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 the portion of our borrowings at variable interest rates;
● reducing the availability of our cash flows to fund our working capital requirements, capital expenditures, acquisitions, investments and other general corporate requirements because we will be required to use a substantial portion of our cash flows 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 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 increasingly 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 additional 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.
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, 2021, we had approximately $10.5 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.
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. Tax laws are dynamic and continue to evolve as new legislation is enacted and interpretive guidance issued. Additionally, the EU and organizations such as the Organization for Economic Co-operation and Development continue to promote increased disclosure and transparency, which may increase our overall compliance costs or have other adverse effects on us.
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.
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 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 ongoing COVID-19 pandemic, and a decline in sentiment towards fossil fuels. Many companies, including us, have had employee layoffs as a result of reduced business activities in an industry downturn. 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. As a result, our ability to remain productive and profitable will depend upon our ability to employ and retain skilled, qualified and experienced workers, and we may have competition for personnel with the requisite skill set.
Cybersecurity breaches or business system disruptions may adversely affect our business.
We rely on our information 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 continue to work remotely as a result of the ongoing COVID-19 pandemic.
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.
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 in breach, in the event of a “change of control.” Any or all of these provisions or factors may discourage a takeover proposal or tender offer not approved by management and our Board and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less in return for their shares than otherwise might be available in the event of a takeover attempt.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
VESSELS AND OTHER OPERATING ASSETS
As of December 31, 2021, our fleet included six owned vessels, six IRSs, three SILs, the ROAM, 43 ROVs and four trenchers. We also had four vessels under long-term charter. All of our vessels, both owned and chartered, have DP capabilities specifically designed to meet the needs of our customers’ offshore and deepwater activities. Our Seawell and Well Enhancer vessels also have built-in saturation diving systems.
Listing of Vessels and Other Assets Related to Operations as of December 31, 2021 (1)
Placed
Flag
in
Length
State
Service (2)
(Feet)
DP
Floating Production Unit -
Helix Producer I
Bahamas
4/2009
DP2
Well Intervention -
Q4000 (3)
U.S.
4/2002
DP3
Seawell (4)
U.K.
7/2002
DP2
Well Enhancer (4)
U.K.
10/2009
DP2
Q5000
Bahamas
4/2015
DP3
Siem Helix 1 (5)
Bahamas
6/2016
DP3
Siem Helix 2 (5)
Bahamas
2/2017
DP3
Q7000
Bahamas
1/2020
DP3
6 IRSs, 3 SILs and the ROAM (6)
-
Various
-
-
Robotics -
43 ROVs and 4 Trenchers (4), (7)
-
Various
-
-
Grand Canyon II (5)
Norway
4/2015
DP3
Grand Canyon III (5)
Norway
5/2017
DP3
(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 8.
(4) Serves as security for the ABL Facility described in Note 8.
(5) Vessel under long-term charter agreement.
(6) We own a 50% interest in the 15K IRS and the ROAM, both of which we jointly developed with Schlumberger.
(7) Average age of our fleet of ROVs and trenchers is approximately 11.3 years.
We incur routine dry dock, inspection, maintenance and repair costs pursuant to applicable statutory regulations in order to maintain our vessels in accordance with the rules of the applicable class society. In addition to complying with these requirements, we have our own asset maintenance programs that we believe permit us to continue to provide our customers with well-maintained, reliable assets.
FACILITIES
Our corporate headquarters are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas 77043. We currently lease all of our facilities, which are primarily located in Texas, Scotland, Singapore and Brazil.

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ITEM 3. LEGAL PROCEEDINGS
Item 3. Legal Proceedings
The information required to be set forth under this heading is incorporated by reference from Note 17 to our consolidated financial statements included in Item 8. Financial Statements and Supplementary Data of this Annual Report.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures
Not applicable.
Information about our Executive Officers
Our executive officers are as follows:
Name
Age
Position
Owen Kratz
President, Chief Executive Officer and Director
Erik Staffeldt
Executive Vice President and Chief Financial Officer
Scott A. Sparks
Executive Vice President and Chief Operating Officer
Kenneth E. Neikirk
Senior 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. 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 26 years of experience in the energy industry. Mr. Staffeldt is a graduate of the University of Notre Dame with a BBA in Accounting and Loyola University in New Orleans with an MBA, and is a Certified Public Accountant.
Scott A. (“Scotty”) Sparks is Executive Vice President and Chief Operating Officer of Helix, having joined Helix in 2001. He served as Executive Vice President - Operations of Helix from May 2015 until February 2016. From October 2012 until May 2015, he was Vice President - Commercial and Strategic Development of Helix. He has also served in various positions within Helix Robotics Solutions, Inc. (formerly known as Canyon Offshore, Inc.), including as Senior Vice President from 2007 to September 2012. Mr. Sparks has over 31 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 Senior Vice President, General Counsel and Corporate Secretary of Helix. Mr. Neikirk has over 21 years of experience practicing law in the corporate and energy sectors, and has been a member of Helix’s legal department since 2007, most recently serving as Helix’s 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

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2022, the closing sale price of our common stock on the NYSE was $4.18 per share. As of February 17, 2022, there were 284 registered shareholders and approximately 93,650 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. We currently intend to retain earnings, if any, for the future operation and growth of our business. In addition, our current financing arrangements restrict the payment of cash dividends on our common stock. 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, 2016 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 2021 (the “Peer Group”) including the following companies: Archrock, Inc., Core Laboratories N.V., Dril-Quip, Inc., Expro Group Holdings N.V., Forum Energy Technologies, Inc., Halliburton Company, Helmerich & Payne, Inc., Nabors Industries Ltd., Newpark Resources, Inc., NOV Inc., Oceaneering International, Inc., Oil States International, Inc., RPC, Inc., Schlumberger Limited, TETRA Technologies, Inc., and Transocean Ltd. The returns of each member of the Peer Group have been weighted according to each individual company’s equity market capitalization as of December 31, 2021 and have been adjusted for the reinvestment of any dividends. We believe that the members of the Peer Group provide services and products more comparable to us than those companies included in the OSX. The graph assumes $100 was invested on December 31, 2016 in our common stock at the closing price on that date price and on December 31, 2016 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 - (64.6)%; the Peer Group - (58.5)%; the OSX - (68.4)%; and S&P 500 - 133.4%. These results are not necessarily indicative of future performance.
Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group
As of December 31,
Helix
$
100.0
$
85.5
$
61.3
$
109.2
$
47.6
$
35.4
Peer Group Index
$
100.0
$
85.7
$
49.5
$
53.3
$
32.8
$
41.5
Oil Service Index
$
100.0
$
82.8
$
45.4
$
45.1
$
26.1
$
31.6
S&P 500
$
100.0
$
121.8
$
116.5
$
153.2
$
181.4
$
233.4
Source: Bloomberg
Issuer Purchases of Equity Securities
(c)
Total number of
(d)
shares
Maximum
(a)
(b)
purchased as
number of shares
Total number
Average
part of publicly
that may yet be
of shares
price paid
announced
purchased under
Period
purchased (1)
per share
program
the program (2) (3)
October 1 to October 31, 2021
-
$
-
-
7,908,635
November 1 to November 30, 2021
-
-
-
7,908,635
December 1 to December 31, 2021
37,842
3.25
-
8,182,193
37,842
$
3.25
-
(1) Includes shares forfeited in satisfaction of tax obligations upon vesting of restricted shares.
(2) Under the terms of our stock repurchase program, we may 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 14), and such shares increase the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 11.
(3) In December 2021, we issued 273,558 shares of restricted stock to independent members of our Board. In January 2022, we issued 15,775 shares of restricted stock to certain independent members of our Board who elected to take their 2021 quarterly fees in stock in lieu of cash. These issuances increase the number of shares available for repurchase under our stock repurchase program by a corresponding amount.

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ITEM 6. SELECTED FINANCIAL DATA
Item 6. [Reserved]

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 and robotics operations. The services we offer to the oil and gas market cover the lifecycle of an offshore oil or gas field, and the services we offer to the renewable energy market are currently focused on offshore wind farm projects, including trenching and cable burial and seabed clearance operations. Our well intervention fleet includes seven purpose-built well intervention vessels and 10 intervention systems. Our robotics equipment includes 43 work-class ROVs and four trenchers. We charter robotics support vessels on both long-term and spot bases to facilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the world. Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties.
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, 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 several 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 exploration and production of onshore shale oil and natural gas;
● the cost of offshore exploration for and production and transportation of oil and natural gas;
● the level of excess production capacity;
● the ability of oil and gas companies to generate funds or otherwise obtain 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;
● technological advances affecting energy exploration, production, transportation and consumption;
● potential acceleration of the development of alternative fuels;
● shifts in end-customer preferences toward fuel efficiency and the use of natural gas or renewable energy alternatives;
● weather conditions, natural disasters, and epidemic and pandemic diseases, including the ongoing 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.
Crude oil prices historically have been volatile, which volatility has been exacerbated by the ongoing COVID-19 pandemic. Prices declined significantly in 2020 but have since recovered their losses and are at their highest levels since 2014, but their stability remains uncertain. The decline in oil prices in 2020 and the overall volatility and uncertainty in prices, in addition to the shift in resource allocation to renewable energy, caused oil and gas companies to drastically reduce spending (on both operational activities and capital projects). These factors have led to a decrease in the demand and rates for services provided by offshore oil and gas services providers, but the increases in oil prices in 2021, as well as the outlook for higher sustained oil prices beyond 2021, could lead to higher customer spending for the industry.
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. Lower volumes of work and lower day rates quoted by drilling rig contractors, combined with rig overhang, affects the utilization and/or rates we can achieve for our assets and services. Furthermore, additional volatile and uncertain macroeconomic conditions in some regions and countries around the world as well as ESG initiatives may impact our existing contracts and contracting opportunities and may introduce further volatility into our operations and/or financial results.
The ongoing COVID-19 pandemic has resulted in new market dynamics and challenges to us, including increased costs related to our supply chain, logistics and human capital resources. We have sought to minimize the direct impact of COVID-19 on our offshore workforce with crew changes that comport with travel restrictions and quarantine measures. While the full impact of the COVID-19 pandemic, including the duration of its negative impact on economic activity, remains unknown, we expect such impact to continue to be felt by our industry into the foreseeable future. The uncertainty and other conditions of the current environment have resulted in challenges to renew or secure long-term contracts for our vessels and systems, as operators have been less willing to commit to future spending. These developments have also impacted, and are expected to continue to impact, many other aspects of our industry and the global economy, including limiting access to and use of capital across various sources and markets, disrupting supply chains and increasing costs, and negatively affecting human capital resources including complicating offshore crew changes due to health and travel restrictions as well as the overall health of the global workforce.
Over the near-term, as oil and gas companies evaluate their budgetary spend allocations, we expect they may be weighted towards short-cycle production enhancement of existing wells rather than new long-cycle exploration projects, as historically enhancement is less expensive per incremental barrel of oil than exploration. Over the longer term, we expect oil and gas companies to increasingly focus on optimizing production of their existing subsea wells. Moreover, as the subsea tree base expands and ages, the demand for P&A services should persist. Our well intervention and robotics operations service the lifecycle 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 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 and safely decommission end of life wells are primary drivers of demand for our 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.
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 are subject to the effects of changing prices. Inflation rates have been relatively low and stable over the previous three decades; however, in 2021 due in part to supply chain disruptions and the effects of the COVID-19 pandemic, inflation rates began to rise significantly. Although we are able to reduce some of 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 reduction 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.
Business Activity Summary
In recent years, we have maintained a relatively strong balance sheet and enhanced our financial position through various means including securities offerings (the last of which occurred in August 2020) and executing a new five-year credit facility during 2021, which have allowed us to focus on our operations.
We re-activated the Q7000 in January 2021 and the Seawell in June 2021 after warm-stacking the vessels during part of 2020 due in part to the COVID-19 pandemic. The Q7000 performed well intervention work offshore Nigeria for most of 2021. The Seawell performed various work scopes in the North Sea during the second and third quarters of 2021.
In March 2021, we entered into a new agreement to provide various operators with access to the HFRS for well control purposes in the Gulf of Mexico through at least March 31, 2023.
We completed our five-year contract with BP for the Q5000 in April 2021. We also completed our four-year contracts with Petrobras for the Siem Helix 1 in August 2021 and the Siem Helix 2 in December 2021. Both the Q5000 and the Siem Helix 1 are currently working in the spot market. The Petrobras contract for the Siem Helix 2 was extended at reduced rates for one year until December 2022.
During 2021, we continued to improve our health and safety protocols in order to navigate through the COVID-19 pandemic, including significant measures to protect both onshore and offshore personnel.
We have continued to expand our services and offerings into the offshore renewable energy sector. During 2021, we performed site clearance and/or ROV support work on multiple renewable energy projects in the Asia Pacific and North Sea regions.
Backlog
Backlog is defined as firm commitments represented by signed contracts. As of December 31, 2021, our consolidated backlog totaled $348 million, of which $246 million is expected to be performed in 2022. As of December 31, 2021, our contract with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 2 chartered vessel and our fixed fee agreement for the HP I represented approximately 37% of our total backlog. As of December 31, 2020, the total backlog associated with our operations was $407 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 and free cash flow. EBITDA, Adjusted EBITDA and free cash flow are non-GAAP financial measures that are commonly used but are not recognized accounting terms under GAAP. We use EBITDA, Adjusted EBITDA and free cash flow to monitor and facilitate internal evaluation of the performance of our business operations, to facilitate external comparison of our business results to those of others in our industry, to analyze and evaluate financial and strategic planning decisions regarding future investments and acquisitions, to plan and evaluate operating budgets, and in certain cases, to report our results to the holders of our debt as required by our debt covenants. We believe that our measures of EBITDA, Adjusted EBITDA and free cash flow provide useful information to the public regarding our operating performance and ability to service debt and fund capital expenditures and may help our investors understand 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 and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. EBITDA, Adjusted EBITDA and free cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with 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 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. In the following reconciliation, we provide amounts as reflected in the condensed consolidated financial statements unless otherwise noted.
The reconciliation of our net income (loss) to EBITDA and Adjusted EBITDA is as follows (in thousands):
Year Ended December 31,
Net income (loss)
$
(61,684)
$
20,084
$
57,697
Adjustments:
Income tax provision (benefit)
(8,958)
(18,701)
7,859
Net interest expense
23,201
28,531
8,333
(Gain) loss on extinguishment of long-term debt
(9,239)
Other (income) expense, net
1,490
(4,724)
(1,165)
Depreciation and amortization
141,514
133,709
112,720
Goodwill impairment
-
6,689
-
Gain on equity investment
-
(264)
(1,613)
EBITDA
95,699
156,085
183,849
Adjustments:
(Gain) loss on disposition of assets, net
(889)
-
General provision (release) for current expected credit losses
(54)
-
Realized losses from foreign exchange contracts not designated as hedging instruments
-
(682)
(3,761)
Adjusted EBITDA
$
96,276
$
155,260
$
180,088
The reconciliation of our cash flows from operating activities to free cash flow is as follows (in thousands):
Year Ended December 31,
Cash flows from operating activities
$
140,117
$
98,800
$
169,669
Less: Capital expenditures, net of proceeds from sale of assets
(8,271)
(19,281)
(138,304)
Free cash flow
$
131,846
$
79,519
$
31,365
Comparison of Years Ended December 31, 2021 and 2020
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations. The following table details various financial and operational highlights for the periods presented (dollars in thousands):
Year Ended December 31,
Increase/(Decrease)
Amount
Percent
Net revenues -
Well Intervention
$
516,564
$
539,249
$
(22,685)
(4)
%
Robotics
137,295
178,018
(40,723)
(23)
%
Production Facilities
69,348
58,303
11,045
%
Intercompany eliminations
(48,479)
(42,015)
(6,464)
$
674,728
$
733,555
$
(58,827)
(8)
%
Gross profit (loss) -
Well Intervention
$
(21,262)
$
41,037
$
(62,299)
(152)
%
Robotics
13,441
22,716
(9,275)
(41)
%
Production Facilities
25,024
17,883
7,141
%
Corporate, eliminations and other
(1,810)
(1,727)
(83)
$
15,393
$
79,909
$
(64,516)
(81)
%
Gross margin -
Well Intervention
(4)
%
%
Robotics
%
%
Production Facilities
%
%
Total company
%
%
Number of vessels or robotics assets (1) / Utilization (2)
Well intervention vessels
7 / 67
%
7 / 67
%
Robotics assets (3)
47 / 36
%
49 / 34
%
Chartered robotics vessels
3 / 97
%
2 / 94
%
(1) Represents the number of vessels or robotics assets as of the end of the period, including spot vessels and those under long-term charter, and excluding acquired vessels prior to their in-service dates 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 or robotics assets generated revenues by the total number of calendar days in the applicable period. Utilization rates of chartered robotics vessels in 2021 and 2020 included 477 and 1,057 spot vessel days, respectively, at near full utilization.
(3) Consists of ROVs and trenchers.
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/
(Decrease)
Well Intervention
$
21,521
$
15,039
$
6,482
Robotics
26,958
26,976
(18)
$
48,479
$
42,015
$
6,464
Net Revenues. Our consolidated net revenues decreased by 8% in 2021 as compared to 2020, reflecting lower revenues from our Well Intervention and Robotics segments and higher intercompany eliminations, offset in part by higher revenues in our Production Facilities segment.
Our Well Intervention revenues decreased by 4% in 2021 as compared to 2020, primarily reflecting lower utilization on the Siem Helix 1 in Brazil, lower rates on the Q5000 and lower rates and utilization on the Q4000 in the Gulf of Mexico. These revenue decreases were offset in part by higher utilization on the Q7000 in West Africa, which was warm-stacked for most of 2020.
Our Robotics revenues decreased by 23% in 2021 as compared to 2020, primarily reflecting reduced seabed clearance days using spot vessels, as well as a reduction in trenching activities. Our results included 1,178 vessel days and 336 trenching days in 2021 as compared to 1,690 vessel days and 407 trenching days (including 161 days on third-party vessels) in 2020.
Our Production Facilities revenues increased by 19% in 2021 as compared to 2020, primarily reflecting higher oil and gas prices and higher production volumes from our wells as well as higher HFRS revenues.
The increase in intercompany eliminations was primarily attributable to higher eliminations related to revenues that our Well Intervention segment earned in 2021 associated with capital spending in our Production Facilities segment to perform recompletion work on our Droshky oil and gas properties.
Gross Profit (Loss). Our consolidated 2021 gross profit decreased by $64.5 million as compared to 2020, primarily reflecting lower gross profit in our Well Intervention and Robotics segments, offset in part by higher gross profit in our Production Facilities segment.
Our Well Intervention segment had a gross loss of $21.3 million in 2021 as compared to a gross profit of $41.0 million in 2020, primarily reflecting lower segment revenues as well as higher costs associated with our resumed activity in West Africa during 2021.
The gross profit related to our Robotics segment decreased by $9.3 million in 2021 as compared to 2020, primarily reflecting lower revenues, offset in party by lower costs due to fewer spot vessel days on site clearance projects.
The gross profit related to our Production Facilities segment increased by $7.1 million in 2021 as compared to 2020, primarily reflecting higher revenues during 2021.
Goodwill Impairment. The $6.7 million charge in 2020 reflected the impairment of the entire goodwill balance, which related to our acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) (Note 7).
Selling, General and Administrative Expenses. Our selling, general and administrative expenses were $63.4 million in 2021 as compared to $61.1 million in 2020. The increase primarily reflects higher employee incentive compensation costs, offset in part by cost reduction measures and lower credit loss reserves. Our selling, general and administrative expenses in 2020 included a $2.7 million provision for current expected credit losses (Note 19).
Net Interest Expense. Our net interest expense totaled $23.2 million in 2021 as compared to $28.5 million in 2020, primarily reflecting a reduction in our overall debt levels and the elimination of accretion of debt discounts associated with 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”) as a result of the adoption of Accounting Standards Update (“ASU”) No. 2020-06 beginning January 1, 2021, offset in part by higher yields on the 2026 Notes, which were issued during the third quarter 2020, and the cessation of interest capitalization with the completion of the Q7000 in 2020. Net interest expense in 2020 excluded $1.2 million in capitalized interest associated with the Q7000 (Note 8).
Gain (Loss) on Extinguishment of Long-term Debt. The $0.1 million loss on extinguishment of long-term debt in 2021 was associated with the full repayment of the term loan under our former credit agreement (the “Term Loan”), which was terminated in September 2021 concurrent with our entering into the ABL Facility (Note 8). The $9.2 million gain on extinguishment of long-term debt in 2020 was associated with the repurchase of $90.0 million in aggregate principal amount of the 2022 Notes and $95.0 million in aggregate principal amount of the 2023 Notes.
Other Income (Expense), Net. Net other expense was $1.5 million in 2021 primarily due to foreign currency transaction losses reflecting the weakening of the British pound. Net other income was $4.7 million in 2020 primarily due to foreign currency transaction gains reflecting the strengthening of the British pound.
Income Tax Benefit. Income tax benefit was $9.0 million for 2021 as compared to $18.7 million for 2020. The change in income tax benefit was primarily attributable to certain discrete adjustments, offset in part by the jurisdictional mix of earnings. In 2021 we recognized a $5.0 million benefit related to a reduction in our valuation allowance. In 2020 we recognized a $7.6 million benefit related to the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and an $8.3 million benefit related to a foreign subsidiary restructuring (Note 9). Absent these discrete events, income tax benefit would be $4.0 million and $2.8 million for 2021 and 2020, respectively.
Comparison of Years Ended December 31, 2020 and 2019
Various financial and operational highlights for the years ended December 31, 2020 and 2019 were previously presented in our 2020 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,
Net working capital
$
251,255
$
246,338
Long-term debt (1)
262,137
258,912
Liquidity
304,660
451,532
(1) Current maturities of our long-term debt of $42.9 million and $90.7 million, respectively, are excluded from long-term debt. Long-term debt as of December 31, 2021 is net of unamortized debt issuance costs. Long-term debt as of December 31, 2020 is net of unamortized debt discounts and debt issuance costs. See Note 8 for information relating to our long-term debt, including the impact of our adoption of ASU No. 2020-06.
Net Working Capital
Net working capital is equal to current assets minus current liabilities. It measures short-term liquidity and operational efficiency and is important for predicting cash flow and debt requirements. Our net working capital includes current maturities of our long-term debt.
Liquidity
Liquidity, as defined by us, is equal to cash and cash equivalents, excluding restricted cash, plus available capacity under our credit facility. 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 (Note 8) and excluded $73.6 million of restricted cash primarily related to a short-term project related letter of credit, the restriction from which is expected to be released upon completion of the project. Our liquidity at December 31, 2020 included $291.3 million of cash and cash equivalents and $160.2 million of available borrowing capacity under the Revolving Credit Facility.
The ongoing COVID-19 pandemic has impacted our operations and our revenues, and we expect the pandemic to continue to impact our operations and our operating results into the foreseeable future, whether by contributing to oil price volatility, which in turn affects customer spending and demand for our services, or by disruptions to our operations, including supply chain and crew change disruptions and contributing to prince increases. Nonetheless, we remain focused on maintaining a strong balance sheet and adequate liquidity. We have reduced, deferred or cancelled certain planned capital expenditures and reduced operating costs as appropriate through various measures including warm stacking our vessels when idle. Deferred capital spending and reduced operating costs should return with increases in activity. 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.
The ongoing COVID-19 pandemic and its impact on the energy and financial markets have contributed to rising yields on our existing debt as well as volatility in our stock price, both of which increase our cost of capital. The yield on the 2026 Notes is significantly higher than that of the 2022 Notes and 2023 Notes. The COVID-19 pandemic has also contributed to more limited access to certain capital markets.
An ongoing period of weak, or continued decreases in, industry activity may make it difficult to comply with our covenants and the other restrictions in our debt agreements. Our failure to comply with these covenants and other restrictions could lead to an event of default. Current global and market conditions have increased the potential for that difficulty and are expected to negatively impact the terms on which we are able to secure financing. Decreases in our borrowing base may limit our ability to fully access the ABL Facility. At December 31, 2021, our available borrowing capacity under the ABL Facility was $51.1 million, net of $1.9 million of letters of credit issued under that facility. We currently do not anticipate borrowing under the ABL Facility other than for the issuance of letters of credit.
Cash Flows
The following table provides summary data from our consolidated statements of cash flows (in thousands):
Year Ended December 31,
Cash provided by (used in):
Operating activities
$
140,117
$
98,800
$
169,669
Investing activities
(8,271)
(19,281)
(142,385)
Financing activities
(95,997)
(52,578)
(45,818)
Operating Activities
Net cash flows provided by operating activities were $140.1 million in 2021 as compared to $98.8 million in 2020. The increase in operating cash flows primarily reflects improvements in working capital, lower recertification and dry dock costs, and the receipt in 2021 of $18.9 million in income tax refunds related to the CARES Act, offset in part by lower earnings.
Investing Activities
Capital expenditures represent cash paid principally for the acquisition, construction, completion, upgrade, modification and refurbishment of long-lived property and equipment. Capital expenditures also include interest on property and equipment under development. Our capital expenditures during 2020 primarily included payments associated with the construction and completion of the Q7000, which commenced operations in January 2020.
Financing Activities
Cash flows from financing activities consist primarily of proceeds from debt and equity transactions and repayments related to our long-term debt. 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 (Note 8). Net cash outflows from financing activities of $52.6 million in 2020 primarily reflect the repayment of $46.4 million related to our indebtedness as well as our repurchase of $90 million of the 2022 Notes and $95 million of the 2023 Notes and entry into the capped call transactions associated with the 2026 Notes with proceeds from the issuance of the 2026 Notes in August 2020 (Note 8).
Material Cash Requirements
Our material cash requirements include our obligations to repay our long-term debt, satisfy other contractual cash commitments and fund other obligations.
Long-term debt and other contractual commitments
The following table summarizes 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, 2021 and the portions of those amounts that are short-term (due in less than one year) and long-term (due in one year or greater) based on their stated maturities. Our property and equipment commitments include contractually committed amounts to purchase certain property and equipment and related services but do not include expected capital spending that is not contractually committed as of December 31, 2021. The 2022 Notes, 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 8).
Total
Short-Term
Long-Term
MARAD debt
$
48,850
$
7,937
$
40,913
2022 Notes
35,000
35,000
-
2023 Notes
30,000
-
30,000
2026 Notes
200,000
-
200,000
Interest related to debt
66,875
17,832
49,043
Property and equipment
4,943
4,863
Operating leases (1)
179,305
102,030
77,275
Total cash obligations
$
564,973
$
167,662
$
397,311
(1) Operating leases include vessel charters and facility and equipment leases. At December 31, 2021, our commitment related to long-term vessel charters totaled approximately $156.2 million, of which $63.6 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, 2021.
Other material cash requirements
Other material cash requirements include the following:
Decommissioning. We have decommissioning obligations associated with our oil and gas properties (Note 16). Those obligations approximate $31.0 million (undiscounted) as of December 31, 2021 and are all expected to be paid during the next 12 months. We are entitled to receive certain amounts from Marathon Oil as these decommissioning obligations are fulfilled.
Regulatory certification and dry dock. Our vessels and intervention systems are subject to certain regulatory certification requirements that must be satisfied in order for the vessels and intervention systems to operate. Certification may require dry dock and other compliance costs on a periodic basis, usually every 30 months. These costs can vary and generally range between $3.0 million to $15.0 million per vessel and $0.5 million to $5.0 million per intervention system, and the timing of those costs can vary.
We expect the sources of funds to satisfy our material cash requirements to primarily come from our ongoing operations but can also come from existing cash, availability under the ABL Facility, and access to capital markets.
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.
Property and Equipment
We review our property and equipment for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We evaluate impairment indicators considering the nature of the asset or asset group, the future economic benefits of the asset or asset group, historical and estimated future profitability measures, and other external market conditions or factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and comparing those cash flows to the asset’s carrying value. If the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. The expected future cash flows used for the assessment of recoverability are based on judgmental assessments of operating costs, project margins and capital project spending, considering information available at the date of review. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.
The 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.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2021, we were exposed to market risks associated with foreign currency exchange rates. We had no exposure to interest rate risk as we had no outstanding debt subject to floating rates.
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, resulting in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our consolidated balance sheets. At December 31, 2021, approximately 42% 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, 2021, 2020 and 2019, we recorded foreign currency translation gains (losses) of $(4.5) million, $12.8 million and $5.4 million, respectively, to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments as our non-U.S. undistributed earnings are permanently reinvested.
When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the condensed consolidated statements of operations as a component of “Other income (expense), net.” Foreign currency gains or losses from the remeasurement of 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, 2021, 2020 and 2019, we recorded foreign currency transaction gains (losses) of $(1.5) million, $4.6 million and $1.5 million, respectively, primarily related to our subsidiaries in the U.K.

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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, 2021 and 2020, 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, 2021, 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, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021, 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 24, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Evaluation of property and equipment impairment triggering events
As discussed in Note 2 to the consolidated financial statements, the Company evaluates property and equipment for impairment at least quarterly or whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable, or triggering events. The Company performs this evaluation considering the future economic benefits of the asset or asset groups, historical and estimated future profitability measures, and other factors that may be present, such as extended periods of idle time or the inability to contract the Company’s equipment at economical rates. The carrying value of property and equipment as of December 31, 2021 was $1,658 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.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the evaluation of property and equipment for impairment. This included controls related to the Company’s process to identify and evaluate triggering events that indicate that the carrying value of an asset or asset group may not be recoverable, including the consideration of forecasted to actual results and market conditions in determination of a triggering event. We evaluated the Company’s identification of triggering events, including consideration of future expected revenues from executed contracts. We compared data used by the Company against analyst and industry reports. We compared the Company’s historical forecasts to actual results by asset group to assess the Company’s ability to accurately forecast.
/s/ KPMG LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 24, 2022
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, 2021, 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, 2021, 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, 2021 and 2020, 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, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2022 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Houston, Texas
February 24, 2022
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31,
ASSETS
Current assets:
Cash and cash equivalents
$
253,515
$
291,320
Restricted cash
73,612
-
Accounts receivable, net of allowance for credit losses of $1,477 and $3,469, respectively
144,137
132,233
Other current assets
58,274
102,092
Total current assets
529,538
525,645
Property and equipment
2,938,154
2,948,907
Less accumulated depreciation
(1,280,509)
(1,165,943)
Property and equipment, net
1,657,645
1,782,964
Operating lease right-of-use assets
104,190
149,656
Other assets, net
34,655
40,013
Total assets
$
2,326,028
$
2,498,278
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable
$
87,959
$
50,022
Accrued liabilities
91,712
87,035
Current maturities of long-term debt
42,873
90,651
Current operating lease liabilities
55,739
51,599
Total current liabilities
278,283
279,307
Long-term debt
262,137
258,912
Operating lease liabilities
50,198
101,009
Deferred tax liabilities
86,966
110,821
Other non-current liabilities
3,878
Total liabilities
678,559
753,927
Commitments and contingencies
Redeemable noncontrolling interests
-
3,855
Shareholders’ equity:
Common stock, no par, 240,000 shares authorized, 151,124 and 150,341 shares issued, respectively
1,292,479
1,327,592
Retained earnings
411,072
464,524
Accumulated other comprehensive loss
(56,082)
(51,620)
Total shareholders’ equity
1,647,469
1,740,496
Total liabilities, redeemable noncontrolling interests and shareholders’ equity
$
2,326,028
$
2,498,278
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
Year Ended December 31,
Net revenues
$
674,728
$
733,555
$
751,909
Cost of sales
659,335
653,646
614,071
Gross profit
15,393
79,909
137,838
Gain (loss) on disposition of assets, net
(631)
-
Goodwill impairment
-
(6,689)
-
Selling, general and administrative expenses
(63,449)
(61,084)
(69,841)
Income (loss) from operations
(48,687)
13,025
67,997
Equity in earnings (losses) of investment
(1)
1,439
Net interest expense
(23,201)
(28,531)
(8,333)
Gain (loss) on extinguishment of long-term debt
(136)
9,239
(18)
Other income (expense), net
(1,490)
4,724
1,165
Royalty income and other
2,873
2,710
3,306
Income (loss) before income taxes
(70,642)
1,383
65,556
Income tax provision (benefit)
(8,958)
(18,701)
7,859
Net income (loss)
(61,684)
20,084
57,697
Net loss attributable to redeemable noncontrolling interests
(146)
(2,090)
(222)
Net income (loss) attributable to common shareholders
$
(61,538)
$
22,174
$
57,919
Earnings (loss) per share of common stock:
Basic
$
(0.41)
$
0.13
$
0.39
Diluted
$
(0.41)
$
0.13
$
0.38
Weighted average common shares outstanding:
Basic
150,056
148,993
147,536
Diluted
150,056
149,897
149,577
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Year Ended December 31,
Net income (loss)
$
(61,684)
$
20,084
$
57,697
Other comprehensive income (loss), net of tax:
Net unrealized loss on hedges arising during the period
-
(95)
(680)
Reclassifications into earnings
-
5,470
Income taxes on hedges
-
(72)
(966)
Net change in hedges, net of tax
-
3,824
Foreign currency translation gain (loss)
(4,462)
12,835
5,400
Other comprehensive income (loss), net of tax
(4,462)
13,120
9,224
Comprehensive income (loss)
(66,146)
33,204
66,921
Less comprehensive loss attributable to redeemable noncontrolling interests:
Net loss
(146)
(2,090)
(222)
Foreign currency translation gain
Comprehensive loss attributable to redeemable noncontrolling interests
(96)
(2,000)
(84)
Comprehensive income (loss) attributable to common shareholders
$
(66,050)
$
35,204
$
67,005
The accompanying notes are an integral part of these consolidated financial statements.
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, 2018
148,203
$
1,308,709
$
383,034
$
(73,964)
$
1,617,779
$
-
Net income (loss)
-
-
57,919
-
57,919
(222)
Deferred gain from sale leaseback transaction in retained earnings upon adoption of ASU No. 2016-02
-
-
4,560
-
4,560
-
Foreign currency translation adjustments
-
-
-
5,400
5,400
Unrealized gain on hedges, net of tax
-
-
-
3,824
3,824
-
Issuance of redeemable noncontrolling interests
-
-
-
-
-
3,396
Accretion of redeemable noncontrolling interests
-
-
(143)
-
(143)
Activity in company stock plans, net and other
(1,032)
-
-
(1,032)
-
Share-based compensation
-
11,284
-
-
11,284
-
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
Unrealized gain on hedges, net of tax
-
-
-
-
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)
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
(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
$
-
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
Cash flows from operating activities:
Net income (loss)
$
(61,684)
$
20,084
$
57,697
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization
141,514
133,709
112,720
Goodwill impairment
-
6,689
-
Amortization of debt discounts
-
6,964
6,261
Amortization of debt issuance costs
3,179
3,177
3,600
Share-based compensation
7,689
8,568
11,469
Deferred income taxes
(15,202)
(3,883)
3,485
Equity in (earnings) losses of investment
(216)
(1,439)
(Gain) loss on disposition of assets, net
(889)
-
(Gain) loss on extinguishment of long-term debt
(9,239)
Unrealized gain on derivative contracts, net
-
(601)
(3,383)
Unrealized foreign currency (gain) loss
2,252
(2,665)
(628)
Changes in operating assets and liabilities:
Accounts receivable, net
(14,154)
(8,419)
(3,050)
Income tax receivable, net of income tax payable
18,610
(22,124)
(4,456)
Other current assets
22,973
(28,664)
25,383
Accounts payable and accrued liabilities
46,645
10,830
(31,265)
Other, net
(12,473)
(14,521)
(6,743)
Net cash provided by operating activities
140,117
98,800
169,669
Cash flows from investing activities:
Capital expenditures
(8,322)
(20,244)
(140,854)
STL acquisition, net
-
-
(4,081)
Proceeds from sale of assets
2,550
Net cash used in investing activities
(8,271)
(19,281)
(142,385)
Cash flows from financing activities:
Proceeds from convertible senior notes
-
200,000
-
Repayment of convertible senior notes
-
(183,150)
-
Proceeds from Term Loan
-
-
35,000
Repayment of Term Loan
(29,826)
(3,500)
(35,442)
Repayment of Nordea Q5000 Loan
(53,572)
(35,714)
(35,714)
Repayment of MARAD Debt
(7,560)
(7,200)
(6,858)
Capped call transactions
-
(10,625)
-
Debt issuance costs
(1,337)
(7,747)
(1,586)
Acquisition of redeemable noncontrolling interests
(2,355)
-
-
Payments related to tax withholding for share-based compensation
(2,001)
(5,264)
(1,680)
Proceeds from issuance of ESPP shares
Net cash used in financing activities
(95,997)
(52,578)
(45,818)
Effect of exchange rate changes on cash and cash equivalents and restricted cash
(42)
1,818
1,636
Net increase (decrease) in cash and cash equivalents and restricted cash
35,807
28,759
(16,898)
Cash and cash equivalents and restricted cash:
Balance, beginning of year
291,320
262,561
279,459
Balance, end of year
$
327,127
$
291,320
$
262,561
The accompanying notes are an integral part of these consolidated financial statements.
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 and robotics operations. Traditionally, our services have covered the lifecycle of an offshore oil or gas field. In recent years, we have seen an increasing demand for our services from the offshore renewable energy market. We provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations 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 three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 15).
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, some of which we provide on a stand-alone basis.
Our Robotics segment provides offshore construction, trenching, seabed clearance, 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 and robotics support vessels under long-term charter as well as spot vessels as needed.
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.
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, 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 our asset-based credit agreement (the “ABL Facility”). These cash pledges increase the availability under the ABL Facility. We had no restricted cash as of December 31, 2020.
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 19).
Property and Equipment
Property and equipment is recorded at historical cost, net of accumulated depreciation. Property and equipment is 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 8) and is included as an investing cash outflow in the consolidated statements of cash flows.
Equity Investment
With respect to our investment accounted for using the equity method of accounting, losses in excess of the carrying amount of our equity investment are recognized when (i) we guaranteed the obligations of the investee, (ii) we are otherwise committed to provide further financial support for the investee, or (iii) it is anticipated that the investee’s return to profitability is imminent. Losses in excess of the carrying amount of our equity investment are presented as a liability in the consolidated balance sheets.
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 7).
Deferred Recertification and Dry Dock Costs
Our vessels and certain well intervention assets 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 30 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 other asset 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 other asset are capitalized and depreciated over the asset’s remaining economic useful life. We expense routine repairs and maintenance costs as they are incurred.
As of December 31, 2021 and 2020, deferred recertification and dry dock costs, which were included within “Other assets, net” in the accompanying consolidated balance sheets (Note 3), totaled $16.3 million and $21.5 million (net of accumulated amortization of $23.6 million and $21.8 million), respectively. During the years ended December 31, 2021, 2020 and 2019, amortization expense related to deferred recertification and dry dock costs was $14.6 million, $14.3 million and $12.4 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 construction and IRM services to oil and gas companies as well as subsea trenching and burial of pipelines and cables as well as seabed clearing for the oil and gas and the renewable energy markets. We also provide integrated robotic services by supplying vessels that deploy ROVs and trenchers. Our Production Facilities segment generates revenue by supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties.
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 consider the undistributed earnings of our non-U.S. subsidiaries to be permanently reinvested.
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, 2021, 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.
Compensation cost for performance share unit (“PSU”) awards that have a service condition and a market condition and are accounted for as equity awards, 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. Compensation cost for PSUs that have a service condition and a performance condition and are accounted for as equity awards 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 at 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 at fair value and consist of estimated costs for subsea infrastructure plug and abandonment (“P&A”) and other decommissioning 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, 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 or expense in the consolidated statements of operations. For the years ended December 31, 2021, 2020 and 2019, our foreign currency transaction gains (losses) totaled $(1.5) million, $4.6 million and $1.5 million, respectively. These realized amounts are exclusive of any gains or losses from our foreign currency exchange derivative contracts.
Derivative Instruments and Hedging Activities
Our business is exposed to market risks associated with interest rates and foreign currency exchange rates. Our risk management activities involve the use of derivative financial instruments to mitigate the impact of market risk exposure related to variable interest rates and foreign currency exchange rates. To reduce the impact of these risks on earnings and increase the predictability of our cash flows, from time to time we enter into derivative contracts, including interest rate swaps and foreign currency exchange contracts. Interest rate and foreign currency derivative instruments are reflected in the consolidated balance sheets at fair value. The capped call transactions (the “2026 Capped Calls”) we entered into in connection with the issuance of our Convertible Senior Notes Due 2026 (the “2026 Notes”) are recorded in shareholders’ equity and are not accounted for as derivatives (Note 8).
We engage solely in cash flow hedges. Cash flow hedges are entered into to hedge the variability of cash flows related to a forecasted transaction or to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are reported in OCI. These changes are subsequently reclassified into earnings when the hedged transactions affect earnings. Changes in the fair value of interest rate and foreign currency derivative instruments that are not designated as or do not qualify for hedge accounting are recorded immediately in earnings.
We formally document all relationships between hedging instruments and the related hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an ongoing basis, whether the derivative instruments that are designated as hedging instruments are highly effective in offsetting changes in cash flows of the hedged items. We discontinue hedge accounting if we determine that a derivative is no longer highly effective as a hedge, or if it is probable that a hedged transaction will not occur. If hedge accounting is discontinued because it is probable the hedged transaction will not occur, gains or losses on the hedging instruments are reclassified from accumulated OCI into earnings immediately.
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: 2021 - Petrobras (23%) and Shell (17%); 2020 - Petrobras (28%) and BP (17%); and 2019 - Petrobras (29%), BP (15%) and Shell (13%). 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 described in Note 20.
New Accounting Standards
New accounting standards adopted
In February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2016-02, “Leases (Topic 842)” (“ASC 842”). Our adoption of ASC 842 as of January 1, 2019 resulted in the recognition of operating lease liabilities of $259.0 million and corresponding ROU assets of $253.4 million (net of existing prepaid/deferred rent balances). In addition, we reclassified the remaining deferred gain of $4.6 million (net of deferred taxes of $0.9 million) on a 2016 sale and leaseback transaction to retained earnings. See Note 6 for additional information regarding our leases.
In June 2016, the FASB issued 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 19 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 the 2026 Notes (Note 8), 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 - Details of Certain Accounts
Other current assets consist of the following (in thousands):
December 31,
Contract assets (Note 12)
$
$
2,446
Prepaids
18,228
15,904
Deferred costs (Note 12)
2,967
23,522
Income tax receivable (Note 9)
1,116
20,787
Other receivable (Note 16)
28,805
29,782
Other
6,519
9,651
Total other current assets
$
58,274
$
102,092
Other assets, net consist of the following (in thousands):
December 31,
Deferred recertification and dry dock costs, net (Note 2)
$
16,291
$
21,464
Deferred costs (Note 12)
Charter deposit (1)
12,544
12,544
Intangible assets with finite lives, net
3,472
3,809
Other
1,967
1,335
Total other assets, net
$
34,655
$
40,013
(1) This amount is deposited with the owner of the Siem Helix 2 to offset certain payment obligations associated with the vessel at the end of the charter term.
Accrued liabilities consist of the following (in thousands):
December 31,
Accrued payroll and related benefits
$
28,657
$
24,768
Accrued interest
6,746
7,098
Investee losses in excess of investment (Note 5)
1,499
Deferred revenue (Note 12)
8,272
8,140
Asset retirement obligations (Note 16)
29,658
30,913
Other
17,582
14,617
Total accrued liabilities
$
91,712
$
87,035
Other non-current liabilities consist of the following (in thousands):
December 31,
Deferred revenue (Note 12)
$
$
1,869
Other
2,009
Total other non-current liabilities
$
$
3,878
Note 4 - Property and Equipment
The following is a summary of the gross components of property and equipment (dollars in thousands):
December 31,
Estimated Useful Life
Vessels
15 to 30 years
$
2,343,162
$
2,349,752
ROVs and trenchers
10 years
257,274
263,968
Machinery, equipment and leasehold improvements
5 to 15 years
337,718
335,187
Total property and equipment
$
2,938,154
$
2,948,907
Note 5 - Equity Method Investments
We have a 20% ownership interest in Independence Hub, LLC (“Independence Hub”) that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform, which is nearing the completion of its decommissioning. The remaining liability balances for our share of Independence Hub’s estimated obligations, net of remaining working capital, were $0.8 million and $1.5 million at December 31, 2021 and 2020, respectively.
Note 6 - Leases
We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, 2021, the minimum sublease income to be received in the future totaled $1.5 million.
The following table details the components of our lease cost (in thousands):
Year Ended December 31,
Operating lease cost
$
60,636
$
64,742
$
70,860
Variable lease cost
16,711
15,021
13,780
Short-term lease cost
20,590
37,524
20,384
Sublease income
(1,303)
(1,286)
(1,391)
Net lease cost
$
96,634
$
116,001
$
103,633
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
Maturities of our operating lease liabilities as of December 31, 2020 are as follows (in thousands):
Facilities and
Vessels
Equipment
Total
Less than one year
$
54,621
$
6,028
$
60,649
One to two years
52,106
5,435
57,541
Two to three years
34,580
4,649
39,229
Three to four years
2,470
4,374
6,844
Four to five years
-
2,340
2,340
Over five years
-
4,054
4,054
Total lease payments
$
143,777
$
26,880
$
170,657
Less: imputed interest
(13,352)
(4,697)
(18,049)
Total operating lease liabilities
$
130,425
$
22,183
$
152,608
Current operating lease liabilities
$
46,748
$
4,851
$
51,599
Non-current operating lease liabilities
83,677
17,332
101,009
Total operating lease liabilities
$
130,425
$
22,183
$
152,608
The following table presents the weighted average remaining lease term and discount rate:
December 31,
Weighted average remaining lease term
2.4
years
3.1
years
4.0
years
Weighted average discount rate
7.57
%
7.53
%
7.54
%
The following table presents other information related to our operating leases (in thousands):
Year Ended December 31,
Cash paid for operating lease liabilities
$
61,826
$
66,026
$
71,698
Right-of-use assets obtained in exchange for new operating lease obligations
5,992
1,168
Note 7 - Business Combinations and Goodwill
Oil prices as well as energy and energy services valuations experienced significant decline during the first quarter 2020 due to the COVID-19 pandemic and the price war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”). As a result, we impaired all of our goodwill, which consisted entirely of goodwill attributable to the acquisition in May 2019 of a 70% controlling interest in STL, a subsea engineering firm based in Aberdeen, Scotland. In June 2021, we acquired the remaining 30% noncontrolling interest in STL. These redeemable noncontrolling interests 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
$
-
Note 8 - Long-Term Debt
Long-term debt consists of the following (in thousands):
December 31,
Term Loan (repaid September 2021) (1)
$
-
$
29,750
Nordea Q5000 Loan (matured January 2021) (2)
-
53,572
2022 Notes (mature May 2022)
35,000
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)
48,850
56,410
Unamortized debt discounts (3)
-
(45,692)
Unamortized debt issuance costs
(8,840)
(9,477)
Total debt
305,010
349,563
Less current maturities
(42,873)
(90,651)
Long-term debt
$
262,137
$
258,912
(1) The Term Loan was fully repaid in September 2021 concurrent with our entering into the ABL Facility.
(2) The Nordea Q5000 Loan was fully repaid upon maturity in January 2021.
(3) As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there are no longer any debt discounts associated with the 2022 Notes, the 2023 Notes and the 2026 Notes (Note 2).
Credit Agreement
On September 30, 2021, we entered into the ABL Facility with Bank of America, N.A. (“Bank of America”), Wells Fargo Bank, N.A. and Zions Bancorporation. The ABL Facility provides for an $80 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 ABL Facility also permits us to request an increase of the facility by up to $70 million, subject to certain conditions.
Commitments under the ABL Facility are comprised of separate U.S. and U.K. revolving credit facility commitments of $45 million and $35 million, respectively. The 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, 2021, we had no borrowings under the ABL Facility, and our available borrowing capacity under that facility, based on the borrowing base, totaled $51.1 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 are the initial borrowers under the ABL Facility, whose obligations under the 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 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 ABL Facility initially bear interest at the LIBOR 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 ABL Facility denominated in U.S. dollars initially bear interest at the LIBOR rate and U.K. borrowings denominated in the British pound initially 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. Beginning on the earlier of June 30, 2023, cessation of LIBOR or an earlier opt-in election, LIBOR will be replaced by either SOFR or term SOFR plus a margin of 0.114% to 0.428% or an alternate benchmark rate.
The 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 ABL Facility contains customary default provisions which, if triggered, could result in acceleration of all amounts then outstanding. The 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 $8 million. The ABL Facility also requires us to maintain a pro forma minimum excess availability of $16 million for the 91 days prior to the maturity of each of our outstanding convertible senior notes.
2022 Notes
The 2022 Notes bear interest at a coupon interest rate of 4.25% per annum payable semi-annually in arrears on November 1 and May 1 of each year until maturity. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased by us. The 2022 Notes are convertible by their holders at any time beginning February 1, 2022 at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal, which currently represents 2,519,118 potentially convertible shares at an initial conversion price of approximately $13.89 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 February 1, 2022, holders of the 2022 Notes were able to convert their notes if the closing price of our common stock exceeded 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 2022 Notes was 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 2022 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 30.5887 shares of our common stock per $1,000 principal amount.
Prior to November 1, 2019, the 2022 Notes were not redeemable. On or after November 1, 2019, we may redeem all or any portion of the 2022 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 2022 Notes may convert any of their notes if we call the notes for redemption. Holders of the 2022 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 2022 Notes).
The indenture governing the 2022 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 subsidiary, the principal amount of the 2022 Notes together with any accrued interest will become immediately due and payable.
The 2022 Notes were initially separated between the equity component recognized in shareholders’ equity and the debt component, which was presented as long-term debt, net of the unamortized debt discount and debt issuance costs. The unamortized debt discount and debt issuance costs were being accreted to interest expense through the maturity date of the 2022 Notes. As of December 31, 2020, unamortized debt discount and debt issuance costs related to the 2022 Notes totaled $1.5 million. As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the 2022 Notes (Note 2). As of December 31, 2021, unamortized debt issuance costs related to the 2022 Notes were $0.1 million.
The effective interest rate for the 2022 Notes prior to the adoption of ASU No. 2020-06 was 7.3%. The effective interest rate subsequent to the adoption of ASU No. 2020-06 decreased to 4.8%. For the year ended December 31, 2021, total interest expense related to the 2022 Notes was $1.7 million, with coupon interest expense of $1.5 million and the amortization of issuance costs of $0.2 million. For the years ended December 31, 2020 and 2019, total interest expense related to the 2022 Notes was $6.6 million and $8.9 million, respectively, with coupon interest expense of $3.9 million and $5.3 million, respectively, and the amortization of debt discount and issuance costs of $2.7 million and $3.6 million, respectively.
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 was 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 2023 Notes were initially separated between the equity component recognized in shareholders’ equity and the debt component, which was presented as long-term debt, net of the unamortized debt discount and debt issuance costs. The unamortized debt discount and debt issuance costs were being accreted to interest expense through the maturity date of the 2023 Notes. As of December 31, 2020, unamortized debt discount and debt issuance costs related to the 2023 Notes totaled $3.1 million. As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the 2023 Notes (Note 2). As of December 31, 2021, unamortized debt issuance costs related to the 2023 Notes were $0.3 million.
The effective interest rate for the 2023 Notes prior to the adoption of ASU No. 2020-06 was 7.8%. The effective interest rate subsequent to the adoption of ASU No. 2020-06 decreased to 4.8%. For the year ended December 31, 2021, total interest expense related to the 2023 Notes was $1.4 million, with coupon interest expense of $1.2 million and the amortization of issuance costs of $0.2 million. For the years ended December 31, 2020 and 2019, total interest expense related to the 2023 Notes was $6.6 million and $8.9 million, respectively, with coupon interest expense of $3.7 million and $5.2 million, respectively, and the amortization of debt discount and issuance costs of $2.9 million and $3.7 million, respectively.
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 the 2026 Capped Calls in August 2020 concurrent with the 2026 Notes offering (Note 10). 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 was 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 2026 Notes were initially separated between the equity component recognized in shareholders’ equity and the debt component, which was presented as long-term debt, net of the unamortized debt discount and debt issuance costs. The unamortized debt discount and debt issuance costs were being accreted to interest expense through the maturity date of the 2026 Notes. As of December 31, 2020, unamortized debt discount and debt issuance costs related to the 2026 Notes totaled $47.3 million. As a result of the adoption of ASU No. 2020-06 beginning January 1, 2021, there is no longer any debt discount (or related accretion) associated with the 2026 Notes (Note 2). As of December 31, 2021, unamortized debt issuance costs related to the 2026 Notes were $5.9 million.
The effective interest rate for the 2026 Notes prior to the adoption of ASU No. 2020-06 was 12.4%. The effective interest rate subsequent to the adoption of ASU No. 2020-06 decreased to 7.6%. For the year ended December 31, 2021, total interest expense related to the 2026 Notes was $14.7 million, with coupon interest expense of $13.5 million and the amortization of debt issuance costs of $1.2 million. 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, matures in 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
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. As of December 31, 2020, the remaining principal amount of the Nordea Q5000 Loan was $53.6 million, which we repaid in January 2021.
We previously had another 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, 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.
In accordance with the ABL Facility, the 2022 Notes, the 2023 Notes, the 2026 Notes and the MARAD Debt, we are required to comply with certain covenants, including a springing fixed charge coverage ratio and minimum liquidity with respect to the 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, 2021, we were in compliance with these covenants.
Scheduled maturities of our long-term debt outstanding as of December 31, 2021 are as follows (in thousands):
MARAD
Notes
Notes
Notes
Debt
Total
Less than one year
$
35,000
$
-
$
-
$
7,937
$
42,937
One to two years
-
30,000
-
8,333
38,333
Two to three years
-
-
-
8,749
8,749
Three to four years
-
-
-
9,186
9,186
Four to five years
-
-
200,000
9,644
209,644
Over five years
-
-
-
5,001
5,001
Gross debt
35,000
30,000
200,000
48,850
313,850
Unamortized debt issuance costs (1)
(64)
(314)
(5,901)
(2,561)
(8,840)
Total debt
34,936
29,686
194,099
46,289
305,010
Less current maturities
(34,936)
-
-
(7,937)
(42,873)
Long-term debt
$
-
$
29,686
$
194,099
$
38,352
$
262,137
(1) Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement. See Note 2 for accounting changes as a result of the adoption of ASU No. 2020-06.
The following table details the components of our net interest expense (in thousands):
Year Ended December 31,
Interest expense
$
23,489
$
30,538
$
31,186
Capitalized interest (1)
-
(1,182)
(20,246)
Interest income
(288)
(825)
(2,607)
Net interest expense
$
23,201
$
28,531
$
8,333
(1) The significant reduction in capitalized interest was attributable to the conclusion of our planned major capital commitments following the completion of the Q7000 in 2020.
Note 9 - Income Taxes
We are a U.S.-based multinational corporation subject to taxation in multiple jurisdictions. We believe that our deferred tax assets and liabilities for all jurisdictions are reasonable and fairly presented. Tax laws in each jurisdiction, as well as their interactions, are complex and their interpretation requires significant judgment.
Components of income tax provision (benefit) reflected in the consolidated statements of operations consist of the following (in thousands):
Year Ended December 31,
Current tax provision (benefit):
Domestic
$
(1,103)
$
(18,927)
$
(2)
Foreign
7,347
4,109
4,376
Total current
$
6,244
$
(14,818)
$
4,374
Deferred tax provision (benefit):
Domestic
$
(5,756)
$
3,853
$
3,717
Foreign
(9,446)
(7,736)
(232)
Total deferred
$
(15,202)
$
(3,883)
$
3,485
Total income tax provision (benefit)
$
(8,958)
$
(18,701)
$
7,859
Components of income (loss) before income taxes are as follows (in thousands):
Year Ended December 31,
Domestic
$
(53,989)
$
(3,406)
$
2,219
Foreign
(16,653)
4,789
63,337
Income (loss) before income taxes
$
(70,642)
$
1,383
$
65,556
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,
Taxes at U.S. statutory rate
$
(14,835)
21.0
%
$
21.0
%
$
13,767
21.0
%
Foreign tax provision (benefit)
10,856
(15.3)
(3,426)
(247.7)
(6,557)
(10.0)
CARES Act
-
-
(7,596)
(549.2)
-
-
Subsidiary restructuring
-
-
(8,333)
(602.5)
-
-
Valuation allowance release (net of U.S. tax)
(5,040)
7.1
-
-
-
-
Other
(0.1)
26.2
1.0
Income tax provision (benefit)
$
(8,958)
12.7
%
$
(18,701)
(1,352.2)
%
$
7,859
12.0
%
The U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which was signed into law on March 27, 2020, is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses, which previously had been required to be carried forward, at the tax rates applicable in the relevant carryback year. Under the CARES Act, 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 claim) and an $11.3 million deferred tax expense (reduction in U.S. net operating loss). The refund was received in full during 2021.
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.
During the year ended December 31, 2021, we released a non-U.S. valuation allowance of $6.4 million ($5.0 million net of U.S. federal tax benefit) for deferred tax assets as it is more likely than not that they will be fully utilized.
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,
Deferred tax liabilities:
Depreciation
$
137,898
$
153,226
Debt discounts on 2022 Notes, 2023 Notes and 2026 Notes
-
9,298
Prepaid and other
1,088
-
Total deferred tax liabilities
$
138,986
$
162,524
Deferred tax assets:
Net operating losses
$
(56,369)
$
(59,794)
Reserves, accrued liabilities and other
(9,698)
(11,631)
Total deferred tax assets
(66,067)
(71,425)
Valuation allowance
14,047
19,722
Net deferred tax liabilities
$
86,966
$
110,821
At December 31, 2021, our U.S. net operating losses available for carryforward totaled $180.0 million, of which $112.3 million will begin to expire between 2035 and 2037, with the remaining $67.7 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, 2021, we had $5.3 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, 2021, our non-U.S. net operating losses totaled $71.0 million, and do not expire under local tax law.
At December 31, 2021, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $62.9 million. Due to the enactment of the U.S. Tax Cuts and Jobs Act (the “2017 Tax 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. Management intends to indefinitely reinvest these earnings to fund our international operations. In addition, we expect future U.S. cash generation will be sufficient to meet future U.S. cash needs. Due to complexities in the tax laws and the manner of repatriation, it is not practicable to calculate the deferred income taxes associated with these undistributed earnings.
As of December 31, 2021, we had unrecognized tax benefits of $0.1 million related to uncertain tax positions, which, if recognized, would affect 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. We did not record any interest related to these positions in 2021 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 2021 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 2021.
Note 10 - 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 8), 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 sheet.
Note 11 - Stock Buyback Program
Our Board of Directors (our “Board”) has 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 14). We may continue to make repurchases pursuant to this authority from time to time as additional equity is issued under our stock-based plans depending on prevailing market conditions and other factors. As described in an announced plan, all repurchases may be commenced or suspended at any time as determined by management. We have not purchased any shares available under this program since 2015. As of December 31, 2021, 8,182,193 shares of our common stock were available for repurchase under the program.
Note 12 - Revenue from Contracts with Customers
Disaggregation of Revenue
The following table provides information about disaggregated revenue by contract duration (in thousands):
Well
Production
Intercompany
Total
Intervention
Robotics
Facilities
Eliminations
Revenue
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
Year ended December 31, 2019
Short-term
$
214,926
$
94,501
$
-
$
-
$
309,427
Long-term
378,374
77,171
61,210
(74,273)
442,482
Total
$
593,300
$
171,672
$
61,210
$
(74,273)
$
751,909
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 3). Contract assets as of December 31, 2021 and 2020 were $0.6 million and $2.4 million, respectively. We had no credit losses on our contract assets for the years ended December 31, 2021, 2020 and 2019.
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 3). Contract liabilities as of December 31, 2021 and 2020 totaled $8.7 million and $10.0 million, respectively. Revenue recognized for the years ended December 31, 2021, 2020 and 2019 included $7.9 million, $11.6 million and $10.1 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, 2021, $348.2 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $245.9 million, $102.1 million and $0.2 million in 2022, 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, 2021.
For the years ended December 31, 2021 and 2020, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial. For the year ended December 31, 2019, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were $2.1 million, which resulted from the recognition of previously constrained variable consideration for contractual adjustments related to withholding taxes in Brazil.
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 3). Our deferred contract costs as of December 31, 2021 and 2020 totaled $3.3 million and $24.4 million, respectively. For the years ended December 31, 2021, 2020 and 2019, we recorded $39.1 million, $35.8 million and $31.5 million, respectively, related to amortization of deferred contract costs. There were no associated impairment losses for any period presented.
Note 13 - Earnings Per Share
The computations of the numerator (income) 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,
Income
Shares
Income
Shares
Income
Shares
Basic:
Net income (loss) attributable to common shareholders
$
(61,538)
$
22,174
$
57,919
Less: Undistributed earnings allocated to participating securities
-
(140)
(487)
Less: Accretion of redeemable noncontrolling interests
(241)
(2,400)
(143)
Net income (loss) available to common shareholders, basic
$
(61,779)
150,056
$
19,634
148,993
$
57,289
147,536
Diluted:
Net income (loss) available to common shareholders, basic
$
(61,779)
150,056
$
19,634
148,993
$
57,289
147,536
Effect of dilutive securities:
Share-based awards other than participating securities
-
-
-
-
2,041
Undistributed earnings reallocated to participating securities
-
-
-
-
Net income (loss) available to common shareholders, diluted
$
(61,779)
150,056
$
19,635
149,897
$
57,295
149,577
We had a net loss for the year ended December 31, 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,
Diluted shares (as reported)
150,056
Share-based awards
1,282
Total
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 Notes
2,519
6,537
8,997
2023 Notes
3,168
9,391
13,202
2026 Notes
28,676
10,891
-
Note 14 - 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, 2020 and 2019, we made discretionary employer contributions of $1.6 million and $1.0 million, respectively, to the 401(k) plan.
Employee Stock Purchase Plan
On May 15, 2019, our shareholders approved an amendment to and restatement of the ESPP to: (i) increase the shares authorized for issuance by 1.5 million shares and (ii) delegate to an internal administrator the authority to establish the maximum shares purchasable during a purchase period. As of December 31, 2021, 1.6 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 100% on the third anniversary date of the grant.
On May 15, 2019, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan to: (i) authorize 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy, (ii) establish a maximum award limit applicable to independent members of our Board under the 2005 Incentive Plan, (iii) require, subject to certain exceptions, that all awards under the 2005 Incentive Plan have a minimum vesting or restriction period of one year and (iv) remove certain requirements with respect to performance-based compensation under Section 162(m) of the Internal Revenue Code that were repealed by the 2017 Tax Act. 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, 2021, there were 5.6 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 2021 under the 2005 Incentive Plan:
Grant Date
Fair Value
Date of Grant
Award Type
Shares/Units
Per Share/Unit
Vesting Period
January 1, 2021 (1)
RSU
452,381
$
4.20
33% per year over three years
January 4, 2021 (1)
PSU
452,381
$
5.33
100% on January 4, 2024
January 4, 2021 (2)
Restricted stock
14,249
$
4.20
100% on January 1, 2023
April 1, 2021 (2)
Restricted stock
9,282
$
5.05
100% on January 1, 2023
July 1, 2021 (2)
Restricted stock
8,403
$
5.71
100% on January 1, 2023
July 23, 2021 (2)
Restricted stock
14,664
$
4.54
100% on July 23, 2022
October 1, 2021 (2)
Restricted stock
12,685
$
3.88
100% on January 1, 2023
December 8, 2021 (2)
Restricted stock
273,558
$
3.29
100% on December 8, 2022
(1) Reflects grants to our executive officers.
(2) Reflects grants to certain independent members of our Board.
In January 2022, we granted our executive officers 1,065,705 RSUs and 1,065,705 PSUs under the 2005 Incentive Plan. The grant date fair value of the RSUs was $3.12 per unit or $3.3 million. The grant date fair value of the PSUs was $4.25 per unit or $4.5 million. PSUs and RSUs issued in 2022 are payable in either cash or stock at the discretion of the Compensation Committee. Also in January 2022, we granted $5.0 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,
Grant Date
Grant Date
Grant Date
Shares
Fair Value (1)
Shares
Fair Value (1)
Shares
Fair Value (1)
Awards outstanding at beginning of year
1,176,951
$
6.61
1,173,045
$
6.81
1,320,989
$
7.40
Granted
332,841
3.59
667,752
7.06
846,835
6.02
Vested (2)
(656,066)
6.35
(631,498)
7.52
(993,361)
6.92
Forfeited
-
-
(32,348)
5.41
(1,418)
8.82
Awards outstanding at end of year
853,726
$
5.62
1,176,951
$
6.61
1,173,045
$
6.81
(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, 2021, 2020 and 2019 was $2.6 million, $5.4 million and $6.5 million, respectively.
For the years ended December 31, 2021, 2020 and 2019, $3.3 million, $4.2 million and $6.2 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost associated with unvested restricted stock at December 31, 2021 totaled approximately $2.2 million. The weighted average vesting period related to unvested restricted stock at December 31, 2021 was approximately 0.7 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 contain a service condition and a market condition. PSUs granted in 2021 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee and are initially accounted for as equity awards. The PSUs granted in 2021 consist of two components: (i) 50% based on the performance of our common stock against peer group companies, which contains a service condition and a market condition, and (ii) 50% based on cumulative total Free Cash Flow, which contains a service condition 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. The maximum payout at vesting of our PSUs is 200% of the original PSU awards and the minimum payout is zero.
The following table summarizes information about our equity PSU awards:
Year Ended December 31,
Grant Date
Grant Date
Grant Date
Units
Fair Value (1)
Units
Fair Value (1)
Units
Fair Value (1)
Equity PSU awards outstanding at beginning of year
1,297,126
$
9.99
1,565,044
$
10.17
1,006,360
$
11.76
Granted
452,381
5.33
369,938
13.15
688,540
7.60
Vested
(368,038)
10.44
(589,335)
12.64
-
-
Forfeited
-
-
(48,521)
7.60
(129,856)
8.91
Equity PSU awards outstanding at end of year
1,381,469
$
8.34
1,297,126
$
9.99
1,565,044
$
10.17
(1) Represents the weighted average grant date fair value.
For the years ended December 31, 2021, 2020 and 2019, $4.1 million, $4.0 million and $5.1 million, respectively, were recognized as share-based compensation related to equity PSUs. Future compensation cost associated with unvested equity PSU awards at December 31, 2021 totaled approximately $3.9 million. The weighted average vesting period related to unvested equity PSUs at December 31, 2021 was approximately 0.9 year. In January 2022, 559,150 equity 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 equity PSUs granted in 2018 vested at 200%, representing 736,075 shares of our common stock with a total market value of $3.1 million. In January 2020, 589,335 equity PSUs granted in 2017 vested at 200%, representing 1,178,670 shares of our common stock with a total market value of $11.4 million.
RSU Awards
RSUs granted in 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. Compensation cost recognized for the year ended December 31, 2021 was $0.5 million, which reflects the value of RSUs that were granted in 2021 and paid out in January 2022.
Cash Awards
In 2021, 2020 and 2019, we granted $3.5 million, $4.7 million and $4.6 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, 2021, 2020 and 2019, we recognized compensation costs of $4.0 million and $4.4 million and $3.2 million, respectively, which reflected the cash payouts made in January 2022, 2021 and 2020, respectively.
Note 15 - Business Segment Information
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention 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. 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 offshore construction, trenching, seabed clearance 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 and robotics support vessels under long-term charter as well as spot vessels as needed. Our Production Facilities segment includes the HP I, the HFRS and our ownership of oil and gas properties (Note 16). All material intercompany transactions between the segments have been eliminated.
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,
Net revenues -
Well Intervention
$
516,564
$
539,249
$
593,300
Robotics
137,295
178,018
171,672
Production Facilities
69,348
58,303
61,210
Intercompany eliminations
(48,479)
(42,015)
(74,273)
Total
$
674,728
$
733,555
$
751,909
Income (loss) from operations -
Well Intervention
$
(35,882)
$
26,855
$
89,564
Robotics
5,762
13,755
7,261
Production Facilities
22,906
15,975
17,160
Segment operating income (loss)
(7,214)
56,585
113,985
Goodwill impairment (1)
-
(6,689)
-
Corporate, eliminations and other
(41,473)
(36,871)
(45,988)
Total
$
(48,687)
$
13,025
$
67,997
Net interest expense
(23,201)
(28,531)
(8,333)
Other non-operating income (expense), net
1,246
16,889
5,892
Income (loss) before income taxes
$
(70,642)
$
1,383
$
65,556
Capital expenditures -
Well Intervention
$
2,349
$
19,523
$
139,212
Robotics
Production Facilities
6,770
-
Corporate, eliminations and other
(917)
1,102
Total
$
8,322
$
20,244
$
140,854
Depreciation and amortization -
Well Intervention
$
107,551
$
101,756
$
80,153
Robotics
15,158
15,952
16,459
Production Facilities
19,465
15,652
15,658
Corporate and eliminations
(660)
Total
$
141,514
$
133,709
$
112,720
(1) Relates to the impairment of the entire STL goodwill balance (Note 7).
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,
Well Intervention (1)
$
21,521
$
15,039
$
43,484
Robotics
26,958
26,976
30,789
Total
$
48,479
$
42,015
$
74,273
(1) Amount for the year ended December 31, 2019 included $27.5 million associated with the P&A work on our oil and gas properties in our Production Facilities segment (Note 16).
Revenues by individually significant geographic location are as follows (in thousands):
Year Ended December 31,
U.S.
$
232,661
$
304,563
$
297,162
U.K.
100,154
133,005
193,903
Brazil
154,326
208,565
216,796
West Africa
126,856
41,840
Other
60,731
45,582
43,402
Total
$
674,728
$
733,555
$
751,909
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,
U.S.
$
693,062
$
750,986
U.K. (1)
713,385
764,070
Brazil (2)
251,194
267,896
Singapore
Total
$
1,657,645
$
1,782,964
(1) Includes the Q7000 and certain other assets that are based in the U.K. but are currently operating 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 currently operating 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,
December 31,
Well Intervention
$
2,012,214
$
2,134,081
Robotics
96,249
132,550
Production Facilities
119,004
129,773
Corporate and other
98,561
101,874
Total
$
2,326,028
$
2,498,278
Note 16 - Asset Retirement Obligations
Our AROs relate to our Droshky oil and gas properties that we acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019. In connection with assuming the P&A obligations related to those assets, we are entitled to receive agreed-upon amounts from Marathon Oil as the P&A work is completed. The following table describes the changes in our AROs (in thousands):
AROs at January 1,
$
30,913
$
28,258
$
-
Liability incurred during the period
-
-
53,294
Liability settled during the period
-
-
(28,296)
Revisions in estimates
(2,631)
-
Accretion expense
1,376
2,655
2,438
AROs at December 31,
$
29,658
$
30,913
$
28,258
Note 17 - Commitments and Contingencies and Other Matters
Commitments
We have long-term charter agreements with Siem Offshore AS (“Siem”) for the Siem Helix 1 and Siem Helix 2 vessels, which historically have been used in connection with our contracts with Petrobras to perform well intervention work offshore Brazil. The initial term of the charter agreements with Siem is for seven years, with options to extend. The Siem Helix 1 charter expires June 2023 and the Siem Helix 2 charter expires February 2024. We have time charter agreements for the Grand Canyon II and Grand Canyon III vessels. The expiration date of the Grand Canyon II charter was extended to December 2022, with an option to renew. The Grand Canyon III charter expires May 2023.
Contingencies and Claims
We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations and cash flows.
Litigation
We are involved in various legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and 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 one such lawsuit, during the third quarter 2021 the United States Court of Appeals for the Fifth Circuit issued a ruling adverse to us that may also have implications for some of the other cases in which we are involved, as well as the way offshore personnel are compensated throughout our industry. We have further appealed this matter and continue to vigorously defend these lawsuits. Notwithstanding that we believe we retain valid defenses, at this time we have established a liability for probable losses in certain 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 18 - Statement of Cash Flow Information
The following table provides supplemental cash flow information (in thousands):
Year Ended December 31,
Interest paid, net of interest capitalized
$
20,719
$
15,943
$
1,909
Income taxes paid (1)
8,310
7,434
8,856
(1) Exclusive of income tax refunds. During the year ended December 31, 2021, we received $18.9 million in refunds related to the CARES Act.
Our capital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, 2021 and 2020, these non-cash capital additions totaled $0.3 million and $1.6 million, respectively.
Note 19 - 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, 2021 (in thousands):
Allowance for
Deferred Tax Asset
Credit Losses
Valuation Allowance
Balance at December 31, 2018
$
-
$
17,940
Adjustments
-
Balance at December 31, 2019
-
18,631
Additions (1)
2,684
-
Adjustments (2)
1,091
Balance at December 31, 2020
3,469
19,722
Reductions (1)
(146)
-
Write-offs (3)
(1,846)
-
Adjustments (4)
-
(5,675)
Balance at December 31, 2021
$
1,477
$
14,047
(1) Additions (reductions) in allowance for credit losses reflect credit loss reserves during the respective years, including a $1.7 million credit loss reserve in 2020 related to a receivable in our Robotics segment.
(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.
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 9 for a detailed discussion of the valuation allowance related to our deferred tax assets.
Note 20 - Fair Value Measurements
Assets and liabilities measured at fair value are based on one or more of three valuation approaches as follows:
(a)
Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.
(b)
Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).
(c)
Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).
Our financial instruments include cash and cash equivalents, receivables, accounts payable and long-term debt. The carrying amount of cash and cash equivalents, trade and other current receivables as well as accounts payable approximates fair value due to the short-term nature of these instruments.
The principal amount and estimated fair value of our long-term debt are as follows (in thousands):
December 31, 2021
December 31, 2020
Principal
Fair
Principal
Fair
Amount (1)
Value (2) (3)
Amount (1)
Value (2) (3)
Term Loan (repaid September 2021) (4)
$
-
$
-
$
29,750
$
28,969
Nordea Q5000 Loan (matured January 2021) (5)
-
-
53,572
53,598
MARAD Debt (matures February 2027)
48,850
52,481
56,410
62,318
2022 Notes (mature May 2022)
35,000
34,794
35,000
33,513
2023 Notes (mature September 2023)
30,000
29,054
30,000
28,650
2026 Notes (mature February 2026)
200,000
200,562
200,000
211,383
Total debt
$
313,850
$
316,891
$
404,732
$
418,431
(1) Principal amount includes current maturities and excludes any related unamortized debt discount and debt issuance costs. See Note 8 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 Term Loan, the Nordea Q5000 Loan and 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.
(3) The principal amount and estimated fair value of the 2022 Notes, the 2023 Notes and the 2026 Notes are for the entire instrument inclusive of the conversion feature, which had been accounted for in shareholders’ equity through December 31, 2020.
(4) The Term Loan was fully repaid in September 2021 concurrent with our entering into the ABL Facility (Note 8).
(5) The Nordea Q5000 Loan was fully repaid upon maturity in January 2021 (Note 8).
Note 21 - Derivative Instruments and Hedging Activities
In June 2015, we entered into interest rate swap contracts to fix the interest rate on $187.5 million of the Nordea Q5000 Loan (Note 8). These swap contracts expired in April 2020. Our interest rate swap contracts qualified for cash flow hedge accounting treatment.
In February 2013, we entered into foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand Canyon II and Grand Canyon III charter payments denominated in the Norwegian kroner through July 2019 and February 2020, respectively. A portion of our foreign currency exchange contracts qualified for hedge accounting treatment.
We had no derivative instruments as of December 31, 2021 and 2020. The following tables present the impact that derivative instruments designated as hedging instruments had on our accumulated OCI (net of tax) and our consolidated statements of operations for the years ended December 31, 2020 and 2019 (in thousands):
Unrealized Loss Recognized in OCI
Year Ended December 31,
Foreign exchange contracts
$
(54)
$
(315)
Interest rate swaps
(41)
(365)
$
(95)
$
(680)
Location of Gain (Loss)
Gain (Loss) Reclassified from
Reclassified from
Accumulated OCI into Earnings
Accumulated OCI into
Year Ended December 31,
Earnings
Foreign exchange contracts
Cost of sales
$
(455)
$
(6,125)
Interest rate swaps
Net interest expense
$
(452)
$
(5,470)
The following table presents the impact that derivative instruments not designated as hedging instruments had on our consolidated statements of operations for the years ended December 31, 2020 and 2019 (in thousands):
Loss Recognized in Earnings
Location of Loss
Year Ended December 31,
Recognized in Earnings
Foreign exchange contracts
Other income (expense), net
$
(81)
$
(378)
$
(81)
$
(378)

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2021 to provide reasonable assurance that the information required to be disclosed in our reports under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
(b)Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. This process includes policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risks that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management assessed the effectiveness of our internal control over financial reporting at December 31, 2021. 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, 2021, our internal control over financial reporting was effective.
The effectiveness of our internal control over financial reporting as of December 31, 2021 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 2021 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information
None.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 2022 Annual Meeting of Shareholders to be held on May 18, 2022. 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

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ITEM 11. EXECUTIVE COMPENSATION
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 2022 Annual Meeting of Shareholders to be held on May 18, 2022.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
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 2022 Annual Meeting of Shareholders to be held on May 18, 2022.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 2022 Annual Meeting of Shareholders to be held on May 18, 2022.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
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 2022 Annual Meeting of Shareholders to be held on May 18, 2022.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibit and Financial Statement Schedules
(1)
Financial Statements
The following financial statements included on pages 42 through 78 in this Annual Report are for the fiscal year ended December 31, 2021.
● 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, 2021 and 2020
● Consolidated Statements of Operations for the Years Ended December 31, 2021, 2020 and 2019
● Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2021, 2020 and 2019
● Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2021, 2020 and 2019
● Consolidated Statements of Cash Flows for the Years Ended December 31, 2021, 2020 and 2019
● 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)
Exhibit Number
Description
Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.3
Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of August 16, 2000.
Exhibit 4.4 to the 2001 Form 10-K filed on March 28, 2002 (000-22739)
4.4
Amendment No. 1 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of January 25, 2002.
Exhibit 4.9 to the 2002 Form 10-K/A filed on April 8, 2003 (000-22739)
4.5
Amendment No. 2 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of November 15, 2002.
Exhibit 4.4 to the Form S-3 filed on February 26, 2003 (333-103451)
4.6
Amendment No. 3 Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of July 31, 2003.
Exhibit 4.12 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.7
Amendment No. 4 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of December 15, 2004.
Exhibit 4.13 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.8
Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.
Exhibit 4.1 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.9
Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.
Exhibit 4.2 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.10
Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.
Exhibit 4.3 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.11
Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.
Exhibit 4.4 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.12
Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee.
Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.13
Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027.
Exhibit A to Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.14
Form of Third Amended and Restated Promissory Note to United States of America.
Exhibit 4.7 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.15
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)
Exhibit Number
Description
Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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)
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)
Exhibit Number
Description
Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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)
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)
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)
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)
Exhibit Number
Description
Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.11 *
Employment Agreement between Alisa B. Johnson and the Company dated November 17, 2008.
Exhibit 10.3 to the Current Report on Form 8-K filed on November 19, 2008 (001-32936)
10.12 *
Equity Compensation Agreement by and between Helix Energy Solutions Group, Inc. and Alisa Johnson dated May 1, 2019.
Exhibit 10.1 to the Quarterly Report on Form 10-Q filed on July 26, 2019 (001-32936)
10.13 *
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)
10.14 *
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)
10.15 *
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)
10.16 *
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)
10.17 *
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)
10.18 *
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)
10.19 *
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)
10.20
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)
10.21
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)
10.22
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)
10.23
Construction Contract dated as of September 11, 2013 between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd.
Exhibit 10.1 to the Current Report on Form 8-K filed on September 13, 2013 (001-32936)
10.24
Amendment No. 1, dated as of June 8, 2015, to Construction Contract between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd.
Exhibit 10.1 to the Current Report on Form 8-K filed on June 11, 2015 (001-32936)
10.25
Amendment No. 2, dated December 2, 2015, to Construction Contract between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd.
Exhibit 10.1 to the Current Report on Form 8-K filed on December 7, 2015 (001-32936)
10.26
Amendment No. 3, dated November 15, 2017, to Construction Contract between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd.
Exhibit 10.1 to the Current Report on Form 8-K filed on November 20, 2017 (001-32936)
Exhibit Number
Description
Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.27
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)
14.1
Code of Ethics for Chief Executive Officer and Senior Financial Officers.
Filed herewith
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
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
Cover Page Interactive Data File (formatted as inline XBRL and contained in Exhibit 101).
Filed herewith
*Management contracts or compensatory plans or arrangements