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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K

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

For the fiscal year ended December 31, 2019
or

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

For the transition period from__________ to__________
Commission file number 001-32936
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)

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

Registrant’s telephone number, including area code (281) 618-0400
Securities registered pursuant to Section 12(b) of the Act:

Title of each class |  | Trading Symbol(s) |  | Name of each exchange on which registered
Common Stock |  | HLX |  | New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. ☑ Yes ☐ No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐ Yes ☑ No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ☑ Yes ☐ No
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ☑ Yes ☐ No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ☐ Yes ☑ No
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2019 was approximately $905.9 million.
The number of shares of the registrant’s common stock outstanding as of February 21, 2020 was 149,962,115.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 20, 2020 are incorporated by reference into Part III hereof.

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

|  | Page
PART I
Item 1. | Business | 4
Item 1A. | Risk Factors | 15
Item 1B. | Unresolved Staff Comments | 23
Item 2. | Properties | 23
Item 3. | Legal Proceedings | 24
Item 4. | Mine Safety Disclosures | 25
Unnumbered Item | Information about our Executive Officers | 25
PART II
Item 5. | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 26
Item 6. | Selected Financial Data | 27
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 30
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 41
Item 8. | Financial Statements and Supplementary Data | 42
| Report of Independent Registered Public Accounting Firm | 42
| Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting | 44
| Consolidated Balance Sheets as of December 31, 2019 and 2018 | 45
| Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017 | 46
| Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017 | 47
| Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017 | 48
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017 | 49
| Notes to Consolidated Financial Statements | 50
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 82
Item 9A. | Controls and Procedures | 83
Item 9B. | Other Information | 83
PART III
Item 10. | Directors, Executive Officers and Corporate Governance | 83
Item 11. | Executive Compensation | 84
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 84
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 84
Item 14. | Principal Accounting Fees and Services | 84
PART IV
Item 15. | Exhibits, Financial Statement Schedules | 84
Item 16. | Form 10-K Summary | 88
| Signatures | 89

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

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

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

• | statements regarding our backlog and commercial contracts and rates thereunder;

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

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

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

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

• | statements regarding our trade receivables and their collectability;

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

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

• | statements regarding our ability to retain our senior management and other key employees;

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

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

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

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

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

• | the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;

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

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

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

• | the effectiveness and timing of completion of our vessel and/or system upgrades and major maintenance items;

• | unexpected delays in the delivery, chartering or customer acceptance, and terms of acceptance, of our assets;

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

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

• | the success of our risk management activities;

• | the effects of competition;

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

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• | the impact of current and future laws and governmental regulations, including tax and accounting developments, such as the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) and regulations thereunder;

• | the impact of U.K.’s exit from the European Union (the “EU”), known as Brexit, on our business, operations and financial condition, which is unknown at this time;

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

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

• | the effectiveness of our current and future hedging activities;

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

• | the impact of general, market, industry or business conditions.

Our actual results could also differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those described in “Risk Factors” beginning on page 15 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 30 of this Annual Report. Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
We caution you not to place undue reliance on the forward-looking statements. Forward-looking statements are only as of the date they are made, and other than as required under the securities laws, we assume no obligation to update or revise these forward-looking statements, all of which are expressly qualified by the statements in this section, or provide reasons why actual results may differ. All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. We urge you to carefully review and consider the disclosures made in this Annual Report and our reports filed with the Securities and Exchange Commission (“SEC”) and incorporated by reference herein that attempt to advise interested parties of the risks and factors that may affect our business. Please see “Website and Other Available Information” for further details.
PART I
Item 1. Business
OVERVIEW
Helix Energy Solutions Group, Inc. (together with its subsidiaries, unless context requires otherwise, “Helix,” the “Company,” “we,” “us” or “our”) was incorporated in 1979 and in 1983 was re-incorporated in the state of Minnesota. We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. Our services cover the lifecycle of an offshore oil or gas field. We provide services and methodologies that we believe are critical to maximizing production economics. We provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our life of field services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities. For additional information regarding our strategy and business operations, see sections titled “Our Strategy” and “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 as required under its Listed Company Manual in June 2019. 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 13 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.
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OUR STRATEGY
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. We believe that focusing on these services should deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities and/or the regions in which we operate or add capacity to existing services in our key operating regions. Our well intervention fleet expanded with the delivery in November 2019 of the Q7000, a newbuild semi-submersible vessel. The Q7000 commenced operations in Nigeria in January 2020. Chartering vessels with additional capabilities, such as the Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. We expect to benefit from longer-term contracts that offer firm utilization for our vessels and equipment, and we seek to improve utilization of our well intervention fleet in the Gulf of Mexico as we acquire oil and gas properties and perform the plug and abandonment (“P&A”) of the acquired assets as our schedule permits, subject to regulatory timelines.
In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreement and related agreements for the parties to design, develop, manufacture, promote, market and sell on a global basis integrated equipment and services for subsea well intervention. The alliance leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies.
OUR OPERATIONS
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. We provide a full range of services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services 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 chartered Siem Helix 1 and Siem Helix 2 vessels. Our well intervention equipment includes intervention riser systems (“IRSs”) and subsea intervention lubricators (“SILs”), some of which we provide on a stand-alone basis. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and a ROVDrill, which are designed to complement offshore construction and well intervention services, two robotics support vessels under long-term charter: the Grand Canyon II and the Grand Canyon III, and spot vessels, including the Ross Candies, which is under a flexible charter agreement. Our Production Facilities segment includes the Helix Producer I (the “HP I”), a dynamically positioned floating production vessel that currently processes production from the Phoenix field for the field operator, the Helix Fast Response System (the “HFRS”), our ownership interest in Independence Hub, LLC (“Independence Hub”) 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.
Our current services include:

• | Production. Well intervention; intervention engineering; production enhancement; inspection, repair and maintenance of production structures, trees, jumpers, risers, pipelines and subsea equipment; and support for life of field services.

• | Decommissioning. Reclamation and remediation services; well P&A services; pipeline abandonment services; and site inspections.

• | 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. We have experienced increased demand for our services from the renewable energy industry. Some of the services that we provide to these renewable energy businesses include subsea power cable installation, trenching and burial, along with seabed coring and preparation for construction of wind turbine foundations.

• | Production facilities. Provision of our HP I vessel as an oil and natural gas processing facility for services to oil and gas companies operating in the deepwater of the Gulf of Mexico. Currently, the HP I is being utilized to process production from the Phoenix field.

• | 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.

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Well Intervention
We engineer, manage and conduct well intervention operations, which include production enhancement and abandonment, and construction operations in water depths ranging from 200 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 were used in subsea well intervention to troubleshoot or enhance production, shift sleeves, log wells or perform recompletions. 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 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, inspection, repair and maintenance. Our services provide a cost advantage in the development and management of subsea reservoirs. We expect demand for our services to increase due to efficiency gains from our specialized intervention assets.
Our well intervention business currently operates seven vessels and various equipment such as IRSs and SILs, providing services primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa.
The Q7000, our newly completed semi-submersible well intervention vessel built to U.K. North Sea standards, was delivered to us in November 2019. The vessel commenced integrated well intervention operations offshore Nigeria in January 2020.
In the Gulf of Mexico, our Q4000, a riser-based semi-submersible well intervention vessel, commenced operations in 2002 and serves customers in the spot market. In 2010, the Q4000 served as a key emergency response vessel in the Macondo well control and containment efforts. Our Q5000 riser-based semi-submersible well intervention vessel commenced operations in the Gulf of Mexico in 2015 and is under a five-year contract with BP into 2021.
In Brazil, we provide well intervention services to Petróleo Brasileiro S.A. (“Petrobras”) with the Siem Helix 1 and Siem Helix 2 vessels that we charter from Siem Offshore AS (“Siem”). The initial term of the agreements with Petrobras is for four years, with options to extend by agreement of both parties for an additional period of up to four years. The Siem Helix 1 commenced operations for Petrobras in April 2017 and the Siem Helix 2 commenced operations for Petrobras in December 2017. The initial term of the charter agreements with Siem is for seven years with options to extend.
In the North Sea, the Well Enhancer has performed well intervention, abandonment and coil 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.
Robotics
We have been actively engaged in robotics for over three decades. We operate robotics assets designed to complement offshore construction, maintenance and well intervention services, and often integrate these services with chartered vessels. Our robotics business unit primarily operates in the Gulf of Mexico, North Sea, West Africa and Asia Pacific regions. As global marine construction support operates in deeper waters, 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. Our robotics assets currently include 44 ROVs, four trenchers and one ROVDrill. We charter vessels to support deployment of our robotics assets, and engage spot vessels on short-term charter agreements as needed. Vessels currently under long-term charter agreements include the Grand Canyon II and the Grand Canyon III. The Grand Canyon charter terminated in November 2019.
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Over the last decade there has been an increase in offshore activity associated with the growing renewable energy industry. 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 2019, revenues derived from offshore renewables contracts accounted for 36% of our global robotics revenues. We believe that over the long term our robotics business unit is positioned to continue providing services to a range of clients in the renewable energy industry.
Production Facilities
We own 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 own a 20% interest in Independence Hub, which owns the Independence Hub platform. The platform is currently in the process of being decommissioned.
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. In January 2019 we renewed the agreements that provide various operators with access to the HFRS for well control purposes on newly agreed-upon rates and terms. These agreements are through March 31, 2021 and automatically renew on an annual basis absent proper notice of termination.
In January 2019 we acquired from Marathon Oil Corporation (“Marathon Oil”) several wells and related infrastructure 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 the acquired assets, which we can perform as our schedule permits, subject to regulatory timelines. We completed the P&A of two of the Droshky wells during 2019, and we expect limited production associated with the remaining Droshky wells.
GEOGRAPHIC AREAS
We primarily operate in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. 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: 2019 — Petrobras (29%), BP (15%) and Shell (13%); 2018 — Petrobras (28%) and BP (15%); and 2017 — BP (19%), Petrobras (13%) and Talos (10%). We provided services to over 50 customers in 2019.
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COMPETITORS
The oilfield services industry is highly competitive. While price is a factor, the ability to access specialized vessels, attract and retain skilled personnel, and operate safely are also important to competing in the industry. Our principal competitors in the well intervention business include Baker Hughes, Expro Group, Oceaneering International, Inc., TIOS and international drilling contractors. Our principal competitors in the robotics business include C-Innovation, LLC, DeepOcean Group, DOF Subsea Group, Fugro N.V., Oceaneering International, Inc. and ROVOP. Our competitors may have more financial, personnel, technological and other resources available to them.
ENVIRONMENTAL, SOCIAL AND GOVERNANCE
We continue to implement and improve Environmental, Social and Governance (“ESG”) initiatives and disclosures throughout our business. In conjunction with support from management and our Board of Directors (our “Board”), we incorporate ESG initiatives into our core business values and priorities of safety, sustainability and value creation. We emphasize constant improvement by continually striving to improve our safety record, reducing our environmental impact, and increasing transparency. In 2019, we continued to decrease our Total Recordable Incident Rate from prior years, continued to expand our business with renewable energy customers, and published our first Corporate Sustainability Report. A copy of our current Corporate Sustainability Report is available on our website at www.HelixESG.com/about-helix/corporate-sustainability.
TRAINING, SAFETY, HEALTH, ENVIRONMENT AND QUALITY ASSURANCE
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.
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. As a result, we believe that our QHSE programs are among the best in the industry, and we continuously seek to improve our control of QHSE risks and the safe behavior of our employees. We assess risk by using selected risk analysis tools, controlling work through management system procedures, assessing job risk of all routine and non-routine tasks, documenting daily observations, and collecting data, all in an effort to provide a better understanding of our QHSE risks and at-risk behaviors. We schedule hazard hunts on our vessels and regularly audit QHSE management systems, with assigned responsibilities and action due dates.
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 18001.
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 may be producing and which we plan to ultimately decommission. Being an 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”).
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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 flag state and the country where we operate may impose additional requirements. 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
While we provide services globally and generally can be subject to local laws and regulations wherever we operate, 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 all of 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 as required by the Oil Pollution Prevention and Control Regulations 2005. In the North Sea, international regulations govern working hours and the working environment, as well as standards for diving procedures, equipment and diver health. We also note that the U.K.’s exit from 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, and the Ministry of Labor, which regulates a variety of subjects including work-related accident prevention and use of machinery and equipment.
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”).
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Cabotage Rules
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 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 oil and gas 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 operator of wells, we are also required to have a BSEE-approved Oil Spill Response Plan. In April 2016 BSEE issued the final Oil and Gas and Sulfur Operations in the Outer Continental Shelf-Blowout Preventer Systems and Well Control Rule, which updated requirements for equipment and operations for well control activities associated with drilling, completion, workover and decommissioning operations, and provided further guidance for the design and operation of remotely operated tools. In May 2019, BSEE released revised regulations for well control and blowout preventer systems in response to previous Executive and Secretarial Orders that directed BSEE to review regulations that potentially burdened the development or use of domestically produced energy resources. While leaving the majority of the regulations unchanged, certain provisions were revised and others were added, all in an effort to improve operations on the OCS. The final revised regulations address offshore oil and gas drilling, completions, workovers, and decommissioning activities, and to the extent that any changes are applicable to systems that we own or operate, we have incorporated those changes into our operations as appropriate.
Local Content Requirements
Governments in some countries, notably in Brazil and in the West Africa region, have become increasingly active in establishing and enforcing local content requirements with respect to equipment and crews utilized in operations such as ours, along with other aspects of the oil and gas industries in their respective countries.
Other Regulatory Impact
Additional proposals and proceedings before various international, federal and state regulatory agencies and courts could affect the oil and gas industry, including curtailing production and demand for fossil fuels. We cannot predict when or whether any such proposals may become effective.
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. There is currently little uniformity among the regulations issued by the governmental agencies with authority over environmental regulation. 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 that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern or otherwise affect our operations.
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MARPOL
The U.S. is one of approximately 170 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 90
The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on offshore facility owners or operators, and the lessee or permittee of the 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. Beginning in 2010, the IMO designated 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 and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including owners and operators of contaminated sites where the release occurred and those companies that transport, dispose of or arrange for the disposal of, hazardous substances released at the sites.
OCSLA
The Outer Continental Shelf Lands Act, as amended (“OCSLA”), provides the U.S. government with broad authority to impose environmental protection requirements applicable to lessees and permittees operating in the OCS. Specific design and operational standards may apply to OCS vessels, rigs, platforms, vehicles and structures. Violations can result in substantial civil and criminal penalties, as well as potential court injunctions that could curtail operations and cancel leases.
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Current Compliance and Potential Material 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 to ensure that 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, 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 in the future. Liability related to environmental compliance could have a material adverse effect on our financial position, results of operations and cash flows, and could have a significant impact on our financial ability to carry out our operations.
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 lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful claim for which we are not fully insured could have a material adverse effect on our financial position, results of operations and cash flows.
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 (i.e., limited coverage considering the underlying cost).
Our current insurance program is valid until June 30, 2020.
We maintain Hull and Increased Value insurance, which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are $1.0 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 the vessels, and General Liability insurance, which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. 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 $100,000 per occurrence plus a $750,000 annual aggregate deductible. 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 newly-acquired offshore 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 also maintain Operator Extra Expense coverage that provides up to $150 million of coverage per each loss occurrence for a well control issue. Separately, we also maintain $500 million of liability insurance and $150 million of oil pollution insurance. For any given oil spill event we have 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 generally 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.
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We incur workers’ compensation, MEL and other insurance claims in the normal course of business. We analyze each claim for potential exposure and estimate the ultimate liability of each claim. We have not incurred any significant losses as a result of claims denied by our insurance carriers. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. 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.
EMPLOYEES
As of December 31, 2019, we had 1,650 employees. Of our total employees, we had 378 non-U.S. employees covered by collective bargaining agreements or similar arrangements. We consider our overall relationships with our employees to be satisfactory.
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, 2019, previous and subsequent copies of our Quarterly Reports on Form 10-Q and any 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 “Investors” 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. 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 “Investors” 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) and Twitter (@Helix_ESG).
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.
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Dynamic Positioning (DP): Computer directed thruster systems that use satellite-based positioning and other positioning technologies to ensure 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.
Life of field services: Services performed on offshore facilities, trees and pipelines from the beginning to the end of the economic life of an oil field, including installation, inspection, maintenance, repair, well intervention and abandonment.
Plug and abandonment (P&A): P&A operations usually consist of placing several cement plugs in the wellbore to isolate the reservoir and other fluid-bearing formations when a well reaches the end of its lifetime.
Pound per square inch (p.s.i.): A unit of measurement for pressure or stress resulting from a force of one pound-force applied to an area of one square inch.
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.
ROVDrill: A coring system deployed with an ROV system capable of taking cores from the seafloor in water depths up to 10,000 feet. Because the ROV system operates from the seafloor there is no need for surface drilling strings or the larger support spreads required for conventional coring.
Saturation diving: Divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site, 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 to perform specific projects.
Subsea Intervention Lubricator (SIL): A riserless system designed to facilitate access to subsea wells from a monohull vessel to provide safe, efficient and cost effective riserless well intervention and abandonment solutions. A SIL can be utilized for wireline, logging, light perforating, zone isolation, plug setting and removal, and decommissioning, and provides access to the well bore while providing well control safety for activities that do not require a riser conduit.
Trencher or trencher system: A subsea robotics system capable of providing post-lay trenching, inspection and burial and maintenance of submarine cables and flowlines 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/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
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, results of operations and financial position.
Our business is adversely affected by low oil and gas prices, which occur in a cyclical oil and gas industry.
Our services are substantially dependent upon the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital and other expenditures for offshore exploration, development, drilling and production operations. Although our services are used for other operations during the entire life cycle of a well, when industry conditions are unfavorable such as the current environment, oil and gas companies will likely continue to reduce their budgets for expenditures on all types of operations, and will defer certain activities to the extent possible. The levels of both capital and operating expenditures generally 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 available access to global 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 the Middle East and other oil-producing regions;

• | actions taken by the Organization of Petroleum Exporting Countries (“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 external capital for capital projects and production operations;

• | the sale and expiration dates of offshore leases globally;

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

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

• | potential acceleration of the development of alternative fuels;

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

• | weather conditions, natural disasters, and epidemic and pandemic diseases;

• | 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 and could lead to an even greater surplus of available vessels and therefore increasingly downward pressure on the rates we can charge for our services. 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.
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The majority 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 last several years we have entered into longer term contracts, including the five-year contract with BP for work in the Gulf of Mexico, the two four-year contracts with Petrobras for well intervention services offshore Brazil and the seven-year contract for the HP I. As of December 31, 2019, the BP contract, the Petrobras contracts and the contract for the HP I represented approximately 82% 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 shorter term contracts. In addition, the BP contract and the Petrobras contracts expire in 2021 and the contract for the HP I expires in 2023. Our ability to renew or replace these contracts when they expire or obtain new contracts as alternatives, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers. Given the historically cyclical nature of our industry, we may not be able to renew or replace the contracts or we may be required to 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 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 current backlog may not be ultimately realized for various reasons, and our contracts may be terminated early.
As of December 31, 2019, backlog for our services supported by written agreements or contracts totaled $796 million, of which $509 million is expected to be performed in 2020. We may incur capital costs (a substantial portion of which we expect to recover from these contracts), 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.
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 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.
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 Q7000 vessel is a unique, new-build asset that may experience start-up challenges, and although we have worked in West Africa previously, operating in that region presents certain incremental complications; any of these factors could lead to performance concerns. Additionally, the occurrence or threat of an epidemic or pandemic disease could cause 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.
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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, counterparties, insurers and financial institutions generally, could jeopardize the ability of such parties to perform their obligations to us, including obligations to pay amounts owed to us. Although we assess the creditworthiness of our counterparties, a variety of conditions and factors unrelated to those identified above 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. In addition, we may offer favorable payment 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 and 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 ROV support vessels under long-term time charter agreements. We also have entered into long-term charter agreements for the Siem Helix 1 and Siem Helix 2 vessels to perform work under our contracts with Petrobras. 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.
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.
Although we continue to seek to reduce the level of our capital and other expenses and have raised capital by means of several securities offerings, in the event of a more 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 time charter contracts for our vessels and certain other commitments related to ongoing operational activities, could lead to a material adverse effect on our liquidity and financial position.
Asset upgrade, modification, refurbishment, repair, dry dock and construction projects, and customer contractual acceptance of vessels and 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 existing fleet from time to time. We also construct or make capital improvements to other pieces of equipment (such as the 15K IRS and the ROAM that we jointly constructed with OneSubsea). While some of these capital projects are planned, some are unplanned. Additionally, as vessels and equipment 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.
Estimated capital expenditures could materially exceed our planned capital expenditures. Moreover, assets undergoing upgrades, modifications, refurbishment or repair may not earn revenue during the period they are out of service. Any significant period of unplanned maintenance and repairs related to our assets could have a material adverse effect on our financial position, results of operations and cash flows.
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In addition, delays in the delivery of vessels and other operating assets being constructed or undergoing upgrades, modifications, refurbishment, repair, 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 delay damages under applicable late delivery clauses. In the event of termination 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 oilfield services business in which we operate is 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 substantially 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 substantially 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.
Our indebtedness and the terms of our indebtedness could impair our financial condition and our ability to fulfill our debt obligations.
As of December 31, 2019, we had $405.9 million of consolidated indebtedness outstanding. 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 and equipment and the decommissioning of offshore oil and gas properties; and

• | limiting our ability to use proceeds from asset sales for purposes other than debt repayment (except in certain circumstances where proceeds may be reinvested under criteria set forth in our credit agreements).

A prolonged period of weak economic 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.
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Lack of access to the financial markets could negatively impact our ability to operate our business and to execute our strategy.
Access to financing may be limited and uncertain, especially in times of economic weakness. 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 vessels 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 suppliers 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 North Sea business typically declines in the winter, and bad 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 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 some adverse weather conditions. Accordingly, 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 storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail service 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 events, we may experience disruptions in our operations because customers may curtail their offshore activities due to damage to their 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 lawsuits asserting large claims. 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 cannot make assurances 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.
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Our oil and gas operations involve a high degree of operational risk, particularly risk of personal injury, damage, loss of equipment and environmental accidents.
Beginning in January 2019 we own oil and gas properties as part of our strategy to secure utilization for our vessels and other equipment. Engaging in oil and gas production and transportation operations subjects us to certain risks inherent in the 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. 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 flow.
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 these indemnification obligations.
Government regulations may affect our business operations, including making our operations more difficult and/or costly.
Our business is affected by changes in public policy and by federal, state, local and foreign laws and regulations relating to the offshore oil and gas industry. 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”) which (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.
Tax laws are dynamic and subject to change as new laws are passed and new interpretations are issued or applied. In 2017 the U.S. enacted significant tax reform, and certain provisions of the new law may ultimately adversely affect us. Certain members of the EU are undergoing significant changes to their tax systems, which may have an adverse effect on us. In addition, 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 protection we seek to obtain from our customers, 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.
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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 ensure 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 deepwater blowout. It is expected that 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 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.
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.
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;

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• | 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. In addition, laws and policies of the U.S. affecting foreign trade and taxation may adversely affect our international operations.
Our international operations are exposed to currency devaluation and fluctuation risk.
Since 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 are at risk of changes in the exchange rates between the U.S. dollar and such currencies. In some instances, we may receive payments in currencies that are not easily traded and may be illiquid. 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.
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. Many companies, including us, have had employee layoffs as a result of reduced business activities in an industry downturn. Our continued 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 aspects of our business. Similar to other companies, we 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. Although we continue to 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 or detect every type of attempt or attack. In addition, a cyberattack or security breach could go undetected for an extended period of time. A breach or failure of our information technology 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 ROVs, unplanned capital expenditures, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, theft or misappropriation of funds, violation of privacy or other laws, and exposure to litigation. Any such breach could have a material adverse effect on our business, reputation, financial position, results of operations and cash flows.
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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, IRSs, SILs and ROVDrill, 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 proprietary information as appropriate, there can be no assurance that these measures will adequately protect such IP or other technology. Such a failure could result in an interruption in our operations, increased competition, unplanned capital expenditures, and exposure to litigation. Any such failure could have a material adverse effect on our business, competitive position, financial position, results of operations and cash flows.
Certain provisions of our corporate documents and Minnesota law may discourage a third party from making a takeover proposal.
We are authorized to fix, 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 in the event of a “change of control.” Any or all of these provisions or factors may discourage a takeover proposal or tender offer not approved by management and our Board and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less in return for their shares than otherwise might be available in the event of a takeover attempt.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
VESSELS AND OTHER OPERATING ASSETS
Our fleet currently includes six vessels, six IRSs, three SILs, one ROAM, 44 ROVs, four trenchers and one ROVDrill. We also have four vessels under long-term charter. Currently 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 have built-in saturation diving systems.
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Listing of Vessels and Other Assets Related to Operations (1)

| Flag State |  | Placed in Service (2) |  | Length (Feet) |  | DP
Floating Production Unit — |  |  |  |  |  |  |
Helix Producer I (3) | Bahamas |  | 4/2009 |  | 528 |  | DP2
Well Intervention — |  |  |  |  |  |  |
Q4000 (4) | U.S. |  | 4/2002 |  | 312 |  | DP3
Seawell | U.K. |  | 7/2002 |  | 368 |  | DP2
Well Enhancer | U.K. |  | 10/2009 |  | 432 |  | DP2
Q5000 (5) | Bahamas |  | 4/2015 |  | 358 |  | DP3
Siem Helix 1 (6) | Bahamas |  | 6/2016 |  | 521 |  | DP3
Siem Helix 2 (6) | Bahamas |  | 2/2017 |  | 521 |  | DP3
Q7000 | Bahamas |  | 1/2020 |  | 320 |  | DP3
6 IRSs, 3 SILs and 1 ROAM (7) | — |  | Various |  | — |  | —
Robotics — |  |  |  |  |  |  |
44 ROVs, 4 Trenchers and 1 ROVDrill (3), (8) | — |  | Various |  | — |  | —
Grand Canyon II (6) | Norway |  | 4/2015 |  | 419 |  | DP3
Grand Canyon III (6) | Norway |  | 5/2017 |  | 419 |  | DP3

(1) | Under governmental regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety 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) | Serves as security for the Credit Agreement described in Note 8.

(4) | Subject to a vessel mortgage securing our MARAD Debt described in Note 8.

(5) | Serves as security for our Nordea Q5000 Loan described in Note 8.

(6) | Chartered vessel.

(7) | We own a 50% interest in the 15K IRS and the ROAM, both of which we jointly developed with OneSubsea.

(8) | Average age of our fleet of ROVs, trenchers and ROVDrill is approximately 9.9 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. In the normal course of business, we charter other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and additional robotics support vessels.
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.
Item 3. Legal Proceedings
We are, from time to time, party to litigation arising in the normal course of business. We believe that there are currently no legal proceedings the outcome of which would have a material adverse effect on our financial position, results of operations or cash flows.
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Item 4. Mine Safety Disclosures
Not applicable.
Information about our Executive Officers
Our executive officers are as follows:

Name |  | Age |  | Position
Owen Kratz |  | 65 |  | President, Chief Executive Officer and Director
Erik Staffeldt |  | 48 |  | Executive Vice President and Chief Financial Officer
Scott A. Sparks |  | 46 |  | Executive Vice President and Chief Operating Officer
Kenneth E. Neikirk |  | 44 |  | 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 (SUNY).
Erik Staffeldt is Executive Vice President and Chief Financial Officer of Helix. 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 February 2014 until July 2015, Vice President — Finance and Accounting from July 2015 to June 2017, and Senior Vice President and Chief Financial Officer from June 2017 until February 2018. 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. Mr. Staffeldt served in various financial and accounting capacities prior to joining Helix and has over 24 years of experience in the energy industry. Mr. Staffeldt is a graduate of the University of Notre Dame with a BBA in Accounting and an MBA from Loyola University in New Orleans, 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 29 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 19 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. 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.
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PART II
Item 5. Market for the 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 21, 2020, the closing sale price of our common stock on the NYSE was $8.25 per share. As of February 21, 2020, there were 293 registered shareholders and approximately 22,300 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 prohibit 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, 2014 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 (the “Peer Group”) consisting of the following companies: Dril-Quip, Inc., Forum Energy Technologies, Inc., Frank’s International N.V., McDermott International, Inc., Newpark Resources, Inc., Noble Corporation plc, Oceaneering International, Inc., Oil States International, Inc., SEACOR Holdings Inc., Superior Energy Services Inc., TETRA Technologies, Inc., and Valaris plc. 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, 2019 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, 2014 in our common stock at the closing price on that date price and on December 31, 2014 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 — (55.6)%; the Peer Group — (59.7)%; the OSX — (58.9)%; and S&P 500 — 73.9%. These results are not necessarily indicative of future performance.
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Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group

| As of December 31,
| 2014 |  | 2015 |  | 2016 |  | 2017 |  | 2018 |  | 2019
Helix | $ | 100.0 |  |  | $ | 24.2 |  |  | $ | 40.7 |  |  | $ | 34.8 |  |  | $ | 24.9 |  |  | $ | 44.4 |
Peer Group Index | $ | 100.0 |  |  | $ | 71.7 |  |  | $ | 71.0 |  |  | $ | 57.1 |  |  | $ | 36.3 |  |  | $ | 40.3 |
Oil Service Index | $ | 100.0 |  |  | $ | 76.6 |  |  | $ | 91.2 |  |  | $ | 75.5 |  |  | $ | 41.4 |  |  | $ | 41.1 |
S&P 500 | $ | 100.0 |  |  | $ | 101.4 |  |  | $ | 113.5 |  |  | $ | 138.3 |  |  | $ | 132.2 |  |  | $ | 173.9 |

Source: Bloomberg
Issuer Purchases of Equity Securities

Period |  | (a) Total number of shares purchased (1) |  | (b) Average price paid per share |  | (c) Total number of shares purchased as part of publicly announced program |  | (d) Maximum number of shares that may yet be purchased under the program (2) (3)
October 1 to October 31, 2019 |  | — |  |  | $ | — |  |  | — |  |  | 4,751,642 |
November 1 to November 30, 2019 |  | — |  |  | — |  |  | — |  |  | 4,751,642 |
December 1 to December 31, 2019 |  | 36,627 |  |  | 9.13 |  |  | — |  |  | 4,866,645 |
|  | 36,627 |  |  | $ | 9.13 |  |  | — |  |  |

(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 increases the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 11.

(3) | In December 2019, we issued approximately 0.1 million shares of restricted stock to independent members of our Board. In January 2020, we issued approximately 0.4 million shares of restricted stock to our executive officers, select management employees, and certain members of our Board who have elected to take their 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.

Item 6. Selected Financial Data.
The financial data presented below for each of the five years ended December 31, 2019 should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included elsewhere in this Annual Report.
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| Year Ended December 31,
| 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015
| (in thousands, except per share amounts)
Statement of Operations Data: |  |  |  |  |  |  |  |  |
Net revenues | $ | 751,909 |  |  | $ | 739,818 |  |  | $ | 581,383 |  |  | $ | 487,582 |  |  | $ | 695,082 |
Gross profit (loss) (1) | 137,838 |  |  | 121,684 |  |  | 62,166 |  |  | 46,516 |  |  | (233,774 | )
Income (loss) from operations (2) | 67,997 |  |  | 51,543 |  |  | (1,130 | ) |  | (63,235 | ) |  | (307,360 | )
Net income (loss), including noncontrolling interests (3) | 57,697 |  |  | 28,598 |  |  | 30,052 |  |  | (81,445 | ) |  | (376,980 | )
Net income applicable to noncontrolling interests | (222 | ) |  | — |  |  | — |  |  | — |  |  | — |
Net income (loss) applicable to common shareholders | 57,919 |  |  | 28,598 |  |  | 30,052 |  |  | (81,445 | ) |  | (376,980 | )
Adjusted EBITDA (4) | 180,088 |  |  | 161,709 |  |  | 107,216 |  |  | 89,544 |  |  | 172,736 |
Earnings (loss) per share of common stock: |  |  |  |  |  |  |  |  |
Basic | $ | 0.39 |  |  | $ | 0.19 |  |  | $ | 0.20 |  |  | $ | (0.73 | ) |  | $ | (3.58 | )
Diluted | $ | 0.38 |  |  | $ | 0.19 |  |  | $ | 0.20 |  |  | $ | (0.73 | ) |  | $ | (3.58 | )
Weighted average common shares outstanding: |  |  |  |  |  |  |  |  |
Basic | 147,536 |  |  | 146,702 |  |  | 145,295 |  |  | 111,612 |  |  | 105,416 |
Diluted | 149,577 |  |  | 146,830 |  |  | 145,300 |  |  | 111,612 |  |  | 105,416 |

(1) | Amount in 2015 included impairment charges of $205.2 million for the Helix 534, $133.4 million for the HP I and $6.3 million for certain capitalized vessel project costs.

(2) | Amount in 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit. Amount in 2015 included a $16.4 million goodwill impairment charge related to our U.K. well intervention reporting unit.

(3) | Amount in 2017 included a $51.6 million income tax benefit as a result of the U.S. tax law changes enacted in December 2017 (Note 9). Amount in 2015 included losses totaling $124.3 million related to our investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub. Amount in 2015 also included unrealized losses totaling $18.3 million on our foreign currency exchange contracts associated with the Grand Canyon, Grand Canyon II and Grand Canyon III chartered vessels.

(4) | This is a non-GAAP financial measure. See “Non-GAAP Financial Measures” below for an explanation of the definition and use of such measure as well as a reconciliation of these amounts to each year’s respective reported net income or loss.

| December 31,
| 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015
| (in thousands)
Balance Sheet Data: |  |  |  |  |  |  |  |  |
Working capital | $ | 153,508 |  |  | $ | 259,440 |  |  | $ | 186,004 |  |  | $ | 336,387 |  |  | $ | 473,123 |
Total assets | 2,596,731 |  |  | 2,347,730 |  |  | 2,362,837 |  |  | 2,246,941 |  |  | 2,399,959 |
Total debt | 405,853 |  |  | 440,315 |  |  | 495,627 |  |  | 625,967 |  |  | 749,335 |
Total shareholders’ equity | 1,699,591 |  |  | 1,617,779 |  |  | 1,567,393 |  |  | 1,281,814 |  |  | 1,278,963 |

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.
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We measure our operating performance based on EBITDA and free cash flow. 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 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 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. We separately disclose our non-cash asset impairment charges, which, if not material, would be reflected as a component of our depreciation and amortization expense. Because these impairment charges are material for certain period presented, we have reported them as a separate line item. Non-cash goodwill impairment 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 gains and losses on disposition of assets, if any. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments and other than temporary loss on note receivable, 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 reconciliations, we provide amounts as reflected in our accompanying 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,
| 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015
Net income (loss) | $ | 57,697 |  |  | $ | 28,598 |  |  | $ | 30,052 |  |  | $ | (81,445 | ) |  | $ | (376,980 | )
Adjustments: |  |  |  |  |  |  |  |  |
Income tax provision (benefit) | 7,859 |  |  | 2,400 |  |  | (50,424 | ) |  | (12,470 | ) |  | (101,190 | )
Net interest expense | 8,333 |  |  | 13,751 |  |  | 18,778 |  |  | 31,239 |  |  | 26,914 |
Loss on extinguishment of long-term debt | 18 |  |  | 1,183 |  |  | 397 |  |  | 3,540 |  |  | — |
Other (income) expense, net (1) | (1,165 | ) |  | 6,324 |  |  | 1,434 |  |  | (3,510 | ) |  | 24,310 |
Depreciation and amortization | 112,720 |  |  | 110,522 |  |  | 108,745 |  |  | 114,187 |  |  | 120,401 |
Asset impairments (2) | — |  |  | — |  |  | — |  |  | — |  |  | 345,010 |
Goodwill impairments (3) | — |  |  | — |  |  | — |  |  | 45,107 |  |  | 16,399 |
Gain (loss) on equity investments (4) | (1,613 | ) |  | 3,430 |  |  | 1,800 |  |  | 1,674 |  |  | 122,765 |
EBITDA | 183,849 |  |  | 166,208 |  |  | 110,782 |  |  | 98,322 |  |  | 177,629 |
Adjustments: |  |  |  |  |  |  |  |  |
(Gain) loss on disposition of assets, net | — |  |  | (146 | ) |  | 39 |  |  | (1,290 | ) |  | (92 | )
Realized losses from foreign exchange contracts not designated as hedging instruments | (3,761 | ) |  | (3,224 | ) |  | (3,605 | ) |  | (7,488 | ) |  | (4,801 | )
Other than temporary loss on note receivable | — |  |  | (1,129 | ) |  | — |  |  | — |  |  | — |
Adjusted EBITDA | $ | 180,088 |  |  | $ | 161,709 |  |  | $ | 107,216 |  |  | $ | 89,544 |  |  | $ | 172,736 |

(1) | Amount in 2015 includes unrealized losses totaling $18.3 million on our foreign currency exchange contracts associated with the Grand Canyon, Grand Canyon II and Grand Canyon III chartered vessels.

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(2) | Amount in 2015 reflects asset impairment charges for the Helix 534, the HP I and certain capitalized vessel project costs.

(3) | Amount in 2016 reflects a goodwill impairment charge related to our robotics reporting unit. Amount in 2015 reflects a goodwill impairment charge related to our U.K. well intervention reporting unit.

(4) | Amount in 2015 primarily reflects losses from our share of impairment charges that Deepwater Gateway and Independence Hub recorded in December 2015 and the write-offs of the remaining capitalized interest related to these equity investments.

The reconciliation of our cash flows from operating activities to free cash flow is as follows (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017 |  | 2016 |  | 2015
Cash flows from operating activities | $ | 169,669 |  |  | $ | 196,744 |  |  | $ | 51,638 |  |  | $ | 38,714 |  |  | $ | 110,805 |
Less: Capital expenditures, net of proceeds from sale of assets | (138,304 | ) |  | (137,058 | ) |  | (221,127 | ) |  | (173,310 | ) |  | (302,719 | )
Free cash flow | $ | 31,365 |  |  | $ | 59,686 |  |  | $ | (169,489 | ) |  | $ | (134,596 | ) |  | $ | (191,914 | )

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. With the delivery in November 2019 and the commencement of operations in January 2020 of the Q7000, our well intervention fleet currently includes seven purpose-built well intervention vessels, six IRSs, three SILs and one ROAM. Our robotics equipment currently includes 44 work-class ROVs, four trenchers and one ROVDrill. We also charter ROV support vessels on both long-term and spot bases to facilitate our ROV and trenching operations. Our intervention and robotic operations are geographically dispersed throughout the world. We believe that focusing on these services should deliver favorable long-term financial returns. Our Production Facilities segment includes the HP I, the HFRS and several wells and related infrastructure associated with the Droshky Prospect.
Our alliance with OneSubsea leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. We and OneSubsea jointly developed a 15K IRS, which was completed and placed into service in January 2018, and our first ROAM, which is currently available to customers.
Economic Outlook and Industry Influences
Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities and capital projects. The performance of our business is also largely dependent on 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, and several other factors, including:
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• | worldwide economic activity and general economic and business conditions, including available access to global 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 the Middle East and other oil-producing regions;

• | actions taken by 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 external capital for capital projects and production operations;

• | the sale and expiration dates of offshore leases globally;

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

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

• | potential acceleration of the development of alternative fuels;

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

• | weather conditions, natural disasters, and epidemic and pandemic diseases;

• | environmental and other governmental regulations; and

• | domestic and international tax laws, regulations and policies.

Crude oil prices declined significantly in 2014 and have been volatile since then. Brent crude oil prices fluctuated between $53 and $75 per barrel during 2019. The volatility and uncertainty in future prices have discouraged oil and gas companies from making longer-term investments in offshore exploration and production as well as other offshore operational activities, which has decreased the demand and rates for services provided by drilling rig contractors. The decrease in rates for drilling rig contractors affects us as drilling rigs historically have been the asset class used for offshore well intervention work. Furthermore, the uncertainty and volatility in oil prices have caused our customers to use drilling rigs on existing long-term contracts to perform well intervention work instead of new drilling activities. This rig overhang, combined with lower volumes of work for drilling rig contractors, continues to affect the utilization and/or rates we can achieve for our assets. Furthermore, volatile and uncertain macroeconomic conditions in some regions and countries around the world, such as West Africa, Brazil, China and the U.K. following Brexit, may have a direct and/or indirect impact on our existing contracts and contracting opportunities and may introduce further currency volatility into our operations and/or financial results.
Many oil and gas companies are increasingly focusing on optimizing production of their existing subsea wells. As oil and gas companies begin to increase overall spending levels, we expect that it will likely be weighted towards production enhancement activities rather than exploration projects. Moreover, as the subsea tree base expands and ages, the demand for P&A services should persist. We believe that we have a competitive advantage in performing well intervention services efficiently. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide P&A services at the end of the life of a field as required by governmental regulations. Thus, we believe that fundamentals for our business 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.
We continue to position ourselves for future market recovery while managing through this sustained period of market weakness. Our position is based on multiple factors, including: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as P&A costs are considered; (2) our services offer commercially viable alternatives for reducing the finding and development costs of reserves as compared to new drilling as well as extending and enhancing the commercial life of subsea wells; and (3) in past cycles, well intervention and workover have been some of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.
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Despite being in an ongoing weak market, we did see improvements in 2019 compared to 2018. In the Gulf of Mexico, offshore activity increased with higher utilization and an increase in rig count during the year. Measured signs of improvements also began to show in rates, which typically lag those in utilization. We are seeing positive developments that drive demand for our business, including (1) the decrease in rig overhang as long-term rig contracts expire, which contracts were viewed by our customers as a sunk cost and (2) the decrease in the attractiveness of unconventional onshore oil and gas opportunities, which may diverge investments offshore. We expect to see a continued recovery, albeit a slow recovery, in offshore oil and gas activities in the Gulf of Mexico in 2020.
Business Activity Summary
We have been focused on enhancing our financial position and strengthening our balance sheet through various means including securities offerings (the last of which occurred in March 2018), which has allowed us to strategically focus on our core well intervention and robotics businesses.
In January 2019, we renewed the agreements that provide various operators with access to the HFRS for well control purposes through March 31, 2020 on newly agreed-upon rates and terms. These agreements automatically renew on an annual basis absent proper notice of termination.
Also in January 2019, we acquired from Marathon Oil several wells and related infrastructure 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 the acquired assets, which we can perform as our schedule permits, subject to regulatory timelines. We completed the P&A of two of the Droshky wells during 2019, and we expect limited production associated with the remaining Droshky wells.
In May 2019, we acquired a 70% controlling interest in Subsea Technologies Group Limited (“STL”), an Aberdeen-based subsea engineering company that specializes in the design and manufacture of subsea pressure control equipment, including well intervention, well control and subsea control systems.
In November 2019, we took delivery of the Q7000, a newbuild semi-submersible well intervention vessel built to U.K. North Sea standards. The vessel then transited from the shipyard in Singapore to Nigeria where it commenced operations in January 2020.
In November 2019, we returned the Grand Canyon to its owner upon expiration of the long-term charter agreement. The vessel continues to serve as a spot vessel on a short-term basis.
Backlog
We provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. We provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. In addition to serving the oil and gas market, our Robotics assets are contracted for the development of renewable energy projects (wind farms). As of December 31, 2019, our consolidated backlog that is supported by written agreements or contracts totaled $796 million, of which $509 million is expected to be performed in 2020. The substantial majority of our backlog is associated with our Well Intervention business segment. As of December 31, 2019, our well intervention backlog was $568 million, including $402 million expected to be performed in 2020. Our contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our agreements with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 1 and Siem Helix 2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 82% of our total backlog. As of December 31, 2018, the total backlog associated with our operations was $1.1 billion. Backlog is not necessarily a reliable indicator of revenues derived from these contracts as services may be added or 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 the rates we would have generated had we performed the contract.
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RESULTS OF OPERATIONS
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. All material intercompany transactions between the segments have been eliminated in our consolidated financial statements, including our consolidated results of operations.
Comparison of Years Ended December 31, 2019 and 2018
The following table details various financial and operational highlights for the periods presented (dollars in thousands):

| Year Ended December 31, |  | Increase/(Decrease)
| 2019 |  | 2018 |  | Amount |  | Percent
Net revenues — |  |  |  |  |  |  |
Well Intervention | $ | 593,300 |  |  | $ | 560,568 |  |  | $ | 32,732 |  |  | 6 | %
Robotics | 171,672 |  |  | 158,989 |  |  | 12,683 |  |  | 8 | %
Production Facilities | 61,210 |  |  | 64,400 |  |  | (3,190 | ) |  | (5 | )%
Intercompany eliminations | (74,273 | ) |  | (44,139 | ) |  | (30,134 | ) |  |
| $ | 751,909 |  |  | $ | 739,818 |  |  | $ | 12,091 |  |  | 2 | %
Gross profit (loss) — |  |  |  |  |  |  |
Well Intervention | $ | 104,376 |  |  | $ | 101,129 |  |  | $ | 3,247 |  |  | 3 | %
Robotics | 15,809 |  |  | (4,978 | ) |  | 20,787 |  |  | (4) |
Production Facilities | 19,222 |  |  | 27,626 |  |  | (8,404 | ) |  | (30 | )%
Corporate, eliminations and other | (1,569 | ) |  | (2,093 | ) |  | 524 |  |  |
| $ | 137,838 |  |  | $ | 121,684 |  |  | $ | 16,154 |  |  | 13 | %
Gross margin — |  |  |  |  |  |  |
Well Intervention | 18 | % |  | 18 | % |  |  |  |
Robotics | 9 | % |  | (3 | )% |  |  |  |
Production Facilities | 31 | % |  | 43 | % |  |  |  |
Total company | 18 | % |  | 16 | % |  |  |  |
Number of vessels or robotics assets (1) / Utilization (2) |  |  |  |  |  |  |
Well Intervention vessels | 6/89% |  |  | 6/83% |  |  |  |  |
Robotics assets (3) | 50/41% |  |  | 52/37% |  |  |  |  |
Chartered robotics vessels | 3/87% |  |  | 3/76% |  |  |  |  |

(1) | Represents the number of vessels or robotics assets as of the end of the period, including vessels under both short-term and long-term charters, 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 available calendar days in the applicable period. The average utilization rates of chartered robotics vessels in 2019 and 2018 included 191 and 245 spot vessel days, respectively, at near full utilization.

(3) | Consists of ROVs, trenchers and ROVDrill.

(4) | Percent calculation not meaningful.

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

| Year Ended December 31, |  | Increase/
| 2019 |  | 2018 |  | (Decrease)
Well Intervention | $ | 43,484 |  |  | $ | 14,218 |  |  | $ | 29,266 |
Robotics | 30,789 |  |  | 29,921 |  |  | 868 |
| $ | 74,273 |  |  | $ | 44,139 |  |  | $ | 30,134 |

Net Revenues. Our total net revenues increased by 2% in 2019 as compared to 2018 reflecting a mix of higher revenues from our Well Intervention and Robotics business segments, lower revenues from our Production Facilities business segment, and higher intercompany eliminations.
Our Well Intervention revenues increased by 6% in 2019 as compared to 2018, primarily reflecting higher revenues in the Gulf of Mexico and Brazil, partially offset by lower revenues in the North Sea. The increase in revenues in the Gulf of Mexico was primarily attributable to higher utilization of the Q4000 during 2019 as compared to 2018. This revenue increase was offset by a reduction in IRS rental revenues during the comparative year-over-year periods. Our Well Intervention revenues in the Gulf of Mexico during 2019 also included $27.5 million associated with intercompany P&A work on two of the Droshky wells for our Production Facilities segment, for which we received payments from Marathon Oil in 2019. The increase in revenues in Brazil was primarily a result of higher utilization of both the Siem Helix 1 and the Siem Helix 2 during 2019. Our Well Intervention revenues in Brazil during 2019 also included approximately $3.9 million of contractual adjustments related to withholding taxes in Brazil, of which $2.1 million related to previous years (Note 12). The decrease in revenues in the North Sea primarily reflected a weaker British pound and lower rates as compared to 2018.
Our Robotics revenues increased by 8% in 2019 as compared to 2018. The increase primarily reflected increased utilization of our chartered vessels (from 76% in 2018 to 87% in 2019) and our robotics assets also achieved higher utilization in 2019 as compared to 2018.
Our Production Facilities revenues decreased by 5% in 2019 as compared to 2018 primarily reflecting lower revenues from the HFRS during 2019, offset in part by production revenues from the oil and gas properties that we acquired from Marathon Oil in January 2019 (Note 1).
The increase in intercompany eliminations was primarily the result of $27.5 million in revenue that our Well Intervention business segment recognized with its completion of P&A work on behalf of our Production Facilities segment.
Gross Profit (Loss). Our 2019 gross profit increased by $16.2 million, or 13%, as compared to 2018 reflecting improvements in our Well Intervention and Robotics business segments, offset in part by lower gross profit in our Production Facilities business segment.
The gross profit related to our Well Intervention segment increased by $3.2 million, or 3%, in 2019 as compared to 2018, primarily reflecting improved operating results in Brazil and the Gulf of Mexico, offset in part by reduced operating results in the North Sea and lower IRS rental unit utilization.
Our Robotics segment achieved a gross profit of $15.8 million in 2019 as compared to a gross loss of $5.0 million in 2018 primarily reflecting increased utilization for our chartered vessels and our robotics assets as well as a reduction in vessel costs due to the termination of the Grand Canyon charter in November 2019 (Notes 1 and 17) and the expiration of the hedge of the Grand Canyon II charter payments in July 2019 (Note 21).
The gross profit related to our Production Facilities segment decreased by 30% in 2019 as compared to 2018 primarily reflecting revenue decreases for the HFRS.
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Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by $0.4 million in 2019 as compared to 2018. The decrease was primarily attributable to a net reduction in employee compensation costs in 2019 as compared to 2018 (Note 14).
Equity in Earnings (Losses) of Investment. Equity in earnings (losses) of investment was $1.4 million in 2019 as compared to $(3.9) million in 2018 primarily reflecting a reduction in our share of estimated obligations to decommission the Independence Hub platform (Note 5).
Net Interest Expense. Our net interest expense totaled $8.3 million in 2019 as compared to $13.8 million in 2018 primarily reflecting higher capitalized interest and a reduction in our overall debt levels from $479.2 million in 2018 to $436.1 million in 2019. Capitalized interest totaled $20.2 million for 2019 as compared to $15.6 million for 2018 as a result of the construction and completion of the Q7000.
Loss on Extinguishment of Long-term Debt. The $1.2 million loss in 2018 was attributable to the write-off of the unamortized debt issuance costs related to the prepayment of $61 million of the then-existing term loan in March 2018 and costs associated with the redemption of the 2032 Notes (Note 8).
Other Income (Expense), Net. Net other income was $1.2 million for 2019 as compared to net other expense of $6.3 million for 2018. Net other income (expense) in 2019 and 2018 included foreign currency transaction gains (losses) of $1.5 million and $(4.3) million, respectively. These amounts primarily reflect foreign exchange fluctuations in our non-U.S. dollar currencies. Also included in the comparable year over year periods were net losses of $0.4 million in 2019 and $0.9 million in 2018 associated with our foreign currency exchange contracts that were not designated as cash flow hedges (Note 21). In addition, net other expense for 2018 included a $1.1 million other than temporary loss on a note receivable.
Royalty Income and Other. Royalty income and other decreased by $1.3 million in 2019 as compared to 2018. The decrease was primarily attributable to the reduction in our overriding royalty income, which was affected by lower average oil prices and lower production volumes in 2019 as compared to 2018.
Income Tax Provision (Benefit). Income tax provision was $7.9 million for 2019 as compared to $2.4 million for 2018. The effective tax rate was 12.0% for 2019 as compared to 7.7% for 2018. The increase was primarily attributable to improvements in profitability in the U.S. year over year (Note 9).
Comparison of Years Ended December 31, 2018 and 2017
Various financial and operational highlights for the years ended December 31, 2018 and 2017 were previously presented in our 2018 Annual Report on Form 10-K.
LIQUIDITY AND CAPITAL RESOURCES
Overview
The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):

| December 31,
| 2019 |  | 2018
Working capital (1) | $ | 153,508 |  |  | $ | 259,440 |
Long-term debt (2) | 306,122 |  |  | 393,063 |
Liquidity (3) | 379,533 |  |  | 426,813 |

(1) | Working capital as of December 31, 2019 included the recognition of $53.8 million of current operating lease liabilities as a result of the adoption of Accounting Standards Update No. 2016-02, “Leases (Topic 842)” in 2019 (Notes 2 and 6) and the classification of the Nordea Q5000 Loan of $89.0 million in current maturities of long-term debt (Note 8).

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(2) | Long-term debt does not include the current maturities portion of our long-term debt as that amount is included in net working capital. Long-term debt is also net of unamortized debt discounts and debt issuance costs. See Note 8 for information relating to our long-term debt.

(3) | Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under the Revolving Credit Facility, which capacity is reduced by letters of credit drawn against that facility. Our liquidity at December 31, 2019 included cash and cash equivalents of $208.4 million and $171.1 million of available borrowing capacity under the Revolving Credit Facility (Note 8). Our liquidity at December 31, 2019 did not include $54.1 million of restricted cash (short-term). Our liquidity at December 31, 2018 included cash and cash equivalents of $279.5 million and $147.4 million of available borrowing capacity under our then-existing revolving credit facility.

The carrying amount of our long-term debt, including current maturities, net of unamortized debt discounts and debt issuance costs, is as follows (in thousands):

| December 31,
| 2019 |  | 2018
Term Loan (matures June 2020) | $ | 32,869 |  |  | $ | 33,321 |
Nordea Q5000 Loan (matures April 2020) | 89,031 |  |  | 123,980 |
MARAD Debt (matures February 2027) | 60,073 |  |  | 66,443 |
Convertible Senior Notes Due 2022 (mature May 2022) (1) | 115,765 |  |  | 112,192 |
Convertible Senior Notes Due 2023 (mature September 2023) (1) | 108,115 |  |  | 104,379 |
Total debt | $ | 405,853 |  |  | $ | 440,315 |

(1) | Convertible Senior Notes Due 2022 (the “2022 Notes”) and Convertible Senior Notes Due 2023 (the “2023 Notes”) will increase to their face amounts through accretion of the debt discounts through May 1, 2022 and September 15, 2023, respectively.

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

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Cash provided by (used in): |  |  |  |  |
Operating activities | $ | 169,669 |  |  | $ | 196,744 |  |  | $ | 51,638 |
Investing activities | (142,385 | ) |  | (136,014 | ) |  | (221,127 | )
Financing activities | (45,818 | ) |  | (46,186 | ) |  | 77,482 |

Our current requirements for cash primarily reflect the need to fund our operations and capital spending for our current lines of business and to service our debt. As of December 31, 2019, the remaining principal balance of the Nordea Q5000 Loan was classified to current as its maturity date is April 30, 2020. Although we currently have no plans to do so, we have the ability to fund the repayment of the Nordea Q5000 Loan when due with available borrowing capacity under the Revolving Credit Facility.
Given the ongoing industry-wide spending reductions, we continue to remain focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, defer or cancel certain planned capital expenditures. We believe that our cash on hand, internally generated cash flows and availability under the Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.
In accordance with the Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio and various leverage ratios, as well as the maintenance of a minimum cash balance, net worth, working capital and debt-to-equity requirements. The Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring additional secured indebtedness or indebtedness guaranteed by us. The Credit Agreement does permit us to incur certain unsecured indebtedness and also provides for our
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subsidiaries to incur project financing indebtedness (such as the MARAD Debt and the Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. The Credit Agreement also permits Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as defined in the Credit Agreement). As of December 31, 2019 and 2018, we were in compliance with all of the covenants in our long-term debt agreements.
A prolonged period of weak industry activity may make it difficult to comply with our covenants and the other restrictions in the agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to fully access the Revolving Credit Facility may be impacted. At December 31, 2019, our available borrowing capacity under the Revolving Credit Facility, based on the applicable leverage ratio covenant, was $171.1 million, net of $3.9 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrow under the Revolving Credit Facility other than for the issuance of letters of credit. Our ability to comply with loan agreement covenants and other restrictions is affected by economic conditions and other events beyond our control. Our failure to comply with these covenants and other restrictions could lead to an event of default, the possible acceleration of our outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral.
Subject to the terms of the Credit Agreement, we may borrow and/or obtain letters of credit of up to $25 million under the Revolving Credit Facility. See Note 8 for additional information relating to our long-term debt, including more information regarding the Credit Agreement and related covenants and collateral.
The 2022 Notes and the 2023 Notes can be converted into our common stock by the holders or redeemed by us prior to their stated maturity under certain circumstances specified in the applicable indenture governing the notes. We can settle any conversion in cash, shares of our common stock or a combination thereof.
Operating Cash Flows
Total cash flows from operating activities decreased by $27.1 million in 2019 as compared to 2018 primarily reflecting changes in our working capital during 2019 as well as higher regulatory certification costs for our vessels and systems, which included costs related to planned dry docks for three of our vessels.
Total cash flows from operating activities increased by $145.1 million in 2018 as compared to 2017 primarily reflecting improvements in our operations, collection of accounts receivable and reductions in interest payments.
Investing Activities
Capital expenditures represent cash paid principally for the acquisition, construction, completion, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Capital expenditures also include interest on property and equipment under development. Significant (uses) sources of cash associated with investing activities are as follows (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Capital expenditures: |  |  |  |  |
Well Intervention | $ | (139,212 | ) |  | $ | (136,164 | ) |  | $ | (230,354 | )
Robotics | (417 | ) |  | (151 | ) |  | (648 | )
Production Facilities | (123 | ) |  | (325 | ) |  | — |
Other | (1,102 | ) |  | (443 | ) |  | (125 | )
STL acquisition, net | (4,081 | ) |  | — |  |  | — |
Proceeds from sale of assets (1) | 2,550 |  |  | 25 |  |  | 10,000 |
Other | — |  |  | 1,044 |  |  | — |
Net cash used in investing activities | $ | (142,385 | ) |  | $ | (136,014 | ) |  | $ | (221,127 | )

(1) | Amount in 2019 primarily reflects cash received from the sale of certain property acquired from Marathon Oil (Note 16). Amount in 2017 reflects cash received from the sale of our former spoolbase facility located in Ingleside, Texas.

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Our capital expenditures above primarily included payments associated with the construction and completion of the Q7000 (see below), the investment in the topside well intervention equipment for the Siem Helix 1 and Siem Helix 2 vessels that we charter to perform our agreements with Petrobras (see below), and the investment in the 15K IRS and the ROAM.
In September 2013, we entered into a contract for the construction of the Q7000, a newbuild semi-submersible well intervention vessel built to U.K. North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% was paid upon the delivery of the vessel in November 2019. At December 31, 2019, our total investment in the Q7000 was $536.4 million, including $346.0 million of installment payments to the shipyard. The vessel commenced operations in Nigeria in January 2020.
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years, with options to extend by agreement of both parties for an additional period of up to four years. In connection with the Petrobras agreements, we entered into charter agreements with Siem for two monohull vessels, the Siem Helix 1, which commenced operations for Petrobras in April 2017, and the Siem Helix 2, which commenced operations for Petrobras in December 2017.
Financing Activities
Cash flows from financing activities consist primarily of proceeds from debt and equity transactions and repayments of our long-term debt. Net cash outflows from financing activities of $45.8 million in 2019 primarily reflected the repayment of $42.6 million of our indebtedness and $2.0 million in net cash outflows related to repayments and net refinancing, including fees, of the Term Loan (Note 8). Net cash outflows from financing activities of $46.2 million in 2018 primarily reflected the repayment of $166.4 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of $125 million of the 2023 Notes (Note 8).
Net cash outflows from financing activities were $46.2 million in 2018 as compared to net cash inflows of $77.5 million in 2017. In 2018, we repaid approximately $166 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of $125 million of our 2023 Notes. Cash inflows from financing activities in 2017 included the net proceeds of approximately $220 million we received from our underwritten public equity offering in January 2017, offset in part by debt repayments in 2017.
Free Cash Flow
Free cash flow decreased by $28.3 million in 2019 as compared to 2018 attributable to the decrease in operating cash flows and higher capital expenditures in 2019.
Free cash flow increased by $229.2 million in 2018 as compared to 2017 primarily attributable to higher operating cash flows and reduced capital expenditures in 2018 as a result of the completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.
Free cash flow is a non-GAAP financial measure. See Item 6 for the definition and calculation of free cash flow.
Outlook
We anticipate that our capital expenditures, including capitalized interest and regulatory certification costs for our vessels and systems, will approximate $50 million for 2020. We believe that cash on hand, internally generated cash flows and availability under the Revolving Credit Facility will provide the capital necessary to continue funding our 2020 operating needs and to meet our debt obligations due in 2020.
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Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 2019 and the scheduled years in which the obligations are contractually due (in thousands):

| Total (1) |  | Less Than 1 Year |  | 1-3 Years |  | 3-5 Years |  | More Than 5 Years
Term Loan | $ | 33,250 |  |  | $ | 3,500 |  |  | $ | 29,750 |  |  | $ | — |  |  | $ | — |
Nordea Q5000 Loan | 89,286 |  |  | 89,286 |  |  | — |  |  | — |  |  | — |
MARAD debt | 63,610 |  |  | 7,200 |  |  | 15,497 |  |  | 17,082 |  |  | 23,831 |
2022 Notes (2) | 125,000 |  |  | — |  |  | 125,000 |  |  | — |  |  | — |
2023 Notes (3) | 125,000 |  |  | — |  |  | — |  |  | 125,000 |  |  | — |
Interest related to debt (4) | 51,401 |  |  | 17,457 |  |  | 24,759 |  |  | 6,706 |  |  | 2,479 |
Property and equipment (5) | 7,978 |  |  | 7,978 |  |  | — |  |  | — |  |  | — |
Operating leases (6) | 378,642 |  |  | 107,565 |  |  | 192,501 |  |  | 72,325 |  |  | 6,251 |
Total cash obligations | $ | 874,167 |  |  | $ | 232,986 |  |  | $ | 387,507 |  |  | $ | 221,113 |  |  | $ | 32,561 |

(1) | Excludes unsecured letters of credit outstanding at December 31, 2019 totaling $3.9 million. These letters of credit may be issued to support various obligations, such as contractual obligations, contract bidding and insurance activities.

(2) | Notes mature in May 2022. The 2022 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $18.06 per share, which is 130% of the conversion price. At December 31, 2019, the conversion trigger was not met. See Note 8 for additional information.

(3) | Notes mature in September 2023. The 2023 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20 days in the period of 30 consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $12.31 per share, which is 130% of the conversion price. At December 31, 2019, the conversion trigger was not met. See Note 8 for additional information.

(4) | Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at December 31, 2019 for variable rate debt.

(5) | Primarily reflects costs associated with the Q7000 prior to the commencement of its operations in January 2020 (Note 17).

(6) | Operating leases include vessel charters and facility and equipment leases. At December 31, 2019, our commitment related to long-term vessel charters totaled approximately $340.9 million, of which $137.0 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, 2019.

Contingencies
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.
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our discussion and analysis of our financial condition and results of operations, as reflected in the accompanying consolidated financial statements and related footnotes, are prepared in conformity with GAAP. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change 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 policies in this regard are those described below. While these issues require us to make judgments that are somewhat subjective, they are generally based on a significant amount of historical data and current market data. See Note 2 for a detailed discussion on the application of our accounting policies.
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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 base our evaluation on impairment indicators such as 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 of 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 to the asset’s carrying value. Impairment 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 decisions, 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 fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.
The review of property and equipment for impairment indicators, the determination of the appropriate asset groups at which to evaluate impairment, 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.
Income Taxes
We conduct business in numerous countries and earn income in various jurisdictions. Income taxes have been provided based upon the tax laws and rates in those jurisdictions. The provision of our income taxes involves the interpretation of various laws and regulations, and changes in those laws, our operations and/or legal structure could impact our income tax liabilities. Furthermore, our tax filings are subject to regular audits and examination by local taxing authorities. We provide for uncertain tax positions and related interest and penalties based upon management’s assessment of whether a tax benefit is more likely than not to be sustained upon examination by tax authorities. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.
We record deferred taxes based on the differences between financial reporting and the tax basis of assets and liabilities. The carrying value of deferred tax assets are based on our estimates, judgments and assumptions regarding future operating results and taxable income. Loss carryforwards and tax credits are assessed for realization, and 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 assets will not be realized. If we subsequently determine that we will be able to realize deferred tax assets in the future in excess of our net recorded amount, the resulting adjustment would increase earnings for the period in which such determination was made. We will continue to assess the adequacy of a valuation allowance on a quarterly basis. Any changes to our estimated valuation allowance could be material to our consolidated financial position and results of operations.
The 2017 Tax Act requires the taxable repatriation of foreign earnings that had been reinvested in previous years. Subsequently, repatriation of foreign earnings will generally be free of U.S. federal tax with the possible exception of withholding taxes and state taxes. As of December 31, 2019, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $129.2 million. We intend to indefinitely reinvest these earnings, as well as future earnings from our non-U.S. subsidiaries without operations in the U.S., to fund our international operations. We have not accrued for the possibility of withholding taxes. The computation of the potential deferred tax liability associated with the amount of reinvested earnings and other basis difference is not practicable.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2019, we were exposed to market risks associated with interest rates and foreign currency exchange rates.
Interest Rate Risk. As of December 31, 2019, $122.5 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may continue to rise, thereby increasing our interest expense and related cash outlay. In June 2015, we entered into various interest rate swap contracts to fix the interest rate on a portion of the Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. As of December 31, 2019, the interest rate on $67.0 million of the Nordea Q5000 Loan was hedged. Debt subject to variable rates after considering hedging activities was $55.5 million. The impact of interest rate risk is estimated using a hypothetical increase in interest rates by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional $0.6 million in interest expense for the year ended December 31, 2019.
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 provide for collections from 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, 2019, approximately 15% of our assets were impacted by changes in foreign currencies in relation to the U.S. dollar. For the years ended December 31, 2019, 2018 and 2017, we recorded foreign currency translation gains (losses) of $5.4 million, $(7.2) million and $16.3 million, respectively, to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments since we consider our undistributed earnings (when applicable) of our non-U.S. subsidiaries without operations in the U.S. to be permanently reinvested.
When currencies other than the functional currency are to be paid or received, the resulting transaction gain or loss is recognized in the consolidated statements of operations as a component of “Other income (expense), net.” For the years ended December 31, 2019, 2018 and 2017, we recorded foreign currency transaction gains (losses) of $1.5 million, $(4.3) million and $(2.2) million, respectively, primarily related to our subsidiaries in the U.K.
In February 2013, we entered into various foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and Grand Canyon III charter payments denominated in the Norwegian kroner. The contracts related to the Grand Canyon II charter payments were fully settled through July 2019 and the contracts related to the Grand Canyon III charter payments were fully settled through February 2020. A portion of these foreign currency exchange contracts qualified for cash flow hedge accounting treatment.
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Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
Helix Energy Solutions Group, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group, Inc. and subsidiaries (the Company) as of December 31, 2019 and 2018, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2019, 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, 2019, 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 27, 2020 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Change in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for leases as of January 1, 2019 due to the adoption of FASB ASU 2016-02, Leases.
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 judgment. 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.
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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 assets (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, 2019 was $1,872,637 thousand.
We identified the evaluation of property and equipment impairment triggering events as a critical audit matter. The evaluation of a triggering event for those assets not under a long-term contract required significant judgment, as expected spending trends by customers in the industry may lead to periods of low utilization and low day rates, and could result in the recognition of impairment charges for assets or asset groups.
The primary procedures we performed to address this critical audit matter included the following. We tested certain internal controls over the Company’s processes to identify and assess triggering events that indicate that the carrying value of an asset or asset group may not be recoverable, including controls related to the consideration of forecasted to actual results and market conditions in determination of a triggering event. We evaluated the Company’s identification of potential triggering events, including future expected revenues from executed contracts. We compared data used by the Company against analyst and industry reports. We evaluated the Company’s data and assumptions when we identified information that was contrary to that used by the Company. 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 27, 2020
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders
Helix Energy Solutions Group, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Helix Energy Solutions Group, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2019, 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, 2019, 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, 2019 and 2018, the related consolidated statements of operations, comprehensive income, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2019, and the related notes (collectively, the consolidated financial statements), and our report dated February 27, 2020 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 27, 2020
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)

| December 31,
| 2019 |  | 2018
ASSETS
Current assets: |  |  |
Cash and cash equivalents | $ | 208,431 |  |  | $ | 279,459 |
Restricted cash | 54,130 |  |  | — |
Accounts receivable: |  |  |
Trade, net of allowance for uncollectible accounts of $0 | 75,646 |  |  | 67,932 |
Unbilled and other | 49,811 |  |  | 51,943 |
Other current assets | 50,450 |  |  | 51,594 |
Total current assets | 438,468 |  |  | 450,928 |
Property and equipment | 2,922,274 |  |  | 2,785,778 |
Less accumulated depreciation | (1,049,637 | ) |  | (959,033 | )
Property and equipment, net | 1,872,637 |  |  | 1,826,745 |
Operating lease right-of-use assets | 201,118 |  |  | — |
Other assets, net | 84,508 |  |  | 70,057 |
Total assets | $ | 2,596,731 |  |  | $ | 2,347,730 |
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities: |  |  |
Accounts payable | $ | 69,055 |  |  | $ | 54,813 |
Accrued liabilities | 62,389 |  |  | 85,594 |
Income tax payable | — |  |  | 3,829 |
Current maturities of long-term debt | 99,731 |  |  | 47,252 |
Current operating lease liabilities | 53,785 |  |  | — |
Total current liabilities | 284,960 |  |  | 191,488 |
Long-term debt | 306,122 |  |  | 393,063 |
Operating lease liabilities | 151,827 |  |  | — |
Deferred tax liabilities | 112,132 |  |  | 105,862 |
Other non-current liabilities | 38,644 |  |  | 39,538 |
Total liabilities | 893,685 |  |  | 729,951 |
Redeemable noncontrolling interests | 3,455 |  |  | — |
Shareholders’ equity: |  |  |
Common stock, no par, 240,000 shares authorized, 148,888 and 148,203 shares issued, respectively | 1,318,961 |  |  | 1,308,709 |
Retained earnings | 445,370 |  |  | 383,034 |
Accumulated other comprehensive loss | (64,740 | ) |  | (73,964 | )
Total shareholders’ equity | 1,699,591 |  |  | 1,617,779 |
Total liabilities, redeemable noncontrolling interests and shareholders’ equity | $ | 2,596,731 |  |  | $ | 2,347,730 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Net revenues | $ | 751,909 |  |  | $ | 739,818 |  |  | $ | 581,383 |
Cost of sales | 614,071 |  |  | 618,134 |  |  | 519,217 |
Gross profit | 137,838 |  |  | 121,684 |  |  | 62,166 |
Gain (loss) on disposition of assets, net | — |  |  | 146 |  |  | (39 | )
Selling, general and administrative expenses | (69,841 | ) |  | (70,287 | ) |  | (63,257 | )
Income (loss) from operations | 67,997 |  |  | 51,543 |  |  | (1,130 | )
Equity in earnings (losses) of investment | 1,439 |  |  | (3,918 | ) |  | (2,368 | )
Net interest expense | (8,333 | ) |  | (13,751 | ) |  | (18,778 | )
Loss on extinguishment of long-term debt | (18 | ) |  | (1,183 | ) |  | (397 | )
Other income (expense), net | 1,165 |  |  | (6,324 | ) |  | (1,434 | )
Royalty income and other | 3,306 |  |  | 4,631 |  |  | 3,735 |
Income (loss) before income taxes | 65,556 |  |  | 30,998 |  |  | (20,372 | )
Income tax provision (benefit) | 7,859 |  |  | 2,400 |  |  | (50,424 | )
Net income | 57,697 |  |  | 28,598 |  |  | 30,052 |
Net loss attributable to redeemable noncontrolling interests | (222 | ) |  | — |  |  | — |
Net income attributable to common shareholders | $ | 57,919 |  |  | $ | 28,598 |  |  | $ | 30,052 |
Earnings per share of common stock: |  |  |  |  |
Basic | $ | 0.39 |  |  | $ | 0.19 |  |  | $ | 0.20 |
Diluted | $ | 0.38 |  |  | $ | 0.19 |  |  | $ | 0.20 |
Weighted average common shares outstanding: |  |  |  |  |
Basic | 147,536 |  |  | 146,702 |  |  | 145,295 |
Diluted | 149,577 |  |  | 146,830 |  |  | 145,300 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands)

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Net income | $ | 57,697 |  |  | $ | 28,598 |  |  | $ | 30,052 |
Other comprehensive income (loss), net of tax: |  |  |  |  |
Net unrealized gain (loss) on hedges arising during the period | (680 | ) |  | (847 | ) |  | 3,323 |
Reclassifications to net income | 5,470 |  |  | 7,201 |  |  | 12,915 |
Income taxes on hedges | (966 | ) |  | (1,338 | ) |  | (5,724 | )
Net change in hedges, net of tax | 3,824 |  |  | 5,016 |  |  | 10,514 |
Unrealized gain (loss) on note receivable arising during the period | — |  |  | (629 | ) |  | 629 |
Income taxes on note receivable | — |  |  | 132 |  |  | (220 | )
Unrealized gain (loss) on note receivable, net of tax | — |  |  | (497 | ) |  | 409 |
Foreign currency translation gain (loss) | 5,400 |  |  | (7,166 | ) |  | 16,264 |
Other comprehensive income (loss), net of tax | 9,224 |  |  | (2,647 | ) |  | 27,187 |
Comprehensive income | 66,921 |  |  | 25,951 |  |  | 57,239 |
Less comprehensive loss attributable to redeemable noncontrolling interests: |  |  |  |  |
Net loss | (222 | ) |  | — |  |  | — |
Foreign currency translation gain | 138 |  |  | — |  |  | — |
Comprehensive loss attributable to redeemable noncontrolling interests | (84 | ) |  | — |  |  | — |
Comprehensive income attributable to common shareholders | $ | 67,005 |  |  | $ | 25,951 |  |  | $ | 57,239 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)

| Common Stock |  | Retained Earnings |  | Accumulated Other Comprehensive Loss |  | Total Shareholders’ Equity |  | Redeemable Noncontrolling Interests
| Shares |  | Amount |  |  |  |
Balance, December 31, 2016 | 120,630 |  |  | $ | 1,055,934 |  |  | $ | 322,854 |  |  | $ | (96,974 | ) |  | $ | 1,281,814 |  |  | $ | — |
Net income | — |  |  | — |  |  | 30,052 |  |  | — |  |  | 30,052 |  |  | — |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | 16,264 |  |  | 16,264 |  |  | — |
Unrealized gain on hedges, net of tax | — |  |  | — |  |  | — |  |  | 10,514 |  |  | 10,514 |  |  | — |
Unrealized gain on note receivable, net of tax | — |  |  | — |  |  | — |  |  | 409 |  |  | 409 |  |  | — |
Equity component of debt discount on convertible senior notes | — |  |  | (7 | ) |  | — |  |  | — |  |  | (7 | ) |  | — |
Issuance of common stock, net of transaction costs | 26,450 |  |  | 219,504 |  |  | — |  |  | — |  |  | 219,504 |  |  | — |
Activity in company stock plans, net and other | 660 |  |  | (1,887 | ) |  | — |  |  | — |  |  | (1,887 | ) |  | — |
Share-based compensation | — |  |  | 10,730 |  |  | — |  |  | — |  |  | 10,730 |  |  | — |
Balance, December 31, 2017 | 147,740 |  |  | $ | 1,284,274 |  |  | $ | 352,906 |  |  | $ | (69,787 | ) |  | $ | 1,567,393 |  |  | $ | — |
Net income | — |  |  | — |  |  | 28,598 |  |  | — |  |  | 28,598 |  |  | — |
Reclassification of stranded tax effect to retained earnings | — |  |  | — |  |  | 1,530 |  |  | (1,530 | ) |  | — |  |  | — |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | (7,166 | ) |  | (7,166 | ) |  | — |
Unrealized gain on hedges, net of tax | — |  |  | — |  |  | — |  |  | 5,016 |  |  | 5,016 |  |  | — |
Unrealized loss on note receivable, net of tax | — |  |  | — |  |  | — |  |  | (497 | ) |  | (497 | ) |  | — |
Equity component of debt discount on convertible senior notes | — |  |  | 15,411 |  |  | — |  |  | — |  |  | 15,411 |  |  | — |
Activity in company stock plans, net and other | 463 |  |  | (746 | ) |  | — |  |  | — |  |  | (746 | ) |  | — |
Share-based compensation | — |  |  | 9,770 |  |  | — |  |  | — |  |  | 9,770 |  |  | — |
Balance, December 31, 2018 | 148,203 |  |  | $ | 1,308,709 |  |  | $ | 383,034 |  |  | $ | (73,964 | ) |  | $ | 1,617,779 |  |  | $ | — |
Net income (loss) | — |  |  | — |  |  | 57,919 |  |  | — |  |  | 57,919 |  |  | (222 | )
Reclassification of deferred gain from sale leaseback transaction to retained earnings | — |  |  | — |  |  | 4,560 |  |  | — |  |  | 4,560 |  |  | — |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | 5,400 |  |  | 5,400 |  |  | 138 |
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 | ) |  | 143 |
Activity in company stock plans, net and other | 685 |  |  | (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 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Cash flows from operating activities: |  |  |  |  |
Net income | $ | 57,697 |  |  | $ | 28,598 |  |  | $ | 30,052 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |  |
Depreciation and amortization | 112,720 |  |  | 110,522 |  |  | 108,745 |
Amortization of debt discounts | 6,261 |  |  | 5,735 |  |  | 4,688 |
Amortization of debt issuance costs | 3,600 |  |  | 3,592 |  |  | 6,154 |
Share-based compensation | 11,469 |  |  | 9,925 |  |  | 10,877 |
Deferred income taxes | 3,485 |  |  | (2,430 | ) |  | (54,585 | )
Equity in (earnings) losses of investment | (1,439 | ) |  | 3,918 |  |  | 2,368 |
(Gain) loss on disposition of assets, net | — |  |  | (146 | ) |  | 39 |
Loss on extinguishment of long-term debt | 18 |  |  | 1,183 |  |  | 397 |
Unrealized gain on derivative contracts, net | (3,383 | ) |  | (2,324 | ) |  | (4,423 | )
Changes in operating assets and liabilities, net of acquisitions: |  |  |  |  |  |  |  |
Accounts receivable, net | (3,050 | ) |  | 20,920 |  |  | (28,424 | )
Other current assets | 25,383 |  |  | (9,904 | ) |  | (15,680 | )
Income tax payable, net of income tax receivable | (4,456 | ) |  | 964 |  |  | 3,949 |
Accounts payable and accrued liabilities | (31,893 | ) |  | (352 | ) |  | 33,381 |
Other, net | (6,743 | ) |  | 26,543 |  |  | (45,900 | )
Net cash provided by operating activities | 169,669 |  |  | 196,744 |  |  | 51,638 |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Capital expenditures | (140,854 | ) |  | (137,083 | ) |  | (231,127 | )
STL acquisition, net | (4,081 | ) |  | — |  |  | — |
Proceeds from sale of assets | 2,550 |  |  | 25 |  |  | 10,000 |
Other | — |  |  | 1,044 |  |  | — |
Net cash used in investing activities | (142,385 | ) |  | (136,014 | ) |  | (221,127 | )
Cash flows from financing activities: |  |  |  |  |  |  |  |
Issuance of convertible senior notes | — |  |  | 125,000 |  |  | — |
Redemption of convertible senior notes | — |  |  | (60,365 | ) |  | — |
Proceeds from term loans | 35,000 |  |  | — |  |  | 100,000 |
Repayment of term loans | (35,442 | ) |  | (63,807 | ) |  | (194,758 | )
Repayment of Nordea Q5000 Loan | (35,714 | ) |  | (35,714 | ) |  | (35,715 | )
Repayment of MARAD Debt | (6,858 | ) |  | (6,532 | ) |  | (6,222 | )
Debt issuance costs | (1,586 | ) |  | (3,867 | ) |  | (3,717 | )
Net proceeds from issuance of common stock | — |  |  | — |  |  | 219,504 |
Payments related to tax withholding for share-based compensation | (1,680 | ) |  | (1,407 | ) |  | (2,042 | )
Proceeds from issuance of ESPP shares | 462 |  |  | 506 |  |  | 432 |
Net cash provided by (used in) financing activities | (45,818 | ) |  | (46,186 | ) |  | 77,482 |
Effect of exchange rate changes on cash and cash equivalents and restricted cash | 1,636 |  |  | (1,677 | ) |  | 1,952 |
Net increase (decrease) in cash and cash equivalents and restricted cash | (16,898 | ) |  | 12,867 |  |  | (90,055 | )
Cash and cash equivalents and restricted cash: |  |  |  |  |  |  |  |
Balance, beginning of year | 279,459 |  |  | 266,592 |  |  | 356,647 |
Balance, end of year | $ | 262,561 |  |  | $ | 279,459 |  |  | $ | 266,592 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization
Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix Energy Solutions Group, Inc. and its subsidiaries (“Helix” or the “Company”). We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions.
Our Operations
We provide services and methodologies that we believe are critical to maximizing production economics. Our life of field services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 15).
Our Well Intervention segment includes our vessels and/or equipment used to perform well intervention services 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 two chartered monohull vessels, the Siem Helix 1 and the Siem Helix 2. Our well intervention equipment includes intervention riser systems (“IRSs”) and subsea intervention lubricators (“SILs”), some of which we provide on a stand-alone basis.
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and a ROVDrill, which are designed to complement offshore construction and well intervention services, and two robotics support vessels under long-term charter: the Grand Canyon II and the Grand Canyon III. We also utilize spot vessels as needed, including the Ross Candies, which is under a flexible charter agreement. The Grand Canyon charter terminated in November 2019.
Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamically positioned floating production vessel, the Helix Fast Response System (the “HFRS”), our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 5), and our ownership of oil and gas properties acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019 (Note 8). All of our current production facilities activities are located in the Gulf of Mexico.
On May 29, 2019, we acquired a 70% controlling interest in Subsea Technologies Group Limited (“STL”), a subsea engineering firm based in Aberdeen, Scotland, for $5.1 million, including $4.1 million in cash and $1.0 million that we loaned to STL in December 2018. The acquisition is expected to strengthen our supply of subsea intervention systems. The holders of the remaining 30% noncontrolling interest have the right to put their shares to us in June 2024. These redeemable noncontrolling interests have been recognized as temporary equity at their estimated fair value of $3.4 million at the acquisition date. We recognized $2.4 million of identifiable intangible assets and $6.9 million of goodwill, which are reflected in “Other assets” in the accompanying consolidated balance sheet (Note 3). Goodwill is related to the synergies expected from the acquisition. STL is included in our Well Intervention segment and its revenue and earnings are immaterial to our consolidated results.
Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of 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. We account for our ownership interest in Independence Hub under the equity method of accounting. All material intercompany accounts and transactions have been eliminated.
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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. As of December 31, 2019, we had restricted cash of $54.1 million, which serves as collateral for one letter of credit and is expected to be restricted for less than one year.
Accounts Receivable and Allowance for Uncollectible Accounts
Accounts receivable are stated at the historical carrying amount, net of write-offs and allowance for uncollectible accounts. We establish an allowance for uncollectible accounts based on historical experience as well as any specific collection issues that we have identified. 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. Property and equipment is depreciated on a straight-line basis over the estimated useful life of an asset. 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 grouped for impairment purposes at the lowest level where there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The expected future cash flows used for impairment reviews and related fair value calculations are based on assessments of operating revenues and costs, project margins and capital project decisions, considering all available information at the date of review.
Capitalized Interest
Interest from external borrowings is capitalized on major projects 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 in the same manner as the underlying asset. Capitalized interest is excluded from our interest expense (Note 8).
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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. If we provided a commitment to fund losses, we would continue to record losses resulting in a negative equity method investment, which is 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 as of November 1, 2019 was attributable to the STL acquisition in May 2019 (Note 1). We performed a qualitative assessment. Based on our assessment of relevant events and circumstances, we have determined that there was no impairment of goodwill. We had no goodwill in the accompanying consolidated balance sheet at December 31, 2018.
Deferred Recertification and Dry Dock Costs
Our vessels and certain well intervention equipment 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 length of time for which we expect to receive benefits from the recertification, 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 a piece of equipment 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 a piece of equipment are capitalized and depreciated over the asset’s remaining economic useful life. We expense routine repairs and maintenance costs as they are incurred.
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As of December 31, 2019 and 2018, deferred recertification and dry dock costs, which were included within “Other assets, net” in the accompanying consolidated balance sheets (Note 3), totaled $16.1 million and $8.5 million (net of accumulated amortization of $15.7 million and $15.4 million), respectively. During the years ended December 31, 2019, 2018 and 2017, amortization expense related to deferred recertification and dry dock costs was $12.4 million, $8.3 million and $7.0 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 also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs, trenchers and a ROVDrill to provide subsea construction, inspection, repair and maintenance 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 industries. 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.
We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration received under a contract is allocated to the single performance obligation on a systematic basis that depicts the pattern of the provision of our services to the customer.
The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be earned over the term of the contract. We generally do not provide significant financing to our customers and do not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. Estimated variable consideration, if any, is considered to be constrained and therefore is not included in the transaction price until it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our estimates of variable consideration and amounts of that variable consideration that should be constrained.
Dayrate Contracts. Revenues generated from dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g., operating rate, standby rate, and repair rate). Invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with the contractual rate billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month.
Dayrate contracts also may contain fees charged to the customer for mobilizing and/or demobilizing equipment and personnel. Mobilization and demobilization are considered contract fulfillment activities, and related fees (subject to any constraint on estimates of variable consideration) are allocated to the single performance obligation and recognized ratably over the term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer.
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We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.
A dayrate contract modification involving an extension of the contract by adding days of services is generally accounted for prospectively as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.
Lump Sum Contracts. Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.
We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which the adjustment is identified. Revenue and profit in future periods of contract performance are recognized using the adjusted estimate. If a current estimate of total contract costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is identified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue (either as an increase in or a reduction of revenue) on a cumulative catch-up basis.
We implemented a new accounting policy with respect to revenue from contracts with customers upon the adoption of Accounting Standards Update (“ASU”) No. 2014-09 on January 1, 2018. See Note 12 for additional disclosures.
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 reflected 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 without operations in the U.S. to be permanently reinvested.
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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, 2019, 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 is established or are required to pay amounts in excess of 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 are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. PSUs that are accounted for as liability awards are measured at their estimated fair value at the balance sheet date, and subsequent changes in fair value of the awards are recognized in earnings. Cumulative compensation cost for vested liability PSU awards 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”) activities associated with our oil and gas properties, which 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, 2019, 2018 and 2017, our foreign currency transaction gains (losses) totaled $1.5 million, $(4.3) million and $(2.2) 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. All derivative instruments are reflected in the accompanying consolidated balance sheets at fair value.
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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 a derivative instrument that does not qualify for hedge accounting are recorded in earnings in the period in which the change occurs.
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. If the forecasted transaction continues to be probable of occurring, any unrealized gains or losses in accumulated OCI, a component of shareholders’ equity, are reclassified into earnings over the remaining period of the original forecasted transaction.
Interest Rate Risk
From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. Changes in the fair value of interest rate swaps are reported in accumulated OCI. These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense.
Foreign Currency Exchange Rate Risk
Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. We enter into foreign currency exchange contracts from time to time to stabilize expected cash outflows related to forecasted transactions that are denominated in foreign currencies. Changes in the fair value of foreign currency exchange contracts are reported in accumulated OCI. These changes are subsequently reclassified into earnings when the forecasted payments are made. Changes in the fair value of foreign currency exchange contracts that do not qualify as cash flow hedges are recognized immediately in earnings within “Other income (expense), net” in the consolidated statements of operations.
Earnings Per Share
The presentation of basic earnings per share (“EPS”) on the face of the accompanying consolidated statements of operations is computed by dividing net income or loss 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. Shares of restricted stock are considered participating securities 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, the undistributed earnings for each period are 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. Because the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. 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.
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Major Customers and Concentration of Credit Risk
The market for our products and services is primarily the offshore oil and gas and renewable industries. 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. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses. The percentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) are as follows: 2019 — Petrobras (29%), BP (15%) and Shell (13%); 2018 — Petrobras (28%) and BP (15%); and 2017 — BP (19%), Petrobras (13%) and Talos (10%). Most of the concentration of revenues appears in our Well Intervention business.
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 ASU No. 2016-02, “Leases (Topic 842)” (“ASC 842”), which was updated by subsequent amendments. ASC 842 requires a lessee to recognize a lease ROU asset and related lease liability for most leases, including those classified as operating leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We adopted ASC 842 in the first quarter of 2019 using the modified retrospective method. We also elected the package of practical expedients permitted under the transition guidance that, among other things, allows companies to carry forward their historical lease classification. Our adoption of ASC 842 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) as of January 1, 2019. 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. Subsequent to adoption, leases in foreign currencies will generate foreign currency gains and losses, and we will no longer amortize the deferred gain from the aforementioned sale and leaseback transaction. Aside from these changes, ASC 842 has not had, and is not expected to have, a material impact on our net earnings or cash flows.
New accounting standards issued but not yet effective
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. The guidance will be effective for us as of January 1, 2020. We do not expect this ASU to have a material impact on our consolidated financial statements upon adoption.
We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.
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Note 3 — Details of Certain Accounts
Other current assets consist of the following (in thousands):

| December 31,
| 2019 |  | 2018
Contract assets (Note 12) | $ | 740 |  |  | $ | 5,829 |
Prepaids | 11,526 |  |  | 10,306 |
Deferred costs (Note 12) | 28,340 |  |  | 27,368 |
Other | 9,844 |  |  | 8,091 |
Total other current assets | $ | 50,450 |  |  | $ | 51,594 |

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

| December 31,
| 2019 |  | 2018
Prepaids | $ | 777 |  |  | $ | 5,896 |
Deferred recertification and dry dock costs, net (Note 2) | 16,065 |  |  | 8,525 |
Deferred costs (Note 12) | 14,531 |  |  | 38,574 |
Charter deposit (1) | 12,544 |  |  | 12,544 |
Other receivable (Note 16) | 27,264 |  |  | — |
Goodwill (Note 7) | 7,157 |  |  | — |
Intangible assets with finite lives, net (Note 2) | 3,847 |  |  | 1,402 |
Other | 2,323 |  |  | 3,116 |
Total other assets, net | $ | 84,508 |  |  | $ | 70,057 |

(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,
| 2019 |  | 2018
Accrued payroll and related benefits | $ | 31,417 |  |  | $ | 43,079 |
Investee losses in excess of investment (Note 5) | 4,069 |  |  | 5,125 |
Deferred revenue (Note 12) | 11,568 |  |  | 10,103 |
Derivative liability (Note 21) | 1,002 |  |  | 9,311 |
Other | 14,333 |  |  | 17,976 |
Total accrued liabilities | $ | 62,389 |  |  | $ | 85,594 |

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

| December 31,
| 2019 |  | 2018
Investee losses in excess of investment (Note 5) | $ | — |  |  | $ | 6,035 |
Deferred gain on sale of property (1) | — |  |  | 5,052 |
Deferred revenue (Note 12) | 8,286 |  |  | 15,767 |
Asset retirement obligations (Note 16) | 28,258 |  |  | — |
Derivative liability (Note 21) | — |  |  | 884 |
Other | 2,100 |  |  | 11,800 |
Total other non-current liabilities | $ | 38,644 |  |  | $ | 39,538 |

(1) | Relates to the sale and lease-back in January 2016 of certain office and warehouse property located in Aberdeen, Scotland. The deferred gain had been amortized over a 15-year minimum lease term prior to our adoption of ASC 842 on January 1, 2019. See Note 2 for the effect of ASC 842 on this deferred gain.

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 |  | 2019 |  | 2018
Vessels | 15 to 30 years |  | $ | 2,323,314 |  |  | $ | 2,185,409 |
ROVs, trenchers and ROVDrill | 10 years |  | 270,004 |  |  | 284,172 |
Machinery, equipment and leasehold improvements | 5 to 15 years |  | 328,956 |  |  | 316,197 |
Total property and equipment |  |  | $ | 2,922,274 |  |  | $ | 2,785,778 |

Note 5 — Equity Method Investments
We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform, which is in the process of being decommissioned and is expected to be substantially completed within the next 12 months. We recognized a liability of $4.1 million and $11.2 million at December 31, 2019 and 2018, respectively, for our share of Independence Hub’s estimated obligations, net of remaining working capital.
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, 2019, the minimum sublease income to be received in the future totaled $2.9 million.
The following table details the components of our lease cost in 2019 (in thousands):

|  | Year Ended
|  | December 31, 2019
Operating lease cost |  | $ | 70,860 |
Variable lease cost |  | 13,780 |
Short-term lease cost |  | 20,384 |
Sublease income |  | (1,391 | )
Net lease cost |  | $ | 103,633 |

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Maturities of our operating lease liabilities as of December 31, 2019 are as follows (in thousands):

| Vessels |  | Facilities and Equipment |  | Total
2020 | $ | 60,210 |  |  | $ | 6,610 |  |  | $ | 66,820 |
2021 | 54,564 |  |  | 5,888 |  |  | 60,452 |
2022 | 52,106 |  |  | 5,257 |  |  | 57,363 |
2023 | 34,580 |  |  | 4,622 |  |  | 39,202 |
2024 | 2,470 |  |  | 4,349 |  |  | 6,819 |
Thereafter | — |  |  | 6,251 |  |  | 6,251 |
Total lease payments | $ | 203,930 |  |  | $ | 32,977 |  |  | $ | 236,907 |
Less: imputed interest | (24,846 | ) |  | (6,449 | ) |  | (31,295 | )
Total operating lease liabilities | $ | 179,084 |  |  | $ | 26,528 |  |  | $ | 205,612 |
Current operating lease liabilities | $ | 48,716 |  |  | $ | 5,069 |  |  | $ | 53,785 |
Non-current operating lease liabilities | 130,368 |  |  | 21,459 |  |  | 151,827 |
Total operating lease liabilities | $ | 179,084 |  |  | $ | 26,528 |  |  | $ | 205,612 |

The following table presents the weighted average remaining lease term and discount rate in 2019:

| December 31, 2019
Weighted average remaining lease term | 4.0 years |
Weighted average discount rate | 7.54 | %

The following table presents other information related to our operating leases in 2019 (in thousands):

| Year Ended
| December 31, 2019
Cash paid for operating lease liabilities | $ | 71,698 |
ROU assets obtained in exchange for new operating lease obligations | 1,168 |

As previously disclosed in our 2018 Form 10-K and under the previous lease accounting standard, future minimum lease payments for our operating leases as of December 31, 2018 were as follows (in thousands):

| Vessels |  | Facilities and Equipment |  | Total
2019 | $ | 116,620 |  |  | $ | 5,881 |  |  | $ | 122,501 |
2020 | 96,800 |  |  | 5,340 |  |  | 102,140 |
2021 | 89,216 |  |  | 5,185 |  |  | 94,401 |
2022 | 90,371 |  |  | 5,064 |  |  | 95,435 |
2023 | 51,266 |  |  | 4,533 |  |  | 55,799 |
Thereafter | — |  |  | 10,448 |  |  | 10,448 |
Total lease payments | $ | 444,273 |  |  | $ | 36,451 |  |  | $ | 480,724 |

For the years ended December 31, 2018 and 2017, total rental expense was approximately $147.8 million and $114.5 million, respectively. For the years ended December 31, 2018 and 2017, total sublease rental income was $1.4 million and $1.3 million, respectively.
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Note 7 — Goodwill
The changes in the carrying amount of goodwill are as follows (in thousands):

| Well Intervention
Balance at December 31, 2018 | $ | — |
Additions (1) | 6,855 |
Other adjustments (2) | 302 |
Balance at December 31, 2019 | $ | 7,157 |

(1) | Relates to goodwill arising from the STL acquisition in May 2019 (Note 1).

(2) | Relates to foreign currency adjustments.

Note 8 — Long-Term Debt
Long-term debt consists of the following (in thousands):

| December 31,
| 2019 |  | 2018
Term Loan (previously scheduled to mature June 2020) | $ | — |  |  | $ | 33,693 |
Term Loan (matures December 2021) | 33,250 |  |  | — |
2022 Notes (mature May 2022) | 125,000 |  |  | 125,000 |
2023 Notes (mature September 2023) | 125,000 |  |  | 125,000 |
MARAD Debt (matures February 2027) | 63,610 |  |  | 70,468 |
Nordea Q5000 Loan (matures April 2020) | 89,286 |  |  | 125,000 |
Unamortized debt discounts | (22,540 | ) |  | (28,802 | )
Unamortized debt issuance costs | (7,753 | ) |  | (10,044 | )
Total debt | 405,853 |  |  | 440,315 |
Less current maturities | (99,731 | ) |  | (47,252 | )
Long-term debt | $ | 306,122 |  |  | $ | 393,063 |

Credit Agreement
On June 30, 2017, we entered into an Amended and Restated Credit Agreement (and the amendments made thereafter, collectively the “Credit Agreement”) with a group of lenders led by Bank of America, N.A. (“Bank of America”). On June 28, 2019, we amended our existing term loan (the “Term Loan”) and revolving credit facility (the “Revolving Credit Facility”) under the Credit Agreement. The Credit Agreement is comprised of a $35 million Term Loan and a Revolving Credit Facility of $175 million and matures on December 31, 2021. The Revolving Credit Facility permits us to obtain letters of credit up to a sublimit of $25 million. Pursuant to the Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may request aggregate commitments of up to $100 million with respect to an increase in the Revolving Credit Facility. As of December 31, 2019, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the leverage ratios, totaled $171.1 million, net of $3.9 million of letters of credit issued under that facility.
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Borrowings under the Credit Agreement bear interest, at our election, at either Bank of America’s base rate, the LIBOR or a comparable successor rate, or a combination thereof. The Term Loan bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin of 2.25%. The Term Loan bearing interest at a LIBOR rate will bear interest per annum at the LIBOR or a comparable successor rate selected by us plus a margin of 3.25%. The interest rate on the Term Loan was 5.05% as of December 31, 2019. Borrowings under the Revolving Credit Facility bearing interest at the base rate will bear interest at a per annum rate equal to Bank of America’s base rate plus a margin ranging from 1.50% to 2.50%. Borrowings under the Revolving Credit Facility bearing interest at a LIBOR rate will bear interest per annum at the LIBOR or a comparable successor rate selected by us plus a margin ranging from 2.50% to 3.50%. A letter of credit fee is payable by us equal to the applicable margin for LIBOR rate loans multiplied by the daily amount available to be drawn under the applicable letter of credit. Margins on borrowings under the Revolving Credit Facility will vary in relation to the Consolidated Total Leverage Ratio (as defined below) as provided for in the Credit Agreement. We also pay a fixed commitment fee of 0.50% per annum on the unused portion of the Revolving Credit Facility.
The Term Loan principal is required to be repaid in quarterly installments of 2.5% of the aggregate principal amount of the Term Loan, with a balloon payment at maturity. Installment amounts are subject to adjustment for any prepayments on the Term Loan. We may prepay indebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay indebtedness outstanding under the Revolving Credit Facility without premium or penalty, and may reborrow any amounts prepaid up to the amount available under the Revolving Credit Facility.
The Credit Agreement and the other documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, which we consider customary for this type of transaction. The covenants include certain restrictions on our and certain of our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum ratio requirements of EBITDA to interest charges (Consolidated Interest Coverage Ratio), funded debt to EBITDA (Consolidated Total Leverage Ratio) and secured funded debt to EBITDA (Consolidated Secured Leverage Ratio).
We may designate one or more of our new foreign subsidiaries as subsidiaries not generally subject to the covenants in the Credit Agreement (the “Unrestricted Subsidiaries”). The debt and EBITDA of the Unrestricted Subsidiaries with the exception of Helix Q5000 Holdings, S.à r.l. (“Q5000 Holdings”), a wholly owned Luxembourg subsidiary of Helix Vessel Finance S.à r.l., are not included in the calculations of our financial covenants. Our obligations under the Credit Agreement, and those of our subsidiary guarantors under their guarantee, are secured by (i) most of the assets of the parent company, (ii) the shares of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Helix Robotics Solutions Limited (formerly known as Canyon Offshore Limited) and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Helix Robotics Solutions Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.
In June 2019, in connection with the amendment of the Credit Agreement we wrote off the remaining unamortized debt issuance costs associated with a lender exiting the Credit Agreement. In March 2018, we prepaid $61 million of the then-existing term loan with a portion of the net proceeds from the 2023 Notes and recognized a $0.9 million loss to write off the related remaining unamortized debt issuance costs. In June 2017, we recognized a $0.4 million loss to write off the remaining unamortized debt issuance costs related to certain lenders exiting from the then-existing term loan. These losses are presented as “Loss on extinguishment of long-term debt” in the accompanying consolidated statements of operations. In connection with decreases in lenders’ commitments under our then-existing revolving credit facility, in June 2017, we recorded a $1.6 million interest charge to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments were reduced.
In January 2019, contemporaneously with our acquisition from Marathon Oil of several wells and related infrastructure associated with the Droshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244, we amended the Credit Agreement to permit the issuance of certain security to third parties for required P&A obligations and to make certain capital expenditures in connection with acquired assets (Note 16).
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Convertible Senior Notes Due 2022 (“2022 Notes”)
On November 1, 2016, we completed a public offering and sale of the 2022 Notes in the aggregate principal amount of $125 million. The 2022 Notes bear interest at a rate of 4.25% per annum and are payable semi-annually in arrears on November 1 and May 1 of each year, beginning on May 1, 2017. The 2022 Notes mature on May 1, 2022 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2022 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 71.9748 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $13.89 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
Prior to November 1, 2019, the 2022 Notes were not redeemable. Beginning November 1, 2019, if certain conditions are met, we may redeem all or any portion of the 2022 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest and a “make-whole premium” (as defined in the indenture governing the 2022 Notes). Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change” (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 occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2022 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be 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 2022 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
The 2022 Notes were initially accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million ($11.0 million net of tax) as a result of separating the equity component. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount over the term of the 2022 Notes. For the years ended December 31, 2019, 2018 and 2017, interest expense (including amortization of the debt discount) related to the 2022 Notes totaled $8.4 million, $8.1 million and $7.9 million, respectively. The remaining unamortized debt discount of the 2022 Notes was $8.0 million and $11.0 million at December 31, 2019 and 2018, respectively.
Convertible Senior Notes Due 2023 (“2023 Notes”)
On March 20, 2018, we completed a public offering and sale of the 2023 Notes in the aggregate principal amount of $125 million. The 2023 Notes bear interest at a rate of 4.125% per annum and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2018. The 2023 Notes mature on September 15, 2023 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2023 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $9.47 per share of common stock), subject to adjustment in certain circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash. Although not currently convertible, the value of the shares into which the 2023 Notes are convertible exceeded the principal amount of the 2023 Notes by $2.1 million as of December 31, 2019.
Prior to March 15, 2021, the 2023 Notes are not redeemable. On or after March 15, 2021, if certain conditions are met, we may redeem all or any portion of the 2023 Notes at a redemption price payable in cash equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest and a “make-whole premium” (as defined in the indenture governing the 2023 Notes). Holders of the 2023 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2023 Notes).
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The indenture governing the 2023 Notes contains customary terms and covenants, including that upon certain events of default occurring and continuing, either the trustee under the indenture or the holders of not less than 25% in aggregate principal amount then outstanding under the 2023 Notes may declare the entire principal amount of all the notes, and the interest accrued on such notes, if any, to be 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 and unpaid interest thereon will become immediately due and payable.
The 2023 Notes were initially accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2023 Notes, we recorded a debt discount of $20.1 million ($15.9 million net of tax) as a result of separating the equity component. The effective interest rate for the 2023 Notes is 7.8% after considering the effect of the accretion of the related debt discount over the term of the 2023 Notes. For the years ended December 31, 2019 and 2018, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled $8.4 million and $6.4 million, respectively. The remaining unamortized debt discount of the 2023 Notes was $14.5 million and $17.8 million at December 31, 2019 and 2018, respectively.
MARAD Debt
This U.S. government guaranteed financing (the “MARAD Debt”), pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, was used to finance the construction of the Q4000. The MARAD Debt is collateralized by the Q4000 and is guaranteed 50% by us. The MARAD Debt is payable in equal semi-annual installments, matures in February 2027 and bears interest at a rate of 4.93%.
Nordea Credit Agreement
In September 2014, Q5000 Holdings entered into a credit agreement (the “Nordea Credit Agreement”) with a syndicated bank lending group for a term loan (the “Nordea Q5000 Loan”) in an amount of up to $250 million. The Nordea Q5000 Loan was funded in the amount of $250 million in April 2015 at the time the Q5000 vessel was delivered to us. Helix Vessel Finance S.à r.l., an indirect wholly owned Luxembourg subsidiary of Helix, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.
The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. The remaining principal balance and unamortized debt issuance costs related to the Nordea Q5000 Loan are classified as current in the accompanying consolidated balance sheet as of December 31, 2019. Q5000 Holdings may elect to prepay indebtedness outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Quarterly principal installments are subject to adjustment for any prepayments on this debt. We use interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 21). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under the Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.
The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.
Other
We previously issued additional convertible senior notes in March 2012, which were originally scheduled to mature on March 15, 2032 (the “2032 Notes”). In 2018, we fully redeemed the remaining $60.1 million in aggregate principal amount of the 2032 Notes and recognized a corresponding $0.2 million loss. The loss is presented as “Loss on extinguishment of long-term debt” in the accompanying consolidated statements of operations.
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As discussed above, in accordance with the Credit Agreement, the 2022 Notes, the 2023 Notes, the MARAD Debt agreements and the Nordea Credit Agreement, we are required to comply with certain covenants, including with respect to the Credit Agreement, certain financial ratios such as a consolidated interest coverage ratio, a consolidated total leverage ratio and a consolidated secured leverage ratio, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. As of December 31, 2019, we were in compliance with these covenants.
Scheduled maturities of our long-term debt outstanding as of December 31, 2019 are as follows (in thousands):

| Term Loan (1) |  | 2022 Notes |  | 2023 Notes |  | MARAD Debt |  | Nordea Q5000 Loan |  | Total
Less than one year | $ | 3,500 |  |  | $ | — |  |  | $ | — |  |  | $ | 7,200 |  |  | $ | 89,286 |  |  | $ | 99,986 |
One to two years | 29,750 |  |  | — |  |  | — |  |  | 7,560 |  |  | — |  |  | 37,310 |
Two to three years | — |  |  | 125,000 |  |  | — |  |  | 7,937 |  |  | — |  |  | 132,937 |
Three to four years | — |  |  | — |  |  | 125,000 |  |  | 8,333 |  |  | — |  |  | 133,333 |
Four to five years | — |  |  | — |  |  | — |  |  | 8,749 |  |  | — |  |  | 8,749 |
Over five years | — |  |  | — |  |  | — |  |  | 23,831 |  |  | — |  |  | 23,831 |
Gross debt | 33,250 |  |  | 125,000 |  |  | 125,000 |  |  | 63,610 |  |  | 89,286 |  |  | 436,146 |
Unamortized debt discounts (2) | — |  |  | (7,999 | ) |  | (14,541 | ) |  | — |  |  | — |  |  | (22,540 | )
Unamortized debt issuance costs (3) | (381 | ) |  | (1,236 | ) |  | (2,344 | ) |  | (3,537 | ) |  | (255 | ) |  | (7,753 | )
Total debt | 32,869 |  |  | 115,765 |  |  | 108,115 |  |  | 60,073 |  |  | 89,031 |  |  | 405,853 |
Less current maturities | (3,500 | ) |  | — |  |  | — |  |  | (7,200 | ) |  | (89,031 | ) |  | (99,731 | )
Long-term debt | $ | 29,369 |  |  | $ | 115,765 |  |  | $ | 108,115 |  |  | $ | 52,873 |  |  | $ | — |  |  | $ | 306,122 |

(1) | Term Loan pursuant to the Credit Agreement matures in December 2021.

(2) | The 2022 Notes and the 2023 Notes will increase to their face amounts through accretion of their debt discounts to interest expense through May 2022 and September 2023, respectively.

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

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

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Interest expense | $ | 31,186 |  |  | $ | 32,617 |  |  | $ | 38,274 |
Capitalized interest | (20,246 | ) |  | (15,629 | ) |  | (16,906 | )
Interest income | (2,607 | ) |  | (3,237 | ) |  | (2,590 | )
Net interest expense | $ | 8,333 |  |  | $ | 13,751 |  |  | $ | 18,778 |

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Note 9 — Income Taxes
On December 22, 2017, the 2017 Tax Act was enacted. The 2017 Tax Act is comprehensive tax reform legislation that contains significant changes to corporate taxation, including a permanent reduction of the corporate income tax rate from 35% to 21%, a mandatory one-time tax on un-repatriated accumulated earnings of foreign subsidiaries, a partial limitation on the deductibility of business interest expense, and a shift from U.S. taxation on worldwide income of multinational corporations to a partial territorial system (along with rules that create a new U.S. minimum tax on earnings of foreign subsidiaries).
Due to the changes to U.S. tax laws as a result of the 2017 Tax Act, we recorded a $51.6 million net income tax benefit during the fourth quarter of 2017. This amount was comprised of the following:
Reduction of the U.S. Corporate Income Tax Rate
We measure deferred tax assets and liabilities using enacted tax rates that will apply in the years in which the temporary differences are expected to reverse. Accordingly, our deferred tax assets and liabilities were re-measured to reflect the reduction in the U.S. corporate income tax rate from 35% to 21%, resulting in a $59.7 million deferred income tax benefit recorded during the fourth quarter of 2017 and a corresponding decrease in net deferred tax liabilities as of December 31, 2017.
Transition Tax on Foreign Earnings
The one-time transition tax was based on our total post-1986 foreign earnings and profits (“E&P”) deemed repatriated to the U.S. to the extent the E&P has not already been subject to U.S. taxation. We recorded a deferred income tax expense of $8.1 million during the fourth quarter of 2017 related to the one-time transition tax on certain foreign earnings. This resulted in a corresponding decrease in deferred tax assets of $8.1 million due to the utilization of U.S. net operating losses against the deemed mandatory repatriation income inclusion.
We and our subsidiaries file a consolidated U.S. federal income tax return. We believe that our recorded deferred tax assets and liabilities are reasonable. However, tax laws and regulations are subject to interpretation, and the outcomes of tax disputes are inherently uncertain; therefore, our assessments can involve a series of complex judgments about future events and rely heavily on estimates and assumptions.
Components of income tax provision (benefit) reflected in the consolidated statements of operations consist of the following (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Current | $ | 4,374 |  |  | $ | 4,830 |  |  | $ | 4,161 |
Deferred | 3,485 |  |  | (2,430 | ) |  | (54,585 | )
| $ | 7,859 |  |  | $ | 2,400 |  |  | $ | (50,424 | )

Domestic | $ | 3,715 |  |  | $ | (3,161 | ) |  | $ | (53,044 | )
Foreign | 4,144 |  |  | 5,561 |  |  | 2,620 |
| $ | 7,859 |  |  | $ | 2,400 |  |  | $ | (50,424 | )

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

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Domestic | $ | 2,219 |  |  | $ | (28,838 | ) |  | $ | (221 | )
Foreign | 63,337 |  |  | 59,836 |  |  | (20,151 | )
| $ | 65,556 |  |  | $ | 30,998 |  |  | $ | (20,372 | )

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Income taxes are provided based on the U.S. statutory rate and at the local statutory rate for each foreign jurisdiction adjusted for items that are allowed as deductions for federal and foreign income tax reporting purposes, but not for book purposes. The primary differences between the U.S. statutory rate and our effective rate are as follows:

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Statutory rate | 21.0 | % |  | 21.0 | % |  | 35.0 | %
Foreign provision | (10.0 | ) |  | (15.9 | ) |  | (6.2 | )
Change in U.S. statutory rate (1) | — |  |  | — |  |  | 293.1 |
Mandatory U.S. repatriation (1) | — |  |  | — |  |  | (39.7 | )
Change in tax position (2) | — |  |  | — |  |  | (31.1 | )
Other | 1.0 |  |  | 2.6 |  |  | (3.6 | )
Effective rate | 12.0 | % |  | 7.7 | % |  | 247.5 | %

(1) | As a result of the U.S. tax law changes, we recorded a net deferred tax benefit of $51.6 million during the fourth quarter of 2017 (see above).

(2) | As a result of a change in tax position related to our foreign taxes, we recorded a tax charge of $6.3 million in June 2017.

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,
| 2019 |  | 2018
Deferred tax liabilities: |  |  |
Depreciation | $ | 166,239 |  |  | $ | 149,974 |
Debt discounts on 2022 Notes and 2023 Notes | 4,643 |  |  | 5,902 |
Prepaid and other | — |  |  | 1,309 |
Total deferred tax liabilities | $ | 170,882 |  |  | $ | 157,185 |
Deferred tax assets: |  |  |
Net operating losses | $ | (64,178 | ) |  | $ | (47,916 | )
Reserves, accrued liabilities and other | (13,203 | ) |  | (21,347 | )
Total deferred tax assets | (77,381 | ) |  | (69,263 | )
Valuation allowance | 18,631 |  |  | 17,940 |
Net deferred tax liabilities | $ | 112,132 |  |  | $ | 105,862 |

At December 31, 2019, our U.S. net operating losses available for carryforward totaled $228.3 million. The U.S. net operating loss carryforwards prior to 2018 in the amount of $112.3 million will begin to expire in 2035 if unused. Realization is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that all of these tax attributes will be utilized. The amount of the deferred tax asset considered realizable, however, could be reduced if estimates of future taxable income during the carryforward period are reduced.
At December 31, 2019, we had a $3.0 million valuation allowance recorded against our U.S. deferred tax assets for foreign tax credits. Management believes it is more likely than not that we will not be able to utilize the foreign tax credits prior to their expiration.
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At December 31, 2019, we had a $15.6 million valuation allowance related to certain non-U.S. deferred tax assets, primarily net operating losses from our Robotics segment in the U.K., as management believes it is more likely than not that we will not be able to utilize the tax benefits. Additional valuation allowances may be made in the future if in management’s opinion it is more likely than not that future tax benefits will not be utilized.
At December 31, 2019, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $129.2 million. Due to the enactment of the 2017 Tax Act, repatriations of foreign earnings will generally be free of U.S. federal tax but may result in other withholding taxes or state taxes. Indefinite reinvestment is determined by management’s intentions concerning our future operations. We intend to indefinitely reinvest these earnings, as well as future earnings from our non-U.S. subsidiaries without operations in the U.S., to fund our international operations. In addition, we expect future U.S. cash generation will be sufficient to meet future U.S. cash needs. We have not provided deferred income taxes on the accumulated earnings and profits from our non-U.S. subsidiaries without operations in the U.S. as we consider them permanently reinvested. Due to complexities in the tax laws and the manner of repatriation, it is not practicable to estimate the unrecognized amount of deferred income taxes and the related dividend withholding taxes associated with these undistributed earnings.
We account for tax-related interest in interest expense and tax penalties in selling, general and administrative expenses. The statute of limitations on our sole remaining uncertain tax position expired in 2019. Therefore, as of December 31, 2019 there were no unrecognized tax benefits related to uncertain tax positions. As of December 31, 2018 and 2017, we had unrecognized tax benefits of $0.3 million related to uncertain tax positions, which if recognized would have affected the annual effective tax rate in those years.
A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2019, 2018 and 2017 is as follows (in thousands):

| 2019 |  | 2018 |  | 2017
Balance at January 1, | $ | 306 |  |  | $ | 318 |  |  | $ | 343 |
Additions for tax positions of prior years | — |  |  | — |  |  | — |
Reductions for tax positions of prior years | (306 | ) |  | (12 | ) |  | (25 | )
Balance at December 31, | $ | — |  |  | $ | 306 |  |  | $ | 318 |

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 2016 through 2019 remain open to review and examination by the Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2013 through 2019.
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.
On January 10, 2017, we completed an underwritten public offering (the “Offering”) of 26,450,000 shares of our common stock at a public offering price of $8.65 per share. The net proceeds from the Offering approximated $220 million, after deducting underwriting discounts and commissions and offering expenses. We used the net proceeds from the Offering for general corporate purposes, including debt repayment, capital expenditures, working capital and investments in our subsidiaries.
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The components of accumulated OCI are as follows (in thousands):

| December 31,
| 2019 |  | 2018
Cumulative foreign currency translation adjustment | $ | (64,455 | ) |  | $ | (69,855 | )
Net unrealized loss on hedges, net of tax (1) | (285 | ) |  | (4,109 | )
Accumulated OCI | $ | (64,740 | ) |  | $ | (73,964 | )

(1) | Relates to foreign currency hedges for the Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan (Note 21). Balances at December 31, 2019 and 2018 were net of deferred income taxes totaling $0.1 million and $1.0 million, respectively.

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, 2019, 4,866,645 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 Intervention |  | Robotics |  | Production Facilities |  | Intercompany Eliminations (1) |  | Total Revenue
Year ended December 31, 2019 |  |  |  |  |  |  |  |  |
Short-term | $ | 214,926 |  |  | $ | 94,501 |  |  | $ | — |  |  | $ | — |  |  | $ | 309,427 |
Long-term (2) | 378,374 |  |  | 77,171 |  |  | 61,210 |  |  | (74,273 | ) |  | 442,482 |
Total | $ | 593,300 |  |  | $ | 171,672 |  |  | $ | 61,210 |  |  | $ | (74,273 | ) |  | $ | 751,909 |
Year ended December 31, 2018 |  |  |  |  |  |  |  |  |
Short-term | $ | 199,294 |  |  | $ | 89,072 |  |  | $ | — |  |  | $ | — |  |  | $ | 288,366 |
Long-term (2) | 361,274 |  |  | 69,917 |  |  | 64,400 |  |  | (44,139 | ) |  | 451,452 |
Total | $ | 560,568 |  |  | $ | 158,989 |  |  | $ | 64,400 |  |  | $ | (44,139 | ) |  | $ | 739,818 |

(1) | Intercompany revenues among our business segments are under agreements that are considered long-term.

(2) | 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.

Contract Balances
Accounts receivable are recognized when our right to consideration becomes unconditional. Accounts receivable that have been billed to customers are recorded as trade accounts receivable while accounts receivable that have not been billed to customers are recorded as unbilled accounts receivable.
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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, 2019 and 2018 were $0.7 million and $5.8 million, respectively. We had no impairment losses on our accounts receivable for the years ended December 31, 2019 and 2018.
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, 2019 and 2018 totaled $19.9 million and $25.9 million, respectively. Revenue recognized for the years ended December 31, 2019 and 2018 included $10.1 million and $11.6 million, respectively, that were included in the contract liability balance as the beginning of each period.
We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.
Performance Obligations
As of December 31, 2019, $796.4 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $509.4 million in 2020, $221.2 million in 2021 and $65.8 million in 2022 and thereafter. 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, 2019.
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. For the year ended December 31, 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial.
Contract Fulfillment Costs
Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 3). Our deferred contract costs as of December 31, 2019 and 2018 totaled $42.9 million and $65.9 million, respectively. For the years ended December 31, 2019 and 2018, we recorded $31.5 million and $33.1 million, respectively, related to amortization of deferred contract costs existing at the beginning of each period. There were no associated impairment losses for any period presented.
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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,
| 2019 |  | 2018 |  | 2017
| Income |  | Shares |  | Income |  | Shares |  | Income |  | Shares
Basic: |  |  |  |  |  |  |  |  |  |  |
Net income attributable to common shareholders | $ | 57,919 |  |  |  |  | $ | 28,598 |  |  |  |  | $ | 30,052 |  |  |
Less: Undistributed earnings allocated to participating securities | (487 | ) |  |  |  | (273 | ) |  |  |  | (356 | ) |  |
Accretion of redeemable noncontrolling interests | (143 | ) |  |  |  | — |  |  |  |  | — |  |  |
Net income available to common shareholders, basic | $ | 57,289 |  |  | 147,536 |  |  | $ | 28,325 |  |  | 146,702 |  |  | $ | 29,696 |  |  | 145,295 |

Diluted: |  |  |  |  |  |  |  |  |  |  |
Net income available to common shareholders, basic | $ | 57,289 |  |  | 147,536 |  |  | $ | 28,325 |  |  | 146,702 |  |  | $ | 29,696 |  |  | 145,295 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |  |  |
Share-based awards other than participating securities | — |  |  | 2,041 |  |  | — |  |  | 128 |  |  | — |  |  | 5 |
Undistributed earnings reallocated to participating securities | 6 |  |  | — |  |  | 1 |  |  | — |  |  | — |  |  | — |
Net income available to common shareholders, diluted | $ | 57,295 |  |  | 149,577 |  |  | $ | 28,326 |  |  | 146,830 |  |  | $ | 29,696 |  |  | 145,300 |

The following potentially dilutive shares related to the 2022 Notes, the 2023 Notes and the 2032 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
2022 Notes | 8,997 |  |  | 8,997 |  |  | 8,997 |
2023 Notes | 13,202 |  |  | 10,344 |  |  | — |
2032 Notes (1) | — |  |  | 524 |  |  | 2,403 |

(1) | The 2032 Notes were fully redeemed in May 2018.

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Note 14 — Employee Benefit Plans
Defined Contribution Plan
We sponsor a defined contribution 401(k) retirement plan. Our discretionary contributions, which were reactivated in April 2019, are in the form of cash and currently consist of a 50% match of each participant’s contribution up to 5% of the participant’s salary. We made employer contributions of $1.0 million to the 401(k) plan in 2019.
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, 2019, 2.0 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 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 of our Board. 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, restricted stock units, 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, 2019, there were 8.3 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 2019 under the 2005 Incentive Plan:

Date of Grant |  |  | Shares/ Units |  |  | Grant Date Fair Value Per Share/Unit |  | Vesting Period
January 2, 2019 (1) |  |  | 688,540 |  |  |  |  | $ | 5.41 |  |  |  | 33% per year over three years
January 2, 2019 (2) |  |  | 688,540 |  |  |  |  | $ | 7.60 |  |  |  | 100% on January 2, 2022
January 2, 2019 (3) |  |  | 11,841 |  |  |  |  | $ | 5.41 |  |  |  | 100% on January 1, 2021
April 1, 2019 (3) |  |  | 7,625 |  |  |  |  | $ | 7.91 |  |  |  | 100% on January 1, 2021
July 1, 2019 (3) |  |  | 8,727 |  |  |  |  | $ | 8.63 |  |  |  | 100% on January 1, 2021
August 1, 2019 (4) |  |  | 7,151 |  |  |  |  | $ | 8.76 |  |  |  | 100% on August 1, 2020
October 1, 2019 (3) |  |  | 7,948 |  |  |  |  | $ | 8.06 |  |  |  | 100% on January 1, 2021
December 12, 2019 (5) |  |  | 115,003 |  |  |  |  | $ | 9.13 |  |  |  | 100% on December 12, 2020

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

(2) | Reflects grants of PSUs to our executive officers and select management employees. These awards when vested can only be settled in shares of our common stock.

(3) | Reflects grants of restricted stock to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash.

(4) | Reflects a grant of restricted stock made to a new independent member of our Board upon her joining our Board.

(5) | Reflects annual equity grants to each independent member of our Board.

In January 2020, we granted our executive officers and select management employees 369,938 shares of restricted stock and 369,938 PSUs under the 2005 Incentive Plan. The market value of the restricted shares was $9.63 per share or $3.6 million. The grant date fair value of the PSUs was $13.15 per unit. Also in January 2020, we granted $4.7 million of fixed value cash awards to other select management employees under the 2005 Incentive Plan.
Restricted Stock Awards
We grant restricted stock to members of our Board, executive officers and select management employees. The following table summarizes information about our restricted stock:

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
| Shares |  | Grant Date Fair Value (1) |  | Shares |  | Grant Date Fair Value (1) |  | Shares |  | Grant Date Fair Value (1)
Awards outstanding at beginning of year | 1,320,989 |  |  | $ | 7.40 |  |  | 1,579,218 |  |  | $ | 7.63 |  |  | 1,577,973 |  |  | $ | 7.86 |
Granted | 846,835 |  |  | 6.02 |  |  | 614,286 |  |  | 7.46 |  |  | 829,143 |  |  | 8.39 |
Vested (2) | (993,361 | ) |  | 6.92 |  |  | (823,310 | ) |  | 7.88 |  |  | (817,791 | ) |  | 8.84 |
Forfeited | (1,418 | ) |  | 8.82 |  |  | (49,205 | ) |  | 7.62 |  |  | (10,107 | ) |  | 7.01 |
Awards outstanding at end of year | 1,173,045 |  |  | $ | 6.81 |  |  | 1,320,989 |  |  | $ | 7.40 |  |  | 1,579,218 |  |  | $ | 7.63 |

(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, 2019, 2018 and 2017 was $6.5 million, $6.4 million and $6.9 million, respectively.

For the years ended December 31, 2019, 2018 and 2017, $6.2 million, $6.0 million and $7.9 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost associated with unvested restricted stock at December 31, 2019 totaled approximately $4.2 million. The weighted average vesting period related to unvested restricted stock at December 31, 2019 was approximately 1.3 years.
Performance Share Unit Awards
We grant PSUs to our executive officers and from time to time select management employees. The payout at vesting of PSUs is based on the performance of our common stock over a three-year period compared to the performance of other companies in a peer group selected by the Compensation Committee of our Board, with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero. PSUs granted prior to 2017 were settled in cash and accounted for as liability awards. PSUs granted beginning in 2017 are to be settled solely in shares of our common stock and therefore are accounted for as equity awards.
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The following table summarizes information about our equity PSU awards:

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
| Units |  | Grant Date Fair Value (1) |  | Units |  | Grant Date Fair Value (1) |  | Units |  | Grant Date Fair Value (1)
Equity PSU awards outstanding at beginning of year | 1,006,360 |  |  | $ | 11.76 |  |  | 613,665 |  |  | $ | 12.64 |  |  | — |  |  | $ | — |
Granted | 688,540 |  |  | 7.60 |  |  | 449,271 |  |  | 10.44 |  |  | 671,771 |  |  | 12.64 |
Forfeited | (129,856 | ) |  | 8.91 |  |  | (56,576 | ) |  | 10.83 |  |  | (58,106 | ) |  | 12.64 |
Equity PSU awards outstanding at end of year | 1,565,044 |  |  | $ | 10.17 |  |  | 1,006,360 |  |  | $ | 11.76 |  |  | 613,665 |  |  | $ | 12.64 |

(1) | Represents the weighted average grant date fair value, which is determined using a Monte Carlo simulation model.

For the years ended December 31, 2019, 2018 and 2017, $5.1 million, $3.8 million and $2.8 million, respectively, were recognized as share-based compensation related to equity PSU awards. Future compensation cost associated with unvested equity PSU awards at December 31, 2019 totaled approximately $4.2 million. The weighted average vesting period related to unvested equity PSU awards at December 31, 2019 was approximately 1.0 year. In January 2020, 589,335 equity PSU awards granted in 2017 vested at 200%, representing 1,178,670 shares of our common stock with a total market value of $11.4 million.
For the years ended December 31, 2018 and 2017, $0.9 million and $4.6 million, respectively, were recognized as share-based compensation related to liability PSU awards. At December 31, 2018, the liability balance for unvested liability PSU awards related to the 2016 grant was $11.1 million, which were cash settled when they vested in January 2019. During 2018 and 2017, we cash settled $0.9 million and $0.6 million, respectively, related to the liability PSU awards granted in 2015 and 2014.
Cash Awards
In 2019 and 2018, we granted $4.6 million and $5.2 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, 2019 and 2018, $3.2 million and $1.7 million, respectively, was recognized as compensation cost, which reflected the liability balance as of December 31, 2019 and 2018 for the cash payout made in January 2020 and 2019, 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 business segment for financial reporting purposes. Our Well Intervention reportable segment includes our vessels and/or equipment used to perform well intervention services 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 chartered Siem Helix 1 and Siem Helix 2 vessels. Our well intervention equipment includes IRSs and SILs, some of which we provide on a stand-alone basis. Our Robotics segment includes ROVs, trenchers and a ROVDrill, which are designed to complement offshore construction and well intervention services, two robotics support vessels under long-term charter: the Grand Canyon II and the Grand Canyon III, and spot vessels, including the Ross Candies, which is under a flexible charter agreement. We returned the Grand Canyon to its owner during the fourth quarter of 2019. Our Production Facilities segment includes the HP I, the HFRS, our ownership interest in Independence Hub (Note 5) and our ownership of oil and gas properties (Note 1). All material intercompany transactions between the segments have been eliminated.
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We evaluate our performance based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Net revenues — |  |  |  |  |
Well Intervention | $ | 593,300 |  |  | $ | 560,568 |  |  | $ | 406,341 |
Robotics | 171,672 |  |  | 158,989 |  |  | 152,755 |
Production Facilities | 61,210 |  |  | 64,400 |  |  | 64,352 |
Intercompany eliminations | (74,273 | ) |  | (44,139 | ) |  | (42,065 | )
Total | $ | 751,909 |  |  | $ | 739,818 |  |  | $ | 581,383 |

Income (loss) from operations — |  |  |  |  |
Well Intervention | $ | 89,564 |  |  | $ | 87,643 |  |  | $ | 52,733 |
Robotics | 7,261 |  |  | (14,054 | ) |  | (42,289 | )
Production Facilities | 17,160 |  |  | 27,263 |  |  | 28,172 |
Segment operating income | 113,985 |  |  | 100,852 |  |  | 38,616 |
Corporate, eliminations and other | (45,988 | ) |  | (49,309 | ) |  | (39,746 | )
Total | 67,997 |  |  | 51,543 |  |  | (1,130 | )
Net interest expense | (8,333 | ) |  | (13,751 | ) |  | (18,778 | )
Other non-operating income (expense), net | 5,892 |  |  | (6,794 | ) |  | (464 | )
Income (loss) before income taxes | $ | 65,556 |  |  | $ | 30,998 |  |  | $ | (20,372 | )

Capital expenditures — |  |  |  |  |
Well Intervention | $ | 139,212 |  |  | $ | 136,164 |  |  | $ | 230,354 |
Robotics | 417 |  |  | 151 |  |  | 648 |
Production Facilities | 123 |  |  | 325 |  |  | — |
Corporate and other | 1,102 |  |  | 443 |  |  | 125 |
Total | $ | 140,854 |  |  | $ | 137,083 |  |  | $ | 231,127 |

Depreciation and amortization — |  |  |  |  |
Well Intervention | $ | 80,153 |  |  | $ | 76,943 |  |  | $ | 68,301 |
Robotics | 16,459 |  |  | 19,175 |  |  | 23,626 |
Production Facilities | 15,658 |  |  | 14,070 |  |  | 13,936 |
Corporate and eliminations | 450 |  |  | 334 |  |  | 2,882 |
Total | $ | 112,720 |  |  | $ | 110,522 |  |  | $ | 108,745 |

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

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Well Intervention (1) | $ | 43,484 |  |  | $ | 14,218 |  |  | $ | 11,489 |
Robotics | 30,789 |  |  | 29,921 |  |  | 30,576 |
Total | $ | 74,273 |  |  | $ | 44,139 |  |  | $ | 42,065 |

(1) | Amount in the year ended December 31, 2019 included $27.5 million associated with P&A work on two of the Droshky wells for our Production Facilities segment (Note 16). Marathon Oil has agreed to remit payment to us as the P&A work is completed.

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

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
U.S. | $ | 297,162 |  |  | $ | 271,260 |  |  | $ | 283,933 |
U.K. | 193,903 |  |  | 194,434 |  |  | 155,954 |
Brazil | 216,796 |  |  | 208,054 |  |  | 70,710 |
Other | 44,048 |  |  | 66,070 |  |  | 70,786 |
Total | $ | 751,909 |  |  | $ | 739,818 |  |  | $ | 581,383 |

Our operational assets work throughout the year 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 (in thousands):

| December 31,
| 2019 |  | 2018
U.S. | $ | 808,683 |  |  | $ | 862,334 |
U.K. (1) | 782,246 |  |  | 236,512 |
Brazil | 281,698 |  |  | 324,083 |
Singapore (2) | 10 |  |  | 403,816 |
Total | $ | 1,872,637 |  |  | $ | 1,826,745 |

(1) | Includes certain assets that are based in the U.K. but may operate in the North Sea and West Africa regions, including the Q7000 that was delivered to us in November 2019.

(2) | Amount in 2018 primarily included the Q7000 vessel previously under completion at the shipyard in Singapore.

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,
| 2019 |  | 2018
Well Intervention | $ | 2,180,180 |  |  | $ | 1,916,638 |
Robotics | 151,478 |  |  | 147,602 |
Production Facilities | 142,624 |  |  | 120,845 |
Corporate and other | 122,449 |  |  | 162,645 |
Total | $ | 2,596,731 |  |  | $ | 2,347,730 |

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Note 16 — Asset Retirement Obligations
The following table describes the changes in our AROs (both current and long-term) (in thousands):

AROs at January 1, 2019 | $ | — |
Liability incurred during the period (1) | 53,294 |
Liability settled during the period | (28,296 | )
Revisions in estimated cash flows | 822 |
Accretion expense | 2,438 |
AROs at December 31, 2019 | $ | 28,258 |

(1) | In connection with the acquisition in January 2019 of certain assets associated with the Droshky Prospect (Notes 1 and 8), we assumed the AROs for the required P&A of those assets in exchange for agreed-upon amounts to be paid by Marathon Oil as the P&A work is completed. We initially recognized $53.3 million of ARO liability, $50.8 million of receivables and $2.5 million of acquired property for this transaction.

Note 17 — Commitments and Contingencies and Other Matters
Commitments Related to Our Fleet
We have long-term charter agreements with Siem Offshore AS (“Siem”) for the Siem Helix 1 and Siem Helix 2 vessels 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. We have long-term charter agreements for the Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The charter agreements expire in April 2021 for the Grand Canyon II and in May 2023 for the Grand Canyon III. The Grand Canyon charter terminated in November 2019.
In September 2013, we executed a contract for the construction of the Q7000, a newbuild semi-submersible well intervention vessel built to U.K. North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% was paid upon the delivery of the vessel in November 2019. At December 31, 2019, our total investment in the Q7000 was $536.4 million, including $346.0 million of installment payments to the shipyard. With the delivery of the Q7000, all significant capital commitments have been completed. The vessel commenced operations in Nigeria in January 2020.
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.
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Note 18 — Statement of Cash Flow Information
The following table provides supplemental cash flow information (in thousands):

| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Interest paid, net of interest capitalized | $ | 1,909 |  |  | $ | 7,369 |  |  | $ | 10,367 |
Income taxes paid | 8,856 |  |  | 5,705 |  |  | 6,015 |

Our non-cash investing activities include the acquisition of property and equipment for which payment has not been made. As of December 31, 2019 and 2018, these non-cash capital additions totaled $10.2 million and $9.9 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, 2019 (in thousands):

| Allowance for Uncollectible Accounts |  | Deferred Tax Asset Valuation Allowance
Balance at December 31, 2016 | $ | 1,778 |  |  | $ | 3,771 |
Additions (1) (3) | 1,206 |  |  | 2,788 |
Deductions (2) | (232 | ) |  | — |
Adjustments (4) | — |  |  | 5,778 |
Balance at December 31, 2017 | 2,752 |  |  | 12,337 |
Deductions (2) | (2,752 | ) |  | — |
Adjustments (5) | — |  |  | 5,603 |
Balance at December 31, 2018 | — |  |  | 17,940 |
Adjustments (5) | — |  |  | 691 |
Balance at December 31, 2019 | $ | — |  |  | $ | 18,631 |

(1) | The increase in allowance for uncollectible accounts primarily reflects charges associated with the provision for uncertain collection of a portion of our existing trade receivables related to our Robotics segment.

(2) | The decrease in allowance for uncollectible accounts reflects the write-offs of trade receivables that are either settled or deemed uncollectible.

(3) | The addition of a deferred tax asset valuation allowance reflects management’s view that we will not be able to fully realize our foreign tax credits available from 2015 within the carryforward period.

(4) | The increase in valuation allowance primarily reflects additional net operating losses in our Robotics segment in the U.K. for which insufficient future taxable income exists to offset the losses.

(5) | The increase in valuation allowance primarily reflects additional net operating losses in our Robotics segment in the U.K. for which insufficient future taxable income exists to offset the losses.

See Note 2 for a detailed discussion regarding our accounting policy on accounts receivable and allowance for uncollectible accounts and Note 9 for a detailed discussion of the valuation allowance related to our deferred tax assets.
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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, long-term debt and derivative instruments. 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 fair value of our derivative instruments (Note 21) reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. The fair value of our interest rate swaps is calculated as the discounted cash flows of the difference between the rate fixed by the hedging instrument and the LIBOR forward curve over the remaining term of the hedging instrument. The fair value of our foreign currency exchange contracts is calculated as the discounted cash flows of the difference between the fixed payment specified by the hedging instrument and the expected cash inflow of the forecasted transaction using a foreign currency forward curve. These modeling techniques require us to make estimations of future prices, price correlation, volatility and liquidity based on market data. The following tables provide additional information relating to those financial instruments measured at fair value on a recurring basis (in thousands):

| Fair Value at December 31, 2019 |  |  |  | Valuation Approach
| Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |
Interest rate swaps | $ | — |  |  | $ | 44 |  |  | $ | — |  |  | $ | 44 |  |  | (c)
Liabilities: |  |  |  |  |  |  |  |  |
Foreign exchange contracts — hedging instruments | — |  |  | 401 |  |  | — |  |  | 401 |  |  | (c)
Foreign exchange contracts — non-hedging instruments | — |  |  | 601 |  |  | — |  |  | 601 |  |  | (c)
Total net liability | $ | — |  |  | $ | 958 |  |  | $ | — |  |  | $ | 958 |  |  |

| Fair Value at December 31, 2018 |  |  |  | Valuation Approach
| Level 1 |  | Level 2 |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |
Interest rate swaps | $ | — |  |  | $ | 1,064 |  |  | $ | — |  |  | $ | 1,064 |  |  | (c)
Liabilities: |  |  |  |  |  |  |  |  |
Foreign exchange contracts — hedging instruments | — |  |  | 6,211 |  |  | — |  |  | 6,211 |  |  | (c)
Foreign exchange contracts — non-hedging instruments | — |  |  | 3,984 |  |  | — |  |  | 3,984 |  |  | (c)
Total net liability | $ | — |  |  | $ | 9,131 |  |  | $ | — |  |  | $ | 9,131 |  |  |

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

| December 31,
| 2019 |  | 2018
| Principal Amount (1) |  | Fair Value (2) (3) |  | Principal Amount (1) |  | Fair Value (2) (3)
Term Loan (previously scheduled to mature June 2020) | $ | — |  |  | $ | — |  |  | $ | 33,693 |  |  | $ | 33,314 |
Term Loan (matures December 2021) | 33,250 |  |  | 32,959 |  |  | — |  |  | — |
Nordea Q5000 Loan (matures April 2020) | 89,286 |  |  | 89,398 |  |  | 125,000 |  |  | 122,500 |
MARAD Debt (matures February 2027) | 63,610 |  |  | 68,643 |  |  | 70,468 |  |  | 74,406 |
2022 Notes (mature May 2022) | 125,000 |  |  | 134,225 |  |  | 125,000 |  |  | 114,298 |
2023 Notes (mature September 2023) | 125,000 |  |  | 162,188 |  |  | 125,000 |  |  | 114,688 |
Total debt | $ | 436,146 |  |  | $ | 487,413 |  |  | $ | 479,161 |  |  | $ | 459,206 |

(1) | Principal amount includes current maturities and excludes the 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 and the 2023 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the term loans, 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 and the 2023 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.

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, which are settled monthly, began in June 2015 and extend through April 2020. Our interest rate swap contracts qualify for cash flow hedge accounting treatment. Changes in the fair value of interest rate swaps are reported in accumulated OCI (net of tax). These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense.
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. Unrealized losses associated with our foreign currency exchange contracts that qualify for hedge accounting treatment are included in accumulated OCI (net of tax). These changes are subsequently reclassified into earnings when the forecasted vessel charter payments are made and recorded as cost of sales. Changes in unrealized losses associated with the foreign currency exchange contracts that are not designated as cash flow hedges are reflected in “Other income (expense), net” in the accompanying consolidated statements of operations.
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The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands):

| December 31,
| 2019 |  | 2018
| Balance Sheet Location |  | Fair Value |  | Balance Sheet Location |  | Fair Value
Asset Derivative Instruments: |  |  |  |  |  |  |
Interest rate swaps | Other current assets |  | $ | 44 |  |  | Other current assets |  | $ | 863 |
Interest rate swaps | Other assets, net |  | — |  |  | Other assets, net |  | 201 |
|  |  | $ | 44 |  |  |  |  | $ | 1,064 |
Liability Derivative Instruments: |  |  |  |  |  |
Foreign exchange contracts | Accrued liabilities |  | $ | 401 |  |  | Accrued liabilities |  | $ | 5,857 |
Foreign exchange contracts | Other non-current liabilities |  | — |  |  | Other non-current liabilities |  | 354 |
|  |  | $ | 401 |  |  |  |  | $ | 6,211 |

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

| December 31,
| 2019 |  | 2018
| Balance Sheet Location |  | Fair Value |  | Balance Sheet Location |  | Fair Value
Liability Derivative Instruments: |  |  |  |  |  |
Foreign exchange contracts | Accrued liabilities |  | $ | 601 |  |  | Accrued liabilities |  | $ | 3,454 |
Foreign exchange contracts | Other non-current liabilities |  | — |  |  | Other non-current liabilities |  | 530 |
|  |  | $ | 601 |  |  |  |  | $ | 3,984 |

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 (in thousands). We estimate that as of December 31, 2019, $0.3 million of net losses in accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.

| Unrealized Gain (Loss) Recognized in OCI
| Year Ended December 31,
| 2019 |  | 2018 |  | 2017
Foreign exchange contracts | $ | (315 | ) |  | $ | (1,453 | ) |  | $ | 2,672 |
Interest rate swaps | (365 | ) |  | 606 |  |  | 651 |
| $ | (680 | ) |  | $ | (847 | ) |  | $ | 3,323 |

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| Location of Gain (Loss) Reclassified from Accumulated OCI into Earnings |  | Gain (Loss) Reclassified from Accumulated OCI into Earnings
|  | Year Ended December 31,
|  | 2019 |  | 2018 |  | 2017
Foreign exchange contracts | Cost of sales |  | $ | (6,125 | ) |  | $ | (7,709 | ) |  | $ | (12,300 | )
Interest rate swaps | Net interest expense |  | 655 |  |  | 508 |  |  | (615 | )
|  |  | $ | (5,470 | ) |  | $ | (7,201 | ) |  | $ | (12,915 | )

The following table presents the impact that derivative instruments not designated as hedging instruments had on our consolidated statements of operations (in thousands):

| Location of Gain (Loss) Recognized in Earnings |  | Gain (Loss) Recognized in Earnings
|  | Year Ended December 31,
|  | 2019 |  | 2018 |  | 2017
Foreign exchange contracts | Other income (expense), net |  | $ | (378 | ) |  | $ | (901 | ) |  | $ | 818 |
|  |  | $ | (378 | ) |  | $ | (901 | ) |  | $ | 818 |

Note 22 — Quarterly Financial Information (Unaudited)
In addition to being affected by the timing of oil and gas company expenditures, offshore marine construction activities may fluctuate as a result of weather conditions. Historically, a substantial portion of our services has been performed during the summer and fall months. As a result, a disproportionate portion of our revenues and net income is earned during such periods. The following is a summary of consolidated quarterly financial information (in thousands, except per share amounts):

| Quarter Ended
| March 31, |  | June 30, |  | September 30, |  | December 31,
2019 |  |  |  |  |  |  |
Net revenues | $ | 166,823 |  |  | $ | 201,728 |  |  | $ | 212,609 |  |  | $ | 170,749 |
Gross profit | 16,254 |  |  | 39,934 |  |  | 55,074 |  |  | 26,576 |
Net income | 1,318 |  |  | 16,823 |  |  | 31,622 |  |  | 7,934 |
Net income attributable to common shareholders | 1,318 |  |  | 16,854 |  |  | 31,695 |  |  | 8,052 |
Basic earnings per common share | $ | 0.01 |  |  | $ | 0.11 |  |  | $ | 0.21 |  |  | $ | 0.05 |
Diluted earnings per common share | $ | 0.01 |  |  | $ | 0.11 |  |  | $ | 0.21 |  |  | $ | 0.05 |

2018 |  |  |  |  |  |  |
Net revenues | $ | 164,262 |  |  | $ | 204,625 |  |  | $ | 212,575 |  |  | $ | 158,356 |
Gross profit | 12,983 |  |  | 42,897 |  |  | 51,993 |  |  | 13,811 |
Net income (loss) | (2,560 | ) |  | 17,784 |  |  | 27,121 |  |  | (13,747 | )
Net income (loss) attributable to common shareholders | (2,560 | ) |  | 17,784 |  |  | 27,121 |  |  | (13,747 | )
Basic earnings (loss) per common share | $ | (0.02 | ) |  | $ | 0.12 |  |  | $ | 0.18 |  |  | $ | (0.09 | )
Diluted earnings (loss) per common share | $ | (0.02 | ) |  | $ | 0.12 |  |  | $ | 0.18 |  |  | $ | (0.09 | )

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
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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, 2019 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, 2019. 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, 2019, our internal control over financial reporting was effective.
The effectiveness of our internal control over financial reporting as of December 31, 2019 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in its report which appears in Item 8 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 2019 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Except as set forth below, the information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Exchange Act in connection with our 2020 Annual Meeting of Shareholders to be held on May 20, 2020. See also “Executive Officers of the Company” appearing in Part I of this Annual Report.
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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. Interested parties may also request a free copy of these documents from:
Helix Energy Solutions Group, Inc.
ATTN: Corporate Secretary
3505 W. Sam Houston Parkway N., Suite 400
Houston, Texas 77043
Item 11. Executive Compensation
The information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Exchange Act in connection with our 2020 Annual Meeting of Shareholders to be held on May 20, 2020.
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 2020 Annual Meeting of Shareholders to be held on May 20, 2020.
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 2020 Annual Meeting of Shareholders to be held on May 20, 2020.
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 2020 Annual Meeting of Shareholders to be held on May 20, 2020.
PART IV
Item 15. Exhibits and Financial Statement Schedules
(1) Financial Statements
The following financial statements included on pages 42 through 82 in this Annual Report are for the fiscal year ended December 31, 2019.

• | 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, 2019 and 2018

• | Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017

• | Consolidated Statements of Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017

• | Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017

• | Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017

• | 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.
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(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.

Exhibits |  | 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. |  | Filed Herewith
4.2 |  | Form of Common Stock certificate. |  | Exhibit 4.7 to the Form 8-A filed on June 30, 2006 (001-32936)
4.3 |  | Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of August 16, 2000. |  | Exhibit 4.4 to the 2001 Form 10-K filed on March 28, 2002 (000-22739)
4.4 |  | Amendment No. 1 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of January 25, 2002. |  | Exhibit 4.9 to the 2002 Form 10-K/A filed on April 8, 2003 (000-22739)
4.5 |  | Amendment No. 2 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of November 15, 2002. |  | Exhibit 4.4 to the Form S-3 filed on February 26, 2003 (333-103451)
4.6 |  | Amendment No. 3 Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of July 31, 2003. |  | Exhibit 4.12 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.7 |  | Amendment No. 4 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of December 15, 2004. |  | Exhibit 4.13 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.8 |  | Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.9 |  | Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.2 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.10 |  | Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.3 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.11 |  | Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.4 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.12 |  | Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.13 |  | Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027. |  | Exhibit A to Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.14 |  | Form of Third Amended and Restated Promissory Note to United States of America. |  | Exhibit 4.7 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.15 |  | Indenture dated as of March 12, 2012 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 March 12, 2012 (001-32936)
4.16 |  | 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)
4.17 |  | Amendment No. 1 to the Credit Agreement, dated as of May 13, 2015, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on May 14, 2015 (001-32936)
4.18 |  | 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)
4.19 |  | 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)
4.20 |  | 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)
4.21 |  | 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)
4.22 |  | 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)
4.23 |  | 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 |  | Senior Debt Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
4.25 |  | 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)
4.26 |  | 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)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
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 Performance Share Unit Award Agreement. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on December 13, 2019 (001-32936)
10.5 * |  | Form of Restricted Stock Award Agreement. |  | Exhibit 10.3 to the Current Report on Form 8-K filed on December 15, 2011 (001-32936)
10.6 * |  | 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)
10.7 * |  | 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)
10.8 * |  | 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)
10.9 * |  | 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)
10.10 * |  | 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)
10.11 * |  | Employment Agreement between Anthony Tripodo and the Company dated June 25, 2008. |  | Exhibit 10.2 to the Current Report on Form 8-K filed on June 30, 2008 (001-32936)
10.12 * |  | First Amendment to Employment Agreement between Anthony Tripodo and the Company dated November 17, 2008. |  | Exhibit 10.5 to the Current Report on Form 8-K filed on November 19, 2008 (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 * |  | 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 5, 2017 (001-32936)
10.16 * |  | Employment Agreement by and between Helix Energy Solutions Group, Inc. and Ken Neikirk dated May 1, 2019. |  | Exhibit 10.2 to the Quarterly Report on Form 10-Q filed on July 26, 2019 (001-32936)
10.17 |  | 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)
10.18 |  | 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)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.19 |  | 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)
10.20 |  | 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)
10.21 |  | 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)
10.22 |  | 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)
10.23 |  | 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. |  | Exhibit 14.1 to the Annual Report on Form 10-K filed on February 23, 2018
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. |  | Filed herewith
101.SCH |  | XBRL Schema Document. |  | Filed herewith
101.CAL |  | XBRL Calculation Linkbase Document. |  | Filed herewith
101.DEF |  | XBRL Definition Linkbase Document. |  | Filed herewith
101.LAB |  | XBRL Label Linkbase Document. |  | Filed herewith
101.PRE |  | XBRL Presentation Linkbase Document. |  | Filed herewith
104 |  | Cover Page Interactive Data File (embedded within the Inline XBRL document). |  | Contained in Exhibit 101

* | Management contracts or compensatory plans or arrangements

Item 16. Form 10-K Summary
None.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

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

February 27, 2020
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature |  | Title |  | Date
/s/ OWEN KRATZ |  | President, Chief Executive Officer and Director (principal executive officer) |  | February 27, 2020
Owen Kratz |  |  |
/s/ ERIK STAFFELDT |  | Executive Vice President and Chief Financial Officer (principal financial officer and principal accounting officer) |  | February 27, 2020
Erik Staffeldt |  |  |
/s/ AMERINO GATTI |  | Director |  | February 27, 2020
Amerino Gatti |  |  |
/s/ JOHN V. LOVOI |  | Director |  | February 27, 2020
John V. Lovoi |  |  |
/s/ AMY H. NELSON |  | Director |  | February 27, 2020
Amy H. Nelson |  |  |
/s/ NANCY K. QUINN |  | Director |  | February 27, 2020
Nancy K. Quinn |  |  |
/s/ JAN A. RASK |  | Director |  | February 27, 2020
Jan A. Rask |  |  |
/s/ WILLIAM L. TRANSIER |  | Director |  | February 27, 2020
William L. Transier |  |  |
/s/ JAMES A. WATT |  | Director |  | February 27, 2020
James A. Watt |  |  |

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