UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
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þ☑ | | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the fiscal year ended December 31, 20182020
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¨☐ | | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from__________ to__________
Commission File Numberfile number 001-32936
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
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Minnesota (
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| State or other jurisdiction of incorporation or organization) organization | | 95–3409686
(I.R.S. Employer Identification No.) |
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3505 West Sam Houston Parkway North | | |
| Suite 400 | | |
| Houston | Texas | | 77043 |
| (Address of principal executive offices) | |
77043
(Zip Code) |
(281) 618-0400
(Registrant’s telephone number, including area code)code(281) 618-0400
Securities registered pursuant to Section 12(b) of the Act:
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| Title of each class | | Trading Symbol(s) | | Name of each exchange on which registered |
Common Stock (no par value) | | HLX | | New York Stock Exchange |
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. þ☑ 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 þ☑ 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. þ☑ 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). þ☑ Yes ¨☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
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.
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Large accelerated filerþ | ☐ | Accelerated filer | ☑ | Accelerated filer ¨
| Non-accelerated filer ¨☐ | Smaller reporting company¨ | ☐ | Emerging growth company¨ | ☐ |
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). ¨☐ Yes þ☑ No
The aggregate market value of the sharesvoting and non-voting common equity held by non-affiliates of the registrant as of June 30, 20182020 was approximately $1.0 billion.$490.8 million.
The number of shares of the registrant’s common stock outstanding as of February 15, 201919, 2021 was 148,785,311.150,714,706.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 15, 201919, 2021 are incorporated by reference into Part III hereof.
HELIX ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K
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| PART I |
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| PART II |
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| PART III |
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| PART IV |
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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 and beliefs concerningor 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.amended (the “Exchange Act”). All statements included herein or incorporated herein 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.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 orand 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, capital expenditures or other financial items;
•statements regarding our backlog and long-termcommercial 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 ongoing COVID-19 pandemic and oil price volatility, and their respective effects and results, our protocols and plans, the continuation of our current backlog, the spot market, our spending and cost reduction plans and our ability to manage changes;
•statements regarding the acquisition, construction, completion, upgrades to or maintenance of vessels, systems or equipment and any anticipated costs or downtime related thereto, including the construction of our Q7000 vessel;
thereto;•statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;transactions or arrangements;
•statements regarding anticipatedpotential legislative, governmental, regulatory, administrative or other public body actions, requirements, permits or decisions;
•statements regarding our trade receivables and their collectability;
•statements regarding anticipatedpotential developments, industry trends, performance or industry ranking;
•statements regarding global, market or investor sentiment with respect to fossil fuels;
•statements regarding our expansion into the offshore renewable energy market;
•statements regarding general economic or political conditions, whether international, national or in the regional andor 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 bediffer materially different from those in the forward-looking statements. These factors include:
•the results and effects of the ongoing COVID-19 pandemic and actions by governments, customers, suppliers and partners with respect thereto;
•the impact of domestic and global economic conditions and the future impact of such conditions on the oiloffshore energy industry and gas industry;the demand for our services;
•the general impact of oil and gas price fluctuationsvolatility and the cyclical nature of the oil and gas industry;market;
•the impact of any potential cancellation, deferral or modification of our work or contracts by our customers;
•the ability to effectively bid, renew and perform our contracts;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 new assets for our well intervention and robotics fleet;assets;
•the effects of our indebtedness, our ability to comply with debt covenants and our ability to reduce capital commitments;
•the results of our continuing efforts to control costs and improve performance;
•the success of our risk management activities;
•the effects of competition;
•the availability of capital (including any financing) to fund our business strategy and/or operations;
•the impact of current and future laws and governmental regulations including tax and accounting developments, such as how they will be interpreted or enforced;
•the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”);
thefuture impact of the vote in the U.K. to’s exit from the European Union (the “EU”), known as Brexit, and related trade agreements between the U.K. and the EU on our business, operations and financial condition, which is unknown at this time;condition;
•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 discusseddescribed in “Risk Factors” beginning on page 1416 and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” beginning on page 34 of this Annual Report. AllShould 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 attributablestatements.
We caution you not to us or persons actingplace undue reliance on our behalf are expressly qualified in their entirety by these risk factors.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, express or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue. We urge you to carefully review and consider the disclosures made in this Annual Report and our reports filed with the Securities and Exchange Commission (“SEC”) and incorporated by reference herein that attempt to advise interested parties of the risks and factors that may affect our business. Please see “Website and Other Available Information” for further details.
PART I
Item 1. Business
OVERVIEW
Helix Energy Solutions Group, Inc. (together with its subsidiaries, unless context requires otherwise, “Helix,” the “Company,” “we,” “us” or “our”) was incorporated in 1979 and in 1983 was re-incorporated in the state of Minnesota. We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We seek to provideTraditionally, our services and methodologies thathave covered the lifecycle of an offshore oil or gas field. In recent years, we believe are critical to maximizing production economics.have seen an increasing demand for our services from the offshore renewable energy market. We provide services primarily in deepwater in the U.S. 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 elsewhere 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 2018.2020. 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 1315 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. FinancialStatements and Supplementary Data located elsewhere in this Annual Report.
OUR STRATEGY
Our focus is on our well intervention and robotics businesses. We believe that focusing on these services will deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. We expect our well intervention fleet to expand with the completion and delivery in 2019 of the Q7000, a newbuild semi-submersible vessel. Chartering newer vessels with additional capabilities, such as the three Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit from our fixed fee agreement for the Helix Producer I (the “HP I”), a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator until at least June 1, 2023.
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’ strategic alliance 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. We and OneSubsea jointly developed a 15,000 working p.s.i. intervention riser system
(“15K IRS”), each owning a 50% interest. The 15K IRS was completed and placed into service in January 2018. Our total investment in the 15K IRS was approximately $17 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $6 million for our 50% interest. At December 31, 2018, our total investment in the ROAM was $5.6 million. The ROAM is expected to be available in 2019.
OUR OPERATIONS
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. We provide a full range of services to the oil and gas and renewable energy markets primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our Well Intervention segment includes our vessels andand/or equipment used to performaccess offshore wells for the purpose of performing well intervention services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa.enhancement or decommissioning operations. Our well intervention vessels include the Q4000, the Q5000, the SeawellQ7000, the Seawell, the Well Enhancer, and two chartered monohull vessels, the Siem Helix1 and the Siem Helix2. We also have a semi-submersible well intervention vessel under completion, the Q7000. Our well intervention equipment includes intervention riser systems (“IRSs”), subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module (“ROAM”), some of which we provide on a stand-alone basis, and subsea intervention lubricators (“SILs”).basis. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills,a ROVDrill, which are designed to complement offshore construction and well intervention services and three ROVoffshore construction to both the oil and gas and the renewable energy markets globally. Our Robotics segment also includes two robotics support vessels under long-term charter:charter, the Grand Canyon, the Grand Canyon II andthe Grand Canyon III., as well as spot vessels as needed. 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”) and our investment in Independence Hub, LLC (“Independence Hub”).ownership of oil and gas properties. All of our production facilitiescurrent Production Facilities activities are located in the Gulf of Mexico. See Note 1315 for financial results related to our business segments.
Our current servicesServices we currently offer to the offshore oil and gas market worldwide include:
Production. Well intervention; intervention engineering; production enhancement; inspection, repair and maintenance of production structures, trees, jumpers, risers, pipelines and subsea equipment; and life of field support.
Decommissioning. Reclamation and remediation services; well plugging and abandonment 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 alternative energy industry. Some
•Production. Well intervention; intervention engineering; production enhancement; inspection, repair and maintenance of production structures, trees, jumpers, risers, pipelines and subsea equipment; and related support services.
•Decommissioning. Reclamation and remediation services; well plug and abandonment (“P&A”) services; pipeline abandonment services; and site inspections.
•Production Facilities. Provision of the services that we provide to these alternative 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.facility. Currently, the HP I is being utilized to process production from the Phoenix field.
field in the Gulf of Mexico.•Fast Response System. Provision of the HFRS as a response resource in the Gulf of Mexico that can be identified in permit applications to U.S. federal and state agencies and respond to a well control incident.
Services we currently offer to the offshore renewable energy market worldwide include:
•Site Clearance. Site preparation for construction of offshore wind farms, underwater unexploded ordnance identification and disposal and boulder relocation.
•Trenching. Cable protection via jetting and/or cutting by self-propelled trenching ROVs.
•Subsea Support. General subsea support of engineering, procurement, construction and installation contractors with ROV services standalone or with support vessels.
Well Intervention
We engineer, manage and conduct well construction, 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 conduct operations indevelop deepwater reserves, we expect the deepwater basins of the world, development of these reserves will often require the installationnumber of subsea trees. Over time, we expecttrees to increase, which can improve long-term demand for well intervention services to increase due to the growing number of subsea tree installations.services. Historically, drilling rigs were typically necessary forused 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 historicallygenerally have been less than those of offshore drilling rigs. CompetitiveOur vessels derive competitive advantages of our vessels are derived from their lower operating costs, together 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. TheseOur services provide a cost advantage in the development and management of subsea reservoirs. We expect demand for our services to increase due to potentialbelieve we offer efficiency gains from our specialized intervention assets and equipment.assets.
Our well intervention business currently operates sixseven vessels and various equipment such as IRSs, SILs and the ROAM, providing services primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa.
The Q4000 has worked as a rigless riser-based intervention vessel in increasingly deeper water inIn the Gulf of Mexico.Mexico, the Q4000, a riser-based semi-submersible well intervention vessel, has been serving customers in the spot market since 2002. In 2010, the Q4000 served as a key emergency response vessel in the Macondo well control and containment efforts. The Q4000 also serves an important role in the HFRS that was originally established in 2011. Our Q5000 riser-based semi-submersible well intervention vessel commenced operations in the Gulf of Mexico in late 2015. The vessel went on contracted rates in May 20162015 and is under oura five-year contract with BP.BP expiring in the first half of 2021.
In Brazil, we provide well intervention services to Petróleo Brasileiro S.A. (“Petrobras”) with two monohullthe Siem Helix1 and Siem Helix2 vessels the Siem Helix1 and the Siem Helix2, that we charter from Siem Offshore AS (“Siem”). The initial term of the agreements with Petrobras is for four years, from commencement of operations with options to extend by agreement of both parties for an additional period of up to four years. The Siem Helix1 commenced operations for Petrobras in mid-AprilApril 2017 and the Siem Helix2 commenced operations for Petrobras in mid-DecemberDecember 2017. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates 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. Our North Sea well intervention fleet also performs services in West Africa from time to time.
We currently haveThe Q7000, a newbuild semi-submersible well intervention vessel under completion, the Q7000. The vessel is built to U.K. North Sea standards. Pursuantstandards and capable of working globally, commenced operations in January 2020 and is currently performing integrated well intervention operations offshore Nigeria.
Our alliance with Schlumberger leverages the parties’ capabilities to the shipyard contractprovide a unique, fully integrated offering to clients, combining marine support with well access and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in each of 2016, 2017control technologies. Through our alliance, we and 2018,Schlumberger jointly developed a 15K IRS and the remaining 20% will be paid upon the delivery of the vessel,ROAM, which at our option can be deferred until December31, 2019.are currently available to customers.
Robotics
We have been actively engaged in robotics for over three decades. We operate ROVs, trenchers and ROVDrills designed forrobotics assets to complement offshore construction, maintenance and well intervention services for the oil and gas market and to support offshore renewable energy projects for the renewable energy market. We often integrate theseour services with chartered vessels. As global marine construction support operates in deeper waters, the use and scope of ROV services has expanded. Our chartered vessels add value by supporting deployment of our ROVs and trenchers. We provide our customers with vessel availability and schedule flexibility to meet the technological challenges of their subsea activities worldwide. Our robotics assets include 46 ROVs, five trenching systems and one ROVDrill. Our robotics business unit primarily operates in the Gulf of Mexico, North Sea, West Africa and Asia Pacific regions. As global marine construction activity levels increase and as the complexity and water depths of the facilities increase, the use and scope of robotics services has expanded. Our robotics assets and experience, coupled with our chartered vessel fleet and schedule flexibility, allow us to meet the technological challenges of our customers’ subsea activities worldwide. As of December 31, 2020, our robotics assets included 44 ROVs, four trenchers and one ROVDrill. We charter vessels on a long-term or a spot basis to support deployment of our robotics operations. We also engage spot vessels on short-term charter agreements as needed. Vessels currently under long-term charter agreements include the Grand Canyon, the Grand Canyon II and the Grand Canyon III. We returned the Deep Cygnus to its owner during the first quarter of 2018.assets.
Over the last decade and especially in recent years there has been an increase in offshore activity associated with the growing alternative (renewable)renewable energy industry. Specifically there has been an increase in demand for services to support the offshore wind farm industry.market. As the level of activity for offshore alternativerenewable energy projects, including wind farm projects, has increased, so has the need for reliable services and related equipment. Historically, this work was performed with the use ofby barges and other similar vessels, but these types of services are nowincreasingly being contracted to vessels such as our Grand Canyon and Grand Canyon III chartered vessels that aremore 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 2018,2020, revenues derived from offshore renewablesrenewable energy contracts accounted for 33%41% of our global roboticsRobotics segment revenues. We believe that over the long term our robotics business unit is positioned to continue theproviding services it provides to a range of clients in the alternativerenewable energy industry. This is expected to include the use of our chartered vessels, ROVs and trenchers to provide burial services relating to subsea power cable installations on key wind farm developments.market.
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 (“MMcf”) 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 located in 8,000 feet of water in the eastern Gulf of Mexico.
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 centers on our vessels currently operating incombines the Gulf of Mexico, the HP I, the Q4000 and the Q5000, combining them with certain well control equipment that can be deployed to respond to a well control incident. On January 16, 2019, we renewed the agreements that provideWe are under agreement through September 30, 2021 with various operators withto provide access to the HFRS for well control purposes through March 31, 2020. These agreements automatically renew on an annual basis absent proper notice of termination by one of the parties.purposes.
On January 18, 2019, we purchasedOur Production Facilities segment includes two remaining wells acquired from Marathon Oil Corporation (“Marathon Oil”) certain operating depthsin January 2019. These oil and gas properties are associated with the Droshky Prospect onlocated in offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure.244. As part of the transaction, Marathon Oil willagreed to pay us certain agreed upon amounts foras we complete the required plug and abandonment of the acquired assets, which we can perform as our schedules permit subject to regulatory timelines.P&A work.
GEOGRAPHIC AREAS
We primarily operate in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. Our North Sea operations are subject to seasonal changes in demand, which generally peaks in the summer months and declines in the winter months. See Note 1315 for revenues as well as property and equipment net of accumulated depreciation, by geographic location.
CUSTOMERS
Our customers includeconsist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, alternative (renewable)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, customersa customer that accountaccounts 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 whose total represented(those representing 10% or more of our consolidated revenues isrevenues) are as follows: 2020 — Petrobras (28%) and BP (17%); 2019 — Petrobras (29%), BP (15%) and Shell (13%); and 2018 — Petrobras (28%) and BP (15%), 2017 — BP (19%), Petrobras (13%) and Talos (10%), and 2016 — BP (17%) and Shell (11%). We provided services to over 50 customers in 2018.2020.
COMPETITIONCOMPETITORS
The oilfield services industry isand renewable energy services markets are highly competitive. While price is a factor,Price and the ability to access specialized vessels, attract and retain skilled personnel, and demonstrate a good safety record is alsooperate safely are important factors to competing in the industry.these markets. Our principal competitors in the well intervention business include Island Offshore Subsea AS, Wild Well Control,Baker Hughes, C-Innovation, Expro, Oceaneering, International, Inc., Expro GroupTIOS and international drilling contractors. Our principal competitors in the robotics business include C-Innovation, LLC, DeepOcean, Group, DOF Subsea, Group, Fugro, N.V.Oceaneering and Oceaneering International, Inc.ROVOP. Our principal competitors in renewable energy services include UTROV, Briggs Marine, James Fisher and Atlantic Marine. Our competitors may have significantly more or differing financial, personnel, technological and other resources available to them.
TRAINING, SAFETY, HEALTH, ENVIRONMENT
ENVIRONMENTAL, SOCIAL AND QUALITY ASSURANCEGOVERNANCE
We continue to implement and improve Environmental, Social and Governance (“ESG”) initiatives and disclosures throughout our business. We understand we have an important role to play as a steward of the people, communities and environments we serve, and we regularly look for ways to emphasize and improve our own ESG record. We incorporate ESG initiatives into our core business values and priorities of safety, sustainability and value creation with a top-down approach led by management and our Board of Directors (our “Board”). Specifically, the Corporate Governance and Nominating Committee of our Board oversees, assesses and reviews the disclosure and reporting of any matters, including with respect to climate change, regarding the Company’s business and industry, and that committee's charter formally incorporates oversight of ESG matters as a stated responsibility.
We emphasize constant improvement by continually striving to improve our safety record, reducing our environmental impact, and increasing transparency. In 2020, we maintained a low Total Recordable Incident Rate and expanded our business with renewable energy customers. Our efforts are published in our Corporate Sustainability Report and Corporate Sustainability Summary Update, copies of which are available on our website at www.HelixESG.com/about-helix/corporate-sustainability.
HUMAN CAPITAL RESOURCES
Labor Practices
As of December 31, 2020, we had 1,536 employees. Of our total employees, we had 336 non-U.S. employees covered by collective bargaining agreements or similar arrangements. We consider our overall relationships with our employees to be satisfactory. Further, we expect all employees to maintain a work environment free from harassment, discrimination and abuse, and one where employees treat each other with respect, dignity and courtesy.
Anti-Slavery and Anti-Human Trafficking
We are committed to ensuring that there is no modern slavery or human trafficking in our supply chains or in any part of our business. Our workplace policies and procedures demonstrate our commitment to acting ethically and with integrity in all our business relationships, and to implementing and enforcing effective systems and controls to prevent slavery and human trafficking from taking place anywhere in our supply chains. In 2020, we implemented Anti-Human Trafficking training for employees to further arm our workforce with the tools to spot and prevent human trafficking. Our Modern Slavery Statement is available on our website, located at https://www.helixesg.com/modern-slavery-statement.
Employee Health and Safety
Our corporate vision of a zero incidentzero-incident workplace is based on the belief that all incidents should beare preventable and that we can adjustmanage our working conditions to drive safer behaviors. Helix strives to achieve this by focusing on controlling major hazard risks and managingeliminate unsafe behavior. We have established a corporate culture in which QHSE has equaltakes priority toover our other business objectives. Should QHSE be in conflict with business objectives, then QHSE will take priority. Everyone at Helix has the authority and the duty to “STOP WORK” they believe is unsafe.
Helix management actively encourages critical safety behaviors and employees to work in compliance with our goals to avoid injuries to people, environmental disturbances and damage to assets. Our QHSE management systems and training programs were developed by management personnel based on common industry work practices, and by employees with on-site experience who understand the risk and physical challenges of the oceanoffshore work site. As a result, we believe that our QHSE programs are among the best in the industry. We maintain a company-wide effort to continuously improve our control of QHSE risks and the behavior of our employees.
The process includes the assessment of risk through the use of selected risk analysis tools, control of work through management system procedures, job risk assessment of all routine and non-routine tasks, documentation of all daily observations, collection of data and data treatment to provide the mechanism for understanding our QHSE risks and at-risk behaviors. In addition, we schedule hazard hunts on each vessel and regularly audit QHSE management systems; both are completed with assigned responsibilities and action due dates.
environment. The management systems of our business units have been independently assessed and registered compliant towith ISO 9001 (Quality Management Systems) and ISO 14001 (Environmental Management Systems). All of ourOur safety management systems arewere created in accordance with and conform to OHSAS 18001.
Health and Safety during COVID-19
The nature of offshore operations requires our offshore crew members as well as our customers and vendors to periodically travel to and from vessels. The ongoing COVID-19 pandemic has introduced challenges unlike any we have ever seen, and while we like everyone else have not been immune to the impact of the pandemic, our personnel have risen to the occasion. We implemented numerous health and safety protocols in response to the pandemic, including personnel isolation and health screenings prior to travel and crew changes, a rigorous testing regime for all offshore personnel, limiting or altogether eliminating certain common areas aboard our vessels, mandatory face coverings, social distancing, extending the duration of certain offshore shifts to reduce travel and turnover, deep cleanings of our onshore facilities and offshore assets, and immediate quarantine and definitive response protocols in the event any personnel are showing or reporting any potential symptoms. With these measures in place to protect our personnel, those partners with whom we work and their collective families, we have thus far managed to avoid major operational downtime related to the pandemic.
Employee Engagement, Diversity and Inclusion
Employee Tenure and Turnover
We track tenure and voluntary employee turnover. We then use this data to develop our human capital strategy. In 2020, 56% of our workforce had been with the Company for five years or longer, and our global voluntary turnover rate was 4.3%. While these numbers provide valuable insight, the context surrounding these numbers provide an even clearer picture into our global workforce. In April and December 2017, respectively, the Siem Helix1 and the Siem Helix2 commenced operations in Brazil. The commencement of operations required the employment and new hire of sufficient quantities of individuals to man those vessels. In November 2019, we took delivery of the Q7000. The mobilization of the Q7000 again required the hiring and employment of additional employees. Over the past four years, we have commenced operations with three new vessels, which directly impacts the tenure percentages above and skews a greater number of employees into the zero-to-four years category.
Training, Engagement and Improvement
We recognize that we must train our staff in order to be as prepared as possible to perform our operations safely. Our staff receives up to date and relevant training required for their jobs, and Helix leadership actively engages staff so that behaviors reflect the training and critical safety approach we all desire. The initial vessel orientation for new hires is the first of many steps in shaping those behaviors. Each vessel and shore-based employee is assigned a Qualifications and Training Matrix that specifies the qualifications and training that an employee is required to have for the applicable position. All training is tracked annually and evaluated to confirm the quality of training. Ongoing and thoughtful employee participation is a vital element in the success of our QHSE process. While we believe in the strength and effectiveness of our QHSE programs, we continuously look at how we can improve our control of QHSE risks through the behavior and feedback of our employees.
Diversity and Inclusion
We are committed to diversity and inclusion throughout our workforce. In 2020, our worldwide workforce represented 28 different nationalities. Our hiring managers and human resources departments in all regions partner to find the best candidates without regard to factors such as race, religion, color, national origin, age, sex, gender, sexual orientation, gender identity, disability, marital status, veteran status, genetic information or any other basis that would be in violation of any applicable federal, state, local or international law. Employing people with different backgrounds, experiences and perspectives makes Helix a stronger business. We are committed to attracting and retaining high-performing employees through this diverse talent base and evaluating and promoting throughout our organization based on skills and performance.
GOVERNMENT REGULATION
Overview
We provide services primarily in deepwater in the U.S. 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. InBeginning in 2019 we acquired fouroperate end of life offshore oil and gas wells, twosome of which are currently producing and which we willplan to ultimately decommission. Being an operator of these wells subjects us to additional regulatory oversight from the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”).
International Conventions
Our vessels are subject to applicable international maritime convention requirements, which include, but are not limited to, the International Convention for the Prevention of Pollution from Ships (“MARPOL”), the International Convention on Civil Liability for Oil Pollution Damage of 1969, the International Convention on Civil Liability for Bunker Oil Pollution Damage of 2001 (ratified in 2008), the International Convention for the Safety of Life at Sea of 1974 (“SOLAS”), the International Safety Management Code for the Safe Operation of Ships and for Pollution Prevention (the “ISM Code”), the Code for the Construction and Equipment of Mobile Offshore Drilling Units (the “MODU Code”), and the International Convention for the Control and Management of Ships’ Ballast Water and Sediments (the “BWM Convention”). These regimes are applicable in most countries where we operate; however, the 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,(BOEM, BSEE and the Office of Natural Resource Revenue,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 weWe provide services globally and generally can be subject to local laws and regulations wherever we operate, theoperate. Those laws and regulations generally govern environmental, labor, health and safety and other matters. The regulatory regimes of the U.K. and Brazil are of particular importance given the locations of our current operations. The U.K. Continental Shelf in the North Sea is regulated by the Oil and Gas Authority (the “OGA”) in accordance with the Petroleum Act 1998. The OGA controls 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 2016 decision to 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 toand 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 where thein 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, MARPOL, 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 applicable 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 vessel and other marine casualty incidents, recommend improved safety standards, and inspect vessels at will. We also adhere to manning requirements implemented by the Coast Guard for operations on the U.S. Outer Continental Shelf (“OCS”).
Local Content Requirements and Cabotage Rules
We are subject to local content requirements with respect to equipment and crews utilized in certain of our operations. Governments in some countries, notably in Brazil and in the West Africa region, have become increasingly active in establishing and enforcing such requirements along with other aspects of the energy industries in their respective countries.
A number of jurisdictions where we operate require that certain work performed there 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 offshore energy industry in general. The operation of oil and gas properties located on the OCS is regulated primarily by BOEM and BSEE. Among other requirements, BOEM requires lessees of OCS properties to post bonds or provide other adequate financial assurance in connection with the plugging and abandonmentP&A of wells located offshore and the removal of all production facilities. 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. Following the Deepwater Horizon incident in April 2010, BSEE determined and 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 provides guidance for the design and operation of remotely operated tools. OnIn May 11, 2018,2019, BSEE proposed to further revise the
released revised regulations for well control and blowout preventer systems in responsedesigned to Executive and Secretarial Orders directing BSEE to reviewimprove operations on the OCS. The regulations that potentially burden development or use of domestically produced energy resources. The proposed rule would revise requirements for well design, well control, casing, cementing, real time monitoring, and subsea containment. Overall, the rulemaking would modify regulations that impactaddress offshore oil and gas drilling, completions, workovers, and decommissioning activities.
Local Content Requirements
Governments in some countries, notably in Brazilactivities, and in the West Africa region,we 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.incorporated them into our operations.
Other Regulatory Impact
Additional proposals and proceedings before various international, federal and state regulatory agencies and courts could affect the oil and gasenergy industry, including curtailing production and demand for fossil fuels such as oil and natural gas.fuels. We cannot predict when or whether any such proposals may become effective.effective, or how they will be interpreted or enforced.
ENVIRONMENTAL REGULATION
Overview
Our operations are subject to a variety of national (including federal, state and local) and international laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous governmental departments issue rules and regulations to implement and enforce these laws that are often complex, costly to comply with, and carry substantial administrative, civil and possibly criminal penalties for compliance failure. There is currently little uniformity among the regulations issued by the governmentgovernmental 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,below, but thethis discussion does not cover all environmental laws and regulations that govern or otherwise affect our operations.
MARPOL
The United StatesU.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 environmental standards 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 in the U.S., and the lessee or permittee of the U.S. area in which an offshore facility is located, as well as owners and operators of vessels. Any of these entities or persons can be “responsible parties” and are strictly liable for removal costs and damages arising from facility and vessel oil spills or threatened spills. Failure to comply with OPA may result in the assessment of civil, administrative and criminal penalties. In addition, OPA requires owners and operators of vessels over 300 gross tons to provide the Coast Guard with evidence of financial responsibility to cover the cost of cleaning up oil spills from those vessels. A number of foreign jurisdictions also require us to present satisfactory evidence of financial responsibility. We satisfy these requirements through appropriate insurance coverage.
Water Pollution
For operations in the U.S., the Clean Water Act imposes controls on the discharge of pollutants into the navigable waters of the United StatesU.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 that are analogous to the Clean Water Act and also require remediation of releases of petroleum and other 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 orand 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, theThe IMO designateddesignates the waters off North America as an Emission Control Area, meaning that vessels operating in the United StatesU.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. EU Regulation 2015/757 requires monitoring and reporting of the emissions of vessels exceeding 5,000 gross tons that call at EU ports, with the first reports due in 2019. It is anticipated that in the future the EU may move from requiring reporting of emissions to regulations aimed at reducing them.
CERCLA
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) requires the remediation of releases of hazardous substances into the environment in the U.S. and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons, including owners and operators of contaminated sites where the release occurred and those companies that transport, dispose of or arrange for the disposal of, hazardous substances released at the sites.
OCSLA
The Outer Continental Shelf Lands Act, as amended (“OCSLA”), provides the federalU.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 cancellation ofcancel leases.
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 thatand we maintain and update our programs to meet or exceed applicable regulatory requirements in the areas in which we operate.requirements. We do not anticipate that compliance with existing environmental laws and regulations will have a material effect upon our capital expenditures, earnings or competitive position. However, changes in environmental laws and regulations, changes in the ways such laws and regulations are interpreted or enforced, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs or liabilities in the future. Environmental liabilityCosts or liabilities 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).economics.
Our current insurance program is valid until June 30, 2020.generally covers a 12-month period beginning July 1 each year.
We maintain Hull and Increased Value insurance, which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are $1.0$1 million on the Q4000, the Q5000, the Q7000, the HP I and the Well Enhancer, and $500,000 on the Seawell. In addition to the primary deductibles, the vessels are subject to an annual aggregate deductible of $5 million. We also carry Protection and Indemnity (“P&I”) insurance, which covers liabilities arising from the operation of the vessels, and General Liability insurance, which covers liabilities arising from construction operations. TheOur current deductible on both the P&I and General Liability is $100,000 per occurrence.occurrence and $250,000 per occurrence on the General Liability. Onshore employees are covered by Workers’ Compensation. Offshore employees and marine crews are covered by a Maritime Employers Liability (“MEL”) insurance policy, which covers Jones Act exposures and currently includes a deductible of $100,000$250,000 per occurrence plus a $750,000 annual aggregate deductible.occurrence. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability for total limits of $500 million in excess of primary limits as well as OPA insurance for our newly-acquired offshore oil and gas properties with $35 million of coverage as required by BOEM. Our self-insured retention on our medical and health benefits program for employees is $300,000 per participant.
We also maintain Operator Extra Expense coverage that provides up to $150 million of coverage per each loss occurrence for a well control issue.issue on oil and gas properties where we are the operator. Separately, we also maintain $500 million of liability insurance and $150 million of oil pollution insurance. For any given oil spill event we havemaintain 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 partythird-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 generallytypically 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 partythird-party claims associated with well control events.
We incurreceive workers’ compensation, MEL and other insurance claims in the normal course of business. We analyze each claim for its validity, potential exposure and estimate theestimated ultimate liability of each claim. We have not incurred any significant losses as a result of claims denied by our insurance carriers.liability. Our services are provided in hazardous environments where accidentsevents involving catastrophic damage or loss of life could occur, and litigationclaims arising from such an event may result in our being named as a defendant in lawsuits asserting large claims.responsible party. Although there can be no assurance the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations.
EMPLOYEES
As of December 31, 2018, we had 1,546 employees. Of our total employees, we had 409 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. From time to time, we also provide information about Helix on Twitter (@Helix ESG) and LinkedIn (www.linkedin.com/company/helix-energy-solutions-group). Copies of this Annual Report for the year ended December 31, 2018,2020, previous and subsequent copies of our Annual Reports on Form 10-K, 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 Securities and Exchange Commission (“SEC”).SEC. In addition, the Investor Relations portion“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 Investor Relations“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 throughthroughout this Annual Report:
Bureau of Ocean Energy Management (BOEM): BOEM is responsible for managing environmentally and economically responsible development of the U.S. offshore resources. Its functions include offshore leasing, resource evaluation, review and administration of oil and gas exploration and development plans, renewable energy development, National Environmental Policy Act analysis and environmental studies.
Bureau of Safety and Environmental Enforcement (BSEE): BSEE is responsible for safety and environmental oversight of U.S. offshore oil and gas operations, including permitting and inspections of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs.
Deepwater: Water depths exceeding 1,000 feet.
Dynamic Positioning (DP): Computer directed thruster systems that use satellite basedsatellite-based positioning and other positioning technologies to ensureprovide 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 within the failureabsence of one DP system.
DP3: Triple-redundant DP control system comprising a triple-redundant controller unit and three identical operator stations. The system hasis designed to withstand fire or flood in any one compartment without the system failing.compartment. Loss of position should not occur from any single failure, including a completely burnt fire subdivision or flooded watertight compartment.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 3,000 meters (9,840 feet). The system10,000 feet. An IRS can be utilized for wireline intervention, production logging, coiled-tubing operations, well stimulation, and full plug and abandonment operations. The systemoperations, and provides the well control in order to safely access the well bore for these activities.
LifePlug and Abandonment (P&A): P&A operations usually consist of Field Services: Services performed on offshore facilities, treesplacing several cement plugs in the wellbore to isolate the reservoir and pipelines from the beginning toother fluid-bearing formations when a well reaches the end of the economic life of an oil field, including installation, inspection, maintenance, repair, well intervention and abandonment.its lifetime.
QHSE: Quality, Health, Safety and Environmental programs designed to protect the environment, safeguard employee health and avoid injuries.
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.
Riserless Open-water Abandonment Module (ROAM): An 18¾-inch large bore 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 enhancesno well abandonment capabilities from a well intervention vessel.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: ROV deployed A coring system developed to take advantage of existing ROV technology. The coring package, deployed with thean ROV system is capable of taking cores from the seafloor in water depths up to 3,000 meters (9,840 feet).10,000 feet. Because the ROV system operates from the seafloor there is no need for surface drilling strings andor the larger support spreads required for conventional coring.
Saturation Diving: Saturation diving, required for work in water depths between 200 and 1,000 feet, involves diversdiving: Divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.site, required for work in water depths between 200 and 1,000 feet.
Spot Vessels: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 subsea system designed to provide access to the well bore while providing well control safety for activities that do not require a riser conduit. A SIL can be utilized for wireline, logging, light perforating, zone isolation, plug setting and removal, and decommissioning, and it facilitates access to subsea wells from a monohull vessel to provide safe, efficient and cost effective riserless well intervention and abandonment solutions. The system can be utilized for wireline, logging, light perforating, zone isolation, plug setting and removal, and decommissioning. The system provides access to the well bore while providing full well control safety for activities that do not require a riser conduit.
Tension Leg Platform (TLP): A floating production facility anchored to the seabed with tendons.
Trencher or Trencher System:trencher system: A subsea robotics system capable of providing post laypost-lay trenching, inspection and burial (PLIB) 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 Servicesintervention services: Activities related to well maintenance and production management/management and enhancement services. Our well intervention operations include the utilization of slickline and electric line services, pumping services, specialized tooling and coiled tubing services.
Item 1A. Risk Factors
Shareholders should carefully consider the following risk factors in addition to theother 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 also 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 theevents described in these risk factors and elsewhere in this Annual Report could havea material adverse effect on our business, financial position, results of operations and financialposition.cash flows.
Market and Industry Risks
The ongoing COVID-19 pandemic could continue to disrupt our operations and adversely impact our business and financial results.
In March 2020, the World Health Organization classified the outbreak of COVID-19 as a pandemic. The nature of COVID-19 led to worldwide shutdowns and halting of commercial and interpersonal activity, as governments around the world imposed regulations in efforts to control the spread of COVID-19 such as shelter-in-place orders, quarantines, executive orders and similar restrictions. As of December 31, 2020, efforts to contain COVID-19 have not succeeded in many regions, and the global pandemic remains ongoing. Furthermore, although vaccines have been identified, their efficacy and rollout pose logistical and other challenges, and new strains of coronavirus have been identified that may be more contagious, more severe, and for which vaccinations may not be effective. As a result the global economy has been marked by significant slowdown and uncertainty, which led to a precipitous decline in oil prices in response to demand concerns, as further discussed throughout these Risk Factors. These events have resulted in significantly weaker outlook for oil producers and by extension oilfield service companies, including reduced operating and capital budgets as well as market confidence in overall industry viability. We are not currently able to predict the duration or severity of the spread of COVID-19 or the responses thereto, and if economic and industry conditions do not improve, these events will continue to adversely impact our financial condition and results of operations.
The spread of COVID-19 to one or more of our locations, including our vessels, could significantly impact our operations. We have implemented various protocols for both onshore and offshore personnel in efforts to limit the impact of COVID-19, however those may not prove fully successful. The spread of COVID-19 to our onshore workforce could prevent us from supporting our offshore operations, we may experience reduced productivity as our onshore personnel work remotely, and any spread to our key management personnel may disrupt our business. Any outbreak on our vessels may result in the vessel, or some or all of a vessel crew (including customer crew), being quarantined and therefore impede the vessel's ability to generate revenue. We have experienced several instances of COVID-19 among our offshore crew, and although to date we have managed to minimize operational disruption, there can be no guarantee that will remain the case. We have experienced challenges in connection with our offshore crew changes due to health and travel restrictions related to COVID-19, and those challenges and/or restrictions may continue or worsen.
Our business is adversely affected by low oil and gas prices, which occur from time to time in a cyclical oil and gas industry.market that is currently experiencing significant volatility.
Our services are substantially dependent upon the condition of the oil and gas industry,market, and in particular, the willingness of oil and gas companies to make capital and other expenditures for offshore exploration, development, drilling and production operations. Although our services are used for other operations during the entire life cyclelifecycle 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 levelprice war among members of the Organization of Petroleum Exporting Countries (“OPEC”) and other non-OPEC producer nations (collectively with OPEC members, “OPEC+”) during the first quarter 2020 and global storage considerations significantly contributed to the slowdown and uncertainty in the global economy. The confluence of these events along with the continued impact of COVID-19 has resulted in a significantly weaker outlook for oil producers and by extension oilfield service companies, including reduced operating and capital budgets as well as market confidence in overall industry viability. We are not currently able to predict the duration or severity of the continued oil price volatility or the responses thereto, and if economic and industry conditions do not improve, these events will continue to adversely impact our financial condition and results of operations.
The levels of both capital and operating expenditures generally dependslargely depend on the prevailing view of future oil and gas prices, which areis influenced by numerous factors, including:
•worldwide economic activity and general economic and business conditions;conditions, including access to global capital and capital markets;
•the global supply and demand for oil and natural gas, especially in the United States, Europe, China and India;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”)OPEC and/or OPEC+;
•the availability and discovery rate of new oil and natural gas reserves in offshore areas;
•the exploration and production of onshore shale oil and natural gas;
•the cost of offshore exploration for and production and transportation of oil and natural gas;
•the level of excess production capacity;
•the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;
•the environmental and social sustainability of the oil and gas sector and the perception thereof, including within the investing community;
•the sale and expiration dates of offshore leases globally;
•governmental restrictions on oil and gas leases, including executive actions taken with respect to permitting in the United Statesconnection with oil and overseas;gas leases on federal land announced in January 2021;
•technological advances affecting energy exploration, production, transportation and consumption;
•potential acceleration of the development of alternative fuels;
•shifts in end-customer preferences toward fuel efficiency and the use of natural gas;gas or renewable energy alternatives;
•weather conditions, natural disasters, and natural disasters;epidemic and pandemic diseases, including the ongoing COVID-19 pandemic;
•laws, regulations and policies directly related to the industries in which we provide services, and their interpretation and enforcement;
•environmental and other governmental regulations; and
•tax laws, regulations and policies.
A prolonged period of low level of activity by offshore oil and gas operators may continue to adversely affect demand for our services, the utilization and/or rates we can achieve for our assets and services, and the outlook for our industry in general, all of which could lead to an even greater surplus of available vessels or similar assets and therefore increasingly downward pressure on the rates we can charge for our services. InGiven that our business is adversely affected by low oil prices, especially the short term,willingness of oil and gas companies to make capital and other expenditures for offshore exploration, development, drilling and production operations, the persistence of current conditions would negatively impact those companies’ willingness and ability to make those expenditures. Additionally, our customers, in reaction to negative market conditions, may continue to seek to renegotiate theirnegotiate contracts with us 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.
Business and Operational Risks
The majority of our current backlog is concentrated in a small number of long-term contracts.contracts that we may fail to renew or replace.
Although historically our service contracts were of relatively short duration, over the last severalrecent years we have been enteringentered into longer term contracts, such asincluding the five-year contract with BP for work in the U.S. Gulf of Mexico, the two four-year contracts with Petrobras contracts for well intervention services offshore Brazil and the seven-year contract for the HP I. As of December 31, 2018,2020, the BP contract, the Petrobras contracts and the contract for the HP I represented approximately 90%69% of our total backlog. Due to the value at risk, anyAny cancellation, termination or breach of those contracts would have a larger impact on our operating results and financial condition than of our shorter term contracts. The cancellationIn addition, the BP contract and the Petrobras contracts expire in 2021 and the contract for the HP I expires in 2023. Our ability to extend, renew or terminationreplace 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 the oil and gas market, we may not be able to extend, renew or unwillingnessreplace the contracts or we may be required to perform, theseextend, renew or replace expiring contracts or obtain new contracts at rates that are below our existing contract rates, or that have other terms that are less favorable to us than our existing contracts. Failure to extend, renew or replace expiring contracts or secure new contracts at comparable rates and with favorable terms could have a material adverse effect on our financial position, results of operations and cash flows.
Our current backlog for our services may not be ultimately realized for various reasons, and our contracts may be terminated early.
As of December 31, 2018,2020, backlog for our services supported by written agreements or contracts totaled $1.1 billion,$407 million, of which $470$301 million is expected to be performed in 2019.2021. 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 global or industry conditions affecting our customers and their own revenues. Some of these contracts provide for a cancellation fee that is substantially less than the expected rates from the contracts. In addition, some of our customers could experience liquidity issues or could otherwise be unable or unwilling to perform under a contract, in which case a customer may repudiate or seek to cancel or renegotiate the contract. The repudiation, or early cancellation, termination or terminationrenegotiation 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 well operationally under our contracts couldand result in reduced revenues, contractual penalties and/or ultimately, contract termination.
Our equipment and services are very technical and the offshore environment poses its own challenges. Performing the work we do pursuant to the terms of our contracts can be difficult for various reasons, including equipment failure or reduced performance, human error, third-party failure or other fault, design flaws, weather, water currents or soil conditions. In particular, our assets may experience challenges operating in new locations, presenting incremental complications; any of these factors could lead to performance concerns. The nature of offshore operations requires our offshore crew members as well as our customers and vendors to periodically travel to and from the vessels. The occurrence or threat of an epidemic or pandemic disease, including the ongoing COVID-19 pandemic and any related governmental regulations or other travel restrictions or safety measures, may impede our ability to execute such crewing or crew changes, which could lead to vessel downtime or suspension of operations, which may be beyond our control. Failure to perform in accordance with contract specifications can result in reduced rates (or zero rates), contractual penalties, and ultimately, termination in the event of sustained non-performance. For example our services and charter agreements with Petrobras provide that Petrobras can assess fines based on a percentage of our daily operating rate for certain failures of equipment, vessels or personnel, and that ultimately Petrobras has the right to terminate its agreements with us should assessed penalties reach a certain level. Reduced revenues and/or contract termination because ofdue to our inability or failure to perform operationally could have a material adverse effect on our financial position, results of operations and cash flows.
A sustained period of unfavorable industry conditions could jeopardize our customers’Our customers and other counterparties’ abilitycounterparties may be unable to perform their obligations.
Continued uncertain industry uncertainty and domestic and global economic conditions, including the financial condition of our customers, lenders, insurers and other financial institutions generally, could jeopardize the ability of certain of our counterparties, including our customers, insurers and financial institutions,such parties to perform their obligations. obligations to us, including obligations to pay amounts owed to us. In the event one or more of our customers is adversely affected by the ongoing COVID-19 pandemic or otherwise by the current market environment, our business with them may be affected. In this current uncertain environment, we may face an increased risk of customers deferring work, declining to commit to new work, asserting claims of force majeure and/or terminating contracts, or our customers’, subcontractors’ or partners’ inability to make payments or remain solvent.
Although we assess the creditworthiness of our counterparties, a prolonged periodvariety of difficult industry conditions and factors could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts. In particular, our robotics business unit tends to do business with smaller customers that may not be capitalized to the same extent as larger operators.operators and/or that may be more exposed to financial loss in an uncertain economic environment. In addition, we may offer extendedfavorable payment or other contractual terms to our 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 and contracts. If anypolicies. The inability of our significant financial institutions were unablecustomers and other counterparties to perform under these agreements and if we were unable to find suitable replacements at a reasonable cost,may materially adversely affect our business, financial position, results of operations and cash flows could be adversely impacted.flows.
TimeWe may own assets with ongoing costs that cannot be recouped if the assets are not under contract, and time chartering of vessels requires us to make ongoing payments regardless of utilization of and revenue generation from those vessels, and we may own vessels with ongoing costs that cannot be recouped if the vessels are not under contract.vessels.
Typically,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 Helix1 and Siem Helix2 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.
In addition, from time to time we may construct vessels and other assets for our fleet without first obtaining service contracts covering the cost
FleetAsset upgrade, modification, refurbishment, repair, , dry dock and construction projects, and customer contractual acceptance of new vessels and equipment, are subject to risks, including delays, cost overruns, loss of revenue and failure to commence or maintain contracts.
The Q7000, our newbuild semi-submersible well intervention vessel, is under completion at the shipyard in Singapore, and equipment for the vessel is currently being installed. We also construct or make capital improvements to other pieces of equipment (such as the 15K IRS that we jointly constructed with OneSubsea). In addition, 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. While some of these capital projects are planned, some are unplanned. Additionally, as vessels and equipmentassets age, they are more likely to be subject to higher maintenance and repair activities. These projects are subject to the many risks, ofincluding delay orand cost overruns, inherent in any large capital project.
EstimatedActual capital expenditures could materially exceed our estimated or planned capital expenditures. Moreover, our assets undergoing upgrades, modifications, refurbishment, repair or repairdry docks may not earn a day raterevenue during the period they are out of service. Any significant period of such unplanned maintenance and repairs related toactivity for our vessels and other income-producing assets could have a material adverse effect on our financial position, results of operations and cash flows.
In addition, delays in the delivery of vessels and other 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.contract terms. In the event of termination or modification of a contract due to late delivery, we may not be able to secure a replacement contract on favorable terms, if at all.
Because weall, which could have certain capital, debt and other obligations, a prolonged period of low demand and rates for our services could eventually lead to a material adverse effect on our liquidity.business, financial position, results of operations and cash flows.
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 the current industry environment, 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, capital commitments, long-term time charter contracts for our vessels and certain other commitments related to ongoing operational activities, could eventually lead to a material adverse effect on our liquidity and financial position.
We may not be able to compete successfully against current and future competitors.
The oilfield services businessindustries in which we operate isare 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.
The actual or perceived lack of sustainability of the oil and gas sector, or our failure to adequately implement and communicate ESG initiatives that demonstrate our own sustainability, may adversely affect our business.
Sustainability and ESG initiatives have become an increasingly important factor in assessing a company’s outlook, as investors look to identify factors that they believe inform a company’s ability to create long-term value. We understand we have an important role to play as a steward of the people, communities and environments we serve, and we regularly look for ways to emphasize and improve our own ESG record. However the nature of the oil and gas sector in which we predominantly operate may impact in the near or long term sustainability sentiment of investors, lenders, other industry participants and individuals, as the global markets shift towards green energy and environmental conservation. This sentiment may in turn lead to a lack of investment, investability or borrowing capital, or a more negative overall perception related to the fossil fuel industry. Further, we may not succeed in implementing or communicating an ESG message that is well understood or received. As a result we may experience diminished reputation or sentiment, reduced access to capital markets and/or increased cost of capital, an inability to attract and retain talent, and loss of customers or vendors.
Failure to protect our intellectual property or other technology may adversely affect our business.
Our indebtednessindustry is highly technical. We utilize and rely on a variety of advanced assets and other tools, such as our vessels, DP systems, IRSs, SILs, ROAM, ROVs and ROVDrill, to provide customers with services designed to meet the termstechnological 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 indebtednessIP and other proprietary information, challenges to the validity or enforceability of our or our licensors’ IP rights, and breaches of confidentiality obligations. These risks are heightened by the global nature of our business, as effective protections may be limited in certain jurisdictions. Although we endeavor to identify and protect our IP and other confidential or proprietary information as appropriate, there can be no assurance that these measures will succeed. Such a failure could impairresult in an interruption in our financial conditionoperations, increased competition, unplanned capital expenditures, and our abilityexposure tofulfill our debt obligations.
As of December 31, 2018, we had $440.3 million of consolidated indebtedness outstanding. The level of indebtedness may claims. Any such failure could have ana material adverse effect on our futurebusiness, competitive position, financial position, results of operations including:and cash flows.
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 senior secured credit facilities that place annual and aggregate limitations on the types and amounts of investments that we may make; 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 the 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.
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 less favorable terms associated with refinancing of our maturing debt. Also, we may incur increased costs and 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 fees 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 and dispose of non-core business assets.
A further decline in the offshore energy services market could result in additional impairment charges.
Prolonged periods of low utilization and day rates could result in the recognition of impairment charges for our vessels and robotics 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 in the Gulf of Mexico orNorth Sea 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. Weoperations, and we typically have experienced our lowest North Sea utilization rates in the North Sea in the first quarter. As is common in theour industry, we may bear the risk of delays caused by some adverse weather conditions. Accordingly, ourOur results in any one quarter are not necessarily indicative of annual results or continuing trends.
Certain areas in and near the Gulf of Mexico and North Seawhich 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.weather conditions. Damage caused by high winds and turbulent seas could potentially cause us to adjust service operations or 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,conditions, we may experience disruptions in our operations because customers may curtailadjust their offshore activities due to damage to their assets, platforms, pipelines and other related facilities.
The operation of marine vessels is risky, and we do not have insurance coverage forall 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.assertions of our liability. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful liability claim for which we are not fully insured could have a material adverse effect on our financial position, results of operations and cash flows. Moreover, we 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 vesselsassets is in amounts approximating replacement value. In the event of property loss due to a catastrophic marine disaster, mechanical failure, collision or other event, insurance may not cover a substantial loss of revenue, increased costs and other liabilities, and therefore the loss of any of our assets could have a material adverse effect on us.
Our 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 our customers will be willing or financially able to meet these indemnification obligations.
Our oil and gas operations involve a high degree of operational, contractual and financial risk, particularly risk of personal injury, damage, loss of equipment and environmental accidents.incidents.
In January 2019 we acquired certain currently producingbegan owning 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. Furthermore, such operations necessarily involve some degree of contractual counterparty risk, including for the transportation, marketing and sale of such production, and to the extent we have partners in any of the properties we own or operate. As a result, any damage or loss not covered by our insurance could have a material adverse effect on our financial condition, results of operations and cash flow.flows.
Our customers may be unable or unwilling to indemnify us.
Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they agree to protect and indemnify us for liabilities resulting from various hazards associated with offshore operations. We can provide no assurance, however, that we will obtain such contractual indemnification or that our customers will be willing or financially able to meet their indemnification obligations.
Our operations outside of the U.S. subject us to additional risks.
Our operations outside of the U.S. are subject to risks inherent in foreign operations, including:
•the loss of revenue, property and equipment from expropriation, nationalization, war, insurrection, acts of terrorism and other political risks;
•increases in taxes and governmental royalties;
•laws and regulations affecting our operations, including with respect to customs, assessments and procedures, and similar laws and regulations that may affect our ability to move our assets in and out of foreign jurisdictions;
•renegotiation or abrogation of contracts with governmental and quasi-governmental entities;
•changes in laws and policies governing operations of foreign-based companies;
•currency exchange restrictions and exchange rate fluctuations;
•global economic cycles;
•restrictions or quotas on production and commodity sales;
•limited market access; and
•other uncertainties arising out of foreign government sovereignty over our international operations.
Certain countries have in place or are in the process of developing complex laws for foreign companies doing business in these countries, such as local content requirements. Some of these laws are difficult to interpret, making compliance uncertain, and others increase the cost of doing business, which may make it difficult for us in some cases to be competitive. In addition, laws and policies of the U.S. affecting foreign trade, taxation and other commercial activity may adversely affect our international operations.
Financial and Liquidity Risks
Our indebtedness and the terms of our indebtedness could impair our financial condition and our ability tofulfill our debt obligations.
As of December 31, 2020, we had $349.6 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 or industry conditions and other events beyond our control may make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt. If we fail to comply with these covenants and other restrictions, it could lead to reduced liquidity, an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral. These conditions and events may limit our access to the credit markets if we need to replace our existing debt, which could lead to increased costs and less favorable terms, including shorter repayment schedules and higher fees and interest rates.
Because we have certain debt and other obligations, a prolonged period of low demand and rates for our services could lead to a material adverse effect on our liquidity.
A prolonged period of difficult industry conditions, the failure of our customers to expend funds on our services or a longer period of lower rates for our services, coupled with certain fixed obligations that we have related to debt repayment, long-term vessel time charter contracts and certain other commitments related to ongoing operational activities, could lead to a material adverse effect on our liquidity and financial position.
Lack of access to the financial markets could negatively impact our ability to operate our business.
Access to financing may be limited and uncertain, especially in times of economic weakness, or declining sentiment towards industries we service. If capital and credit markets are limited, we may be unable to refinance or we may incur increased costs and obtain less favorable terms associated with refinancing of our maturing debt. Also, we may incur increased costs and obtain less favorable terms associated with any additional financing that we may require for future operations. Limited access to the financial markets could adversely impact our ability to take advantage of business opportunities or react to changing economic and business conditions. Additionally, if capital and credit markets are limited, this could potentially result in our customers curtailing their capital and operating expenditure programs, which could result in a decrease in demand for our assets and a reduction in revenues and/or utilization. Certain of our customers could experience an inability to pay suppliers, including us, in the event they are unable to access financial markets as needed to fund their operations. Likewise, our other counterparties may be unable to sustain their current level of operations, fulfill their commitments and/or fund future operations and obligations, each of which could adversely affect our operations. Continued lower levels of economic activity and weakness in the financial markets could also adversely affect our ability to implement our strategic objectives.
A further decline in the offshore energy services market could result in additional impairment charges.
Prolonged periods of low utilization and low rates for our services could result in the recognition of impairment charges for our assets if future cash flow estimates, based on information available to us at the time, indicate that their carrying value may not be recoverable.
Our international operations are exposed to currency devaluation and fluctuation risk.
Because we are a global company, our international operations are exposed to foreign currency exchange rate risks on all contracts denominated in foreign currencies. For some of our international contracts, a portion of the revenue and local expenses is incurred in local currencies and we 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.
Legal and Regulatory Compliance Risks
Government regulations may affect our business operations, including impeding our operations and making our operations more difficult and/or costly.
Our business is affected by changes in public policy and by federal, state, local and foreigninternational laws and regulations relating to the offshore oil and gas industry.operations. Offshore oil and gas operations are affected by tax, environmental, safety, labor, cabotage and other laws, by changes in those laws, application or interpretation of existing laws, and changes in related administrative regulations or enforcement priorities. It is also possible that these laws and regulations may 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. For instance, in
In January 2017 CBP proposed a modification or revocation of numerous prior letter rulings regarding2021, the interpretationU.S. Department of the Jones Act,Interior issued Order No. 3395, “Temporary Suspension of Delegated Authority” (“Order No. 3395”). Order No. 3395 suspends for 60 days the authority of the Department of Bureaus and Offices to, among other things, issue any fossil fuel authorization including a lease, contract, or other agreement or drilling permit. Order No. 3395 does not limit existing operations under valid leases or apply to authorizations necessary to avoid conditions that may threaten human health or safety or avoid adverse impact to public land or mineral resources. The interpretation or enforcement of Order No. 3395 or similar regulation may directly impede our operations or ability to service our customers’ needs. Such regulations could also result in offshore drilling rigs being diverted to well intervention work, which wouldmay create more competition for the services we offer. Such regulations may also affect oil and gas prices, which could impact the demand for our services. Such impediments, competition or reduction in activity could have significantly changed how foreign flaga material adverse effect on our operations, competitive position, results of operations and cash flows.
On December 20, 2019 CBP finalized a new set of rulings (the “2019 CBP Rulings”) that (i) restrict the scope of items that may be transported aboard non-coastwise qualified vessels could operate on the OCS. WhileOCS and (ii) establish rules regarding incidental vessel movements related to offshore lifting operations. The 2019 CBP withdrew this proposal in May 2017,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. Ifissue and, if a policy change occurredchallenge to the 2019 CBP Rulings were successful along the lines proposedsought by CBP in January 2017, such a newthose organizations, the resulting interpretation of the Jones Act could adversely impact the operations of non-coastwise qualified vessels working in the U.S. Gulf of Mexico, and could potentially make it more difficult and/or costly to perform our offshore services in the area. Industry would undoubtedly challenge any such action
On January 1, 2021, the National Defense Authorization Act for fiscal year 2021 came into force which, among other things, extended federal law, including the Jones Act, to U.S. offshore wind farm projects. This law could potentially make it more difficult and/or costly to provide for U.S. renewables customers the extentservices that it seeks to limit the ability of non-coastwise qualified vessels from performing the operations they arewe currently permitted to perform, but such regulatory or legislative action could create the same uncertaintyprovide for renewables customers in the industry as the January 2017 CBP proposal did.North Sea.
Tax laws are dynamic and subject to change as new laws are passed and new interpretations of the law are issued or applied. In 2017 the United StatesU.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 foreigninternational 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. GovernmentGovernmental 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 protectionprotections we seek to obtain from our customerscounterparties, 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.
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 U.S. Gulf of Mexico, an operator is required to comply with existing and newly developed regulations and enhanced safety standards. Before drilling may commence, the BSEE conducts many inspections of deepwater drilling operations for compliance with its regulations, including the testing of blowout preventers.regulations. Operators also are required to comply with the Safety and Environmental Management System regulations (“SEMS”) regulations within the deadlines specified by the regulations, and ensureconfirm that their contractors have SEMS compliantSEMS-compliant safety and environmental policies and procedures.procedures in place. Additionally, each operator must demonstrate that it has containment resources that are
available promptly in the event of a deepwater blowout, regardlessloss of the company or operator involved.well control. It is expected that thegovernment authorities, including BOEM and the BSEE, will continue to issue further regulations regarding deepwater offshore drilling. Our business, a significant portion of which is in the Gulf of Mexico, provides development services to newly drilled wells, and therefore relies heavily on the industry’s drilling of new oil and gas wells. If the issuance of drilling or other permits is significantly delayed, or if other oil and gas operations are delayed or reduced due to increased costs of complying with regulations, demand for our services in the Gulf of Mexico may also decline. Moreover, if our assets are not redeployed to other locations wheresuch that we can provide our services at a profitable rate,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 United StatesU.S. or in other areas around the world. If the United StatesU.S. or other countries where our customers operate enact stricter restrictions on offshore drilling or further regulate offshore drilling, and thereby increase costs and/or cause delays for our customers, 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 (the “FCPA”) 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 United States subject us to additional risks.General Risks
Our operations outside of the United States 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;
changes in laws and regulations affecting our operations, including changes in customs, assessments and procedures, and changes in 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 restrictions and exchange rate fluctuations;
global economic cycles;
restrictions or quotas on production and commodity sales;
limited market access; and
other uncertainties arising out of foreign government sovereignty over our international operations.
Certain countries have in place or are in the process of developing complex laws for foreign companies doing business in these countries, such as local content requirements. Some of these laws are difficult to interpret, making compliance uncertain, and others increase the cost of doing business, which may make it difficult for us in some cases to be competitive. In addition, laws and policies of the United States 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 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 toattract and retain other highly qualified personnel in the future, could disrupt ouroperations and adversely affect our financial results.
Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in oil and gas prices.nature. Many companies, including us, have had employee lay-offslayoffs 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, workers. For certain projectsqualified and experienced workers, and we may have competition for personnel with the requisite skill set, including from drilling companies.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 aspectsaspect 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. Furthermore, we may also experience increased cybersecurity risk as our onshore personnel continue to work remotely in an effort to limit the impact of COVID-19 at our locations. 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;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;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.
Certain provisions of our corporate documents, financial arrangements and Minnesota law may discourage athird party from making a takeover proposal.
We are authorized to fix,establish, without any action by our shareholders, the rights and preferences on up to 5,000,000 shares of preferred stock, including dividend, liquidation and voting rights. In addition, our by-laws divide theour Board of Directors into three classes. We are also subject to certain anti-takeover provisions of the Minnesota Business Corporation Act. We also have employment arrangements with all of our executive officers that could require cash payments, terms in certain of our convertible senior notes that could increase the applicable conversion rate and covenants in our Credit Facility that could put in breach, in the event of a “change of control.” Any or all of thethese provisions or factors described above may discourage a takeover proposal or tender offer not approved by management and theour Board of Directors 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
OUR VESSELS AND OTHER OPERATING ASSETS
We own aAs of December 31, 2020, our fleet of fiveincluded six vessels, six IRSs, three SILs, 46the ROAM, 44 ROVs, fivefour trenchers and one ROVDrill. We also have fivehad four vessels under long-term charter. Currently allAll 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.
Listing of Vessels and Other Assets Related to Operations as of December 31, 2020 (1)
|
| | | | | | | | | | | | | | | | | | | | | | |
|
Flag State | | Placed in Service (2) | |
Length (Feet) | |
Saturation
Diving
| |
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 | | Capable | | DP2 |
Well Enhancer | U.K. | | 10/2009 | | 432 | | Capable | | DP2 |
Q5000(5)Seawell (3)
| BahamasU.K. | | 4/20157/2002 | | 358368 | | — | | DP3DP2 |
Siem Helix1(6)Well Enhancer (3)
| BahamasU.K. | | 6/201610/2009 | | 521432 | | — | | DP3DP2 |
Siem Helix2(6)Q5000(5)
| Bahamas | | 2/20174/2015 | | 521358 | | — | | DP3 |
6 IRSs and 3 SILs (7)Siem Helix1(6)
| —Bahamas | | Various6/2016 | | —521 | | — | | — |
Robotics — | | | | | | | | | DP3 |
46Siem Helix2(6)
| Bahamas | | 2/2017 | | 521 | | DP3 |
| Q7000 | Bahamas | | 1/2020 | | 320 | | DP3 |
6 IRSs, 3 SILs and the ROAM (7) | — | | Various | | — | | — |
| Robotics — | | | | | | | |
44 ROVs, 54 Trenchers and 1 ROVDrill (3), (8) | — | | Various | | — | | — | | — |
Grand Canyon II(6) | Norway | | 10/20124/2015 | | 419 | | — | | DP3 |
Grand Canyon II(6)
| Norway | | 4/2015 | | 419 | | — | | DP3 |
Grand Canyon III(6) | Norway | | 5/2017 | | 419 | | — | | DP3 |
| |
(1) | Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the U.S. Coast Guard. ABS, BV, DNV and Lloyds are classification societies used by ship 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 our Credit Agreement described in Note 6. |
| |
(4) | Subject to a vessel mortgage securing our MARAD Debt described in Note 6. |
| |
(5) | Serves as security for our Nordea Q5000 Loan described in Note 6. |
| |
(7) | We own a 50% interest in one of our IRSs, the 15K IRS, which we jointly developed with OneSubsea. |
| |
(8) | Average age of our fleet of ROVs, trenchers and ROVDrills is approximately 8.9 years. |
(1)Under governmental regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness, safety and health set by governmental regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the Coast Guard. ABS, BV, DNV and Lloyds are classification societies used by vessel owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.
(2)Represents the date we placed our owned vessels in service (rather than the date of commissioning) or the date the charters for our chartered vessels commenced, as applicable.
(3)Serves as security for the Credit Agreement described in Note 8. The Seawell was pledged as security beginning in July 2020 as was the Well Enhancer beginning in February 2021.
(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)Vessel under long-term charter agreement.
(7)We own a 50% interest in the 15K IRS and the ROAM, both of which we jointly developed with Schlumberger.
(8)Average age of our fleet of ROVs, trenchers and ROVDrill is approximately 10.5 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 vesselasset maintenance programs that we believe permit us to continue to provide our customers with well-maintained, reliable vessels.assets. In the normal course of business, we charter otherspot vessels, on a short-term basis, such as tugboats, cargo barges, utility boats and additional robotics support vessels.
PRODUCTION FACILITIES
We own a 20% interest in Independence Hub, which owns the Independence Hub platform located in the eastern Gulf of Mexico.
FACILITIES
Our corporate headquarters are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas.Texas 77043. We currently lease all of our facilities. The list of our facilities, as of December 31, 2018 is as follows:which are primarily located in Texas, Scotland, Singapore and Brazil.
|
| | | | |
Location | | Function | | Size |
Houston, Texas | | Helix Energy Solutions Group, Inc.
Corporate Headquarters, Project
Management, and Sales Office
| | 118,630 square feet (including 30,104 square feet subject to approximately five years remaining under a sub-lease agreement) |
| | Helix Well Ops, Inc.
Corporate Headquarters, Project
Management and Sales Office
| | |
| | Canyon Offshore, Inc.
Corporate Headquarters, Project Management and Sales Office
| | |
| | Kommandor LLC
Corporate Headquarters
| | |
Houston, Texas | | Helix Energy Solutions Group, Inc.
Canyon Offshore, Inc.
Warehouse and Storage Facility
| | 5.5 acres
(Building: 90,640 square feet)
|
Aberdeen, Scotland | | Helix Well Ops (U.K.) Limited
Corporate Offices and Operations
| | 27,000 square feet |
| | Energy Resource Technology
(U.K). Limited
Corporate Offices
| | |
Aberdeen, Scotland | | Helix Well Ops (U.K.) Limited
Warehouse and Storage Facility
| | 14,124 square feet |
Aberdeen (Dyce), Scotland | | Canyon Offshore Limited
Corporate Offices, Operations and
Sales Office
| | 3.9 acres
(Building: 42,463 square feet)
|
Singapore | | Canyon Offshore International Corp.
Corporate, Operations and Sales Office
| | 22,486 square feet |
| | Helix Offshore Crewing Service Pte. Ltd.
Corporate Headquarters
| | |
Luxembourg | | Helix Group Holdings S.à r.l.
and subsidiaries
Corporate Offices and Operations
| | 161 square feet |
Brazil | | Helix do Brasil Serviços de Petróleo Ltda
Corporate, Operations and Sales Office
| | 3,338 square feet |
Item 3. Legal Proceedings
We are,The information required to be set forth under this heading is incorporated by reference from timeNote 17 to time, party to litigation arisingour consolidated financial statements included in the normal courseItem 8.Financial Statements and Supplementary Data 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.this Annual Report.
Item 4. Mine Safety Disclosures
Not applicable.
Information about our Executive Officers of the Company
TheOur executive officers of Helix are as follows:
|
| | | | | | | | | | | | | |
| Name | | Age | | Position |
| Owen Kratz | | 6466 | | President, Chief Executive Officer and Director |
| Erik Staffeldt | | 4749 | | Executive Vice President and Chief Financial Officer |
| Scott A. Sparks | | 4547 | | Executive Vice President and Chief Operating Officer |
Alisa B. JohnsonKenneth E. Neikirk | | 6145 | | ExecutiveSenior 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 theour Board of Directors 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-tradedpublicly 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 2018.2019. Mr. Staffeldt was also designated as Helix’s “principal accounting officer” for purposes of the Securities Act, of 1933, the Securities Exchange Act of 1934 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 2325 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’s robotics subsidiary,Helix Robotics Solutions, Inc. (formerly known as Canyon Offshore, Inc.), including as Senior Vice President from 2007 to September 2012. Mr. Sparks has over 2930 years of experience in the subsea industry, including as Operations Manager and Vessel Superintendent at Global Marine Systems and BT Marine Systems.
Alisa B. Johnson has served as ExecutiveKenneth E. (“Ken”) Neikirk is Senior Vice President, General Counsel and Corporate Secretary of Helix since November 2008,Helix. Mr. Neikirk has over 20 years of experience practicing law in the corporate and joined Helix as Senior Vice President, General Counselenergy sectors, and Secretary of Helix in September 2006. Ms. Johnson oversees the legal, human resources and contracts and insurance functions. Ms. Johnson has been involved with the energy industry for over 28 years.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 Ms. Johnson worked for Dynegy Inc. for nine years, at which company she held various legal positions of increasing responsibility, including Senior Vice President and Group General Counsel — Generation. From 1990 to 1997, Ms. Johnson held various legal positions at Destec Energy, Inc., and prior to that Ms. JohnsonMr. Neikirk was in private law practice. Ms. Johnson received herpractice in New York and Houston. Mr. Neikirk holds a Bachelor of Arts degree Cum Laude from RiceDuke University and her law degree Cum Laudea Juris Doctor from the University of Houston.Houston Law Center.
PART II
Item 5. Market for the Registrant’s Common Equity, Related StockholderMatters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” On February 15, 2019,19, 2021, the closing sale price of our common stock on the NYSE was $7.36$4.95 per share. As of February 15, 2019,19, 2021, there were 342287 registered shareholders and approximately 21,10093,300 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 ofOperations “— 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, 20132015 to the cumulative total shareholder return for (i) the stocks of 500 large-cap corporations maintained by Standard & Poor’s (“S&P 500”), assuming the reinvestment of dividends; (ii) the Philadelphia Oil Service Sector index (the “OSX”), a price-weighted index of leading oil service companies, assuming the reinvestment of dividends; and (iii) a peer group selected by us as of January 2020 (the “Peer Group”) consisting of the following companies: ChampionX Corporation (formerly known as Apergy Corporation), Archrock, Inc., Baker Hughes Company, Core Laboratories N.V., DMC Global Inc., Dril-Quip, Inc., ForumBristow Group Inc. (formerly known as Era Group Inc.), Exterran Corporation, Geospace Technologies Corporation, Halliburton Company, KLX Energy Technologies,Services Holdings, Inc., Frank’sMatrix Service Company, McDermott International, N.V.Inc., Hornbeck Offshore Services,NOV Inc. (formerly known as National Oilwell Varco, Inc.), Newpark Resources, Inc., Noble Corporation plc, Oceaneering International, Inc., Oil States International, Inc., Rowan CompaniesProPetro Holding Corp., RPC, Inc., Schlumberger Limited, SEACOR Holdings Inc., TechnipFMC plc, Superior Energy Services Inc., TETRA Technologies, Inc., and TidewaterU.S. Silica Holdings, Inc. 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, 20182020 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, 20132015 in our common stock at the closing price on that date price and on December 31, 20132015 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 — (76.7)(20.2)%; the Peer Group — (92.1)(50.3)%; the OSX — (71.3)(68.9)%; and S&P 500 — 50.3%105.8%. These results are not necessarily indicative of future performance.
Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group
| | | | As of December 31, | | As of December 31, |
| | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| Helix | $ | 100.0 |
| | $ | 93.6 |
| | $ | 22.7 |
| | $ | 38.1 |
| | $ | 32.5 |
| | $ | 23.3 |
| Helix | $ | 100.0 | | | $ | 167.7 | | | $ | 143.3 | | | $ | 102.9 | | | $ | 183.1 | | | $ | 79.8 | |
| Peer Group Index | $ | 100.0 |
| | $ | 61.7 |
| | $ | 26.7 |
| | $ | 22.9 |
| | $ | 14.4 |
| | $ | 7.9 |
| Peer Group Index | $ | 100.0 | | | $ | 132.5 | | | $ | 111.4 | | | $ | 66.8 | | | $ | 75.1 | | | $ | 49.7 | |
| Oil Service Index | $ | 100.0 |
| | $ | 75.0 |
| | $ | 56.1 |
| | $ | 65.4 |
| | $ | 53.2 |
| | $ | 28.7 |
| Oil Service Index | $ | 100.0 | | | $ | 101.0 | | | $ | 98.5 | | | $ | 54.0 | | | $ | 53.7 | | | $ | 31.1 | |
| S&P 500 | $ | 100.0 |
| | $ | 113.7 |
| | $ | 115.3 |
| | $ | 129.1 |
| | $ | 157.2 |
| | $ | 150.3 |
| S&P 500 | $ | 100.0 | | | $ | 113.5 | | | $ | 138.3 | | | $ | 132.2 | | | $ | 173.9 | | | $ | 205.8 | |
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, 2020 | | — | | | $ | — | | | — | | | 6,709,159 | |
| November 1 to November 30, 2020 | | — | | | — | | | — | | | 6,709,159 | |
| December 1 to December 31, 2020 | | 24,316 | | | 4.19 | | | — | | | 6,913,705 | |
| | 24,316 | | | $ | 4.19 | | | — | | | |
(1)Includes shares forfeited in satisfaction of tax obligations upon vesting of restricted shares.
(2)Under the terms of our stock repurchase program, we may repurchase shares of our common stock in an amount equal to any equity granted to our employees, officers and directors under our share-based compensation plans, including share-based awards under our existing long-term incentive plans and shares issued to our employees under our Employee Stock Purchase Plan (Note 14), and such shares increase the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 11.
(3)In December 2020, we issued 204,546 shares of restricted stock to independent members of our Board. In January 2021, we issued 14,249 shares of restricted stock to certain independent 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.
|
| | | | | | | | | | | | | |
| 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, 2018 | | — |
| | $ | — |
| | — |
| | 3,804,134 |
|
| November 1 to November 30, 2018 | | 3,768 |
| | 7.35 |
| | — |
| | 3,804,134 |
|
| December 1 to December 31, 2018 | | 41,726 |
| | 7.70 |
| | — |
| | 3,931,076 |
|
| | | 45,494 |
| | $ | 7.67 |
| | — |
| | |
| |
(1) | Includes shares forfeited by a former officer and certain members of our Board of Directors in satisfaction of tax obligations upon vesting of restricted shares. |
| |
(2) | Under the terms of our stock repurchase program, the issuance of shares to members of our Board of Directors and to certain employees, including shares issued to our employees under the Employee Stock Purchase Plan (the “ESPP”) (Note 12), increases the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 9. |
| |
(3) | In January 2019, we issued approximately 0.7 million shares of restricted stock to our executive officers, select management employees, and certain members of our Board of Directors who have elected to take their quarterly fees in stock in lieu of cash. These issuances increase the number of shares available for repurchase by a corresponding amount (Note 9). |
Item 6. Selected Financial Data.Data
The financial data presented below for each of the five years ended December 31, 20182020 should be read in conjunction with Item 7. Management’s Discussion andAnalysis of Financial Condition and Results of Operations and Item 8. FinancialStatements and Supplementary Data included elsewhere in this Annual Report.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| (in thousands, except per share amounts) |
| Statement of Operations Data: | | | | | | | | | |
| Net revenues | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | | | $ | 581,383 | | | $ | 487,582 | |
| Gross profit | 79,909 | | | 137,838 | | | 121,684 | | | 62,166 | | | 46,516 | |
Income (loss) from operations (1) | 13,025 | | | 67,997 | | | 51,543 | | | (1,130) | | | (63,235) | |
| | | | | | | | | |
| | | | | | | | | |
Net income (loss) (2) | 20,084 | | | 57,697 | | | 28,598 | | | 30,052 | | | (81,445) | |
| Net loss attributable to redeemable noncontrolling interests | (2,090) | | | (222) | | | — | | | — | | | — | |
| Net income (loss) attributable to common shareholders | 22,174 | | | 57,919 | | | 28,598 | | | 30,052 | | | (81,445) | |
Adjusted EBITDA (3) | 155,260 | | | 180,088 | | | 161,709 | | | 107,216 | | | 89,544 | |
| Earnings (loss) per share of common stock: | | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| Basic | $ | 0.13 | | | $ | 0.39 | | | $ | 0.19 | | | $ | 0.20 | | | $ | (0.73) | |
| | | | | | | | | |
| | | | | | | | | |
| Diluted | $ | 0.13 | | | $ | 0.38 | | | $ | 0.19 | | | $ | 0.20 | | | $ | (0.73) | |
| Weighted average common shares outstanding: | | | | | | | | | |
| Basic | 148,993 | | | 147,536 | | | 146,702 | | | 145,295 | | | 111,612 | |
| Diluted | 149,897 | | | 149,577 | | | 146,830 | | | 145,300 | | | 111,612 | |
(1)Amount in 2020 included a $6.7 million goodwill impairment charge related to our U.K. well intervention reporting unit (Note 7). Amount in 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | (in thousands, except per share amounts) |
| Statement of Operations Data: | | | | | | | | | |
| Net revenues | $ | 739,818 |
| | $ | 581,383 |
| | $ | 487,582 |
| | $ | 695,082 |
| | $ | 1,107,156 |
|
Gross profit (loss) (1) | 121,684 |
| | 62,166 |
| | 46,516 |
| | (233,774 | ) | | 344,036 |
|
Income (loss) from operations (2) | 51,543 |
| | (1,130 | ) | | (63,235 | ) | | (307,360 | ) | | 261,756 |
|
Net income (loss), including noncontrolling interests (3) | 28,598 |
| | 30,052 |
| | (81,445 | ) | | (376,980 | ) | | 195,550 |
|
| Net income applicable to noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (503 | ) |
| Net income (loss) applicable to common shareholders | 28,598 |
| | 30,052 |
| | (81,445 | ) | | (376,980 | ) | | 195,047 |
|
Adjusted EBITDA (4) | 161,709 |
| | 107,216 |
| | 89,544 |
| | 172,736 |
| | 378,010 |
|
| Earnings (loss) per share of common stock: | | | | | | | | | |
| Basic | $ | 0.19 |
| | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
|
| Diluted | $ | 0.19 |
| | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
|
| Weighted average common shares outstanding: | | | | | | | | | |
| Basic | 146,702 |
| | 145,295 |
| | 111,612 |
| | 105,416 |
| | 105,029 |
|
| Diluted | 146,830 |
| | 145,300 |
| | 111,612 |
| | 105,416 |
| | 105,045 |
|
| |
(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 (Note 2). 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 7). Amount in 2015 included losses totaling $124.3 million related to our investments in 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 (loss), including noncontrolling interests. |
(2)Amount in 2020 included a $9.2 million gain on extinguishment of long-term debt (Note 8), a $7.6 million net tax benefit as a result of the U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) and net deferred tax benefits of $8.3 million due to the reduction in the overall tax rate associated with two of our foreign subsidiaries (Note 9). Amount in 2017 included a $51.6 million income tax benefit as a result of the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”).
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | (in thousands) |
| Balance Sheet Data: | | | | | | | | | |
| Working capital | $ | 259,440 |
| | $ | 186,004 |
| | $ | 336,387 |
| | $ | 473,123 |
| | $ | 468,660 |
|
| Total assets | 2,347,730 |
| | 2,362,837 |
| | 2,246,941 |
| | 2,399,959 |
| | 2,690,179 |
|
| Total debt | 440,315 |
| | 495,627 |
| | 625,967 |
| | 749,335 |
| | 540,853 |
|
| Total shareholders’ equity | 1,617,779 |
| | 1,567,393 |
| | 1,281,814 |
| | 1,278,963 |
| | 1,653,474 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| (in thousands) |
| Balance Sheet Data: | | | | | | | | | |
| Cash and cash equivalents and restricted cash | $ | 291,320 | | | $ | 262,561 | | | $ | 279,459 | | | $ | 266,592 | | | $ | 356,647 | |
Net working capital (1) | 246,338 | | | 153,508 | | | 259,440 | | | 186,004 | | | 336,387 | |
| Total assets | 2,498,278 | | | 2,596,731 | | | 2,347,730 | | | 2,362,837 | | | 2,246,941 | |
Long-term debt (1) | 258,912 | | | 306,122 | | | 393,063 | | | 385,766 | | | 558,396 | |
| | | | | | | | | |
| | | | | | | | | |
| Total shareholders’ equity | 1,740,496 | | | 1,699,591 | | | 1,617,779 | | | 1,567,393 | | | 1,281,814 | |
(1)Current maturities of our long-term debt are included in net working capital and excluded from long-term debt. Long-term debt is also net of unamortized debt discounts and debt issuance costs (Note 8).
Non-GAAP Financial Measures
A non-GAAP financial measure is generally defined by the SEC as a numerical measure of a company’s historical or future performance, financial position or cash flows that includes or excludes amounts from the most directly comparable measure under U.S. generally accepted accounting principles (“GAAP”). Non-GAAP financial measures should be viewed in addition to, and not as an alternative to, our reported results prepared in accordance with GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these measures.
We measure our operating performance based on EBITDA 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 our operating performance and compare our results to other companies that have different financing, capital and tax structures.
We define EBITDA as earnings before income taxes, net interest expense, 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 periods presented, we have reported them as a separate line item. Non-cash goodwill impairment and losses on equity investments are also added back if applicable. Loss on extinguishment of long-term debt is considered equivalent to additional interest expense and thus is added back to net income (loss), including noncontrolling interests.
In the following reconciliation, we provide amounts as reflected in our accompanying consolidated financial statements unless otherwise footnoted. This means that these amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries. Accordingly, to arrive at our measure of Adjusted EBITDA, when applicable, we exclude the noncontrolling interests related to the adjustment components of EBITDA. Our measure of Adjusted EBITDA also excludes gain or loss on disposition of assets. 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.
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 flowflows from operating activities, or other income or cash flow data prepared in accordance with GAAP.
We define EBITDA as earnings before income taxes, net interest expense, gain or loss on extinguishment of long-term debt, net other income or expense, and depreciation and amortization expense. Non-cash impairment losses on goodwill and other long-lived assets and non-cash gains and losses on equity investments are also added back if applicable. To arrive at our measure of Adjusted EBITDA, we exclude the gain or loss on disposition of assets and the general provision for current expected credit losses, 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 the consolidated financial statements unless otherwise noted.
The reconciliation of our net income (loss), including noncontrolling interests, to EBITDA and Adjusted EBITDA is as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | |
| Net income (loss) | $ | 20,084 | | | $ | 57,697 | | | $ | 28,598 | | | $ | 30,052 | | | $ | (81,445) | |
| Adjustments: | | | | | | | | | |
| Income tax provision (benefit) | (18,701) | | | 7,859 | | | 2,400 | | | (50,424) | | | (12,470) | |
| Net interest expense | 28,531 | | | 8,333 | | | 13,751 | | | 18,778 | | | 31,239 | |
| (Gain) loss on extinguishment of long-term debt | (9,239) | | | 18 | | | 1,183 | | | 397 | | | 3,540 | |
| Other (income) expense, net | (4,724) | | | (1,165) | | | 6,324 | | | 1,434 | | | (3,510) | |
| Depreciation and amortization | 133,709 | | | 112,720 | | | 110,522 | | | 108,745 | | | 114,187 | |
| | | | | | | | | |
| Goodwill impairments | 6,689 | | | — | | | — | | | — | | | 45,107 | |
| Gain (loss) on equity investment | (264) | | | (1,613) | | | 3,430 | | | 1,800 | | | 1,674 | |
| EBITDA | 156,085 | | | 183,849 | | | 166,208 | | | 110,782 | | | 98,322 | |
| Adjustments: | | | | | | | | | |
| (Gain) loss on disposition of assets, net | (889) | | | — | | | (146) | | | 39 | | | (1,290) | |
| General provision for current expected credit losses | 746 | | | — | | | — | | | — | | | — | |
| Realized losses from foreign exchange contracts not designated as hedging instruments | (682) | | | (3,761) | | | (3,224) | | | (3,605) | | | (7,488) | |
| Other than temporary loss on note receivable | — | | | — | | | (1,129) | | | — | | | — | |
| Adjusted EBITDA | $ | 155,260 | | | $ | 180,088 | | | $ | 161,709 | | | $ | 107,216 | | | $ | 89,544 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | | | | | | | | |
| Net income (loss), including noncontrolling interests | $ | 28,598 |
| | $ | 30,052 |
| | $ | (81,445 | ) | | $ | (376,980 | ) | | $ | 195,550 |
|
| Adjustments: | | | | | | | | | |
| Income tax provision (benefit) | 2,400 |
| | (50,424 | ) | | (12,470 | ) | | (101,190 | ) | | 66,971 |
|
| Net interest expense | 13,751 |
| | 18,778 |
| | 31,239 |
| | 26,914 |
| | 17,859 |
|
| Loss on extinguishment of long-term debt | 1,183 |
| | 397 |
| | 3,540 |
| | — |
| | — |
|
Other (income) expense, net (1) | 6,324 |
| | 1,434 |
| | (3,510 | ) | | 24,310 |
| | (814 | ) |
| Depreciation and amortization | 110,522 |
| | 108,745 |
| | 114,187 |
| | 120,401 |
| | 109,345 |
|
Asset impairments (2) | — |
| | — |
| | — |
| | 345,010 |
| | — |
|
Goodwill impairments (3) | — |
| | — |
| | 45,107 |
| | 16,399 |
| | — |
|
Losses on equity investments (4) | 3,430 |
| | 1,800 |
| | 1,674 |
| | 122,765 |
| | — |
|
| EBITDA | 166,208 |
| | 110,782 |
| | 98,322 |
| | 177,629 |
| | 388,911 |
|
| Adjustments: | | | | | | | | | |
| Noncontrolling interests | — |
| | — |
| | — |
| | — |
| | (661 | ) |
| (Gain) loss on disposition of assets, net | (146 | ) | | 39 |
| | (1,290 | ) | | (92 | ) | | (10,240 | ) |
| Realized losses from foreign exchange contracts not designated as hedging instruments | (3,224 | ) | | (3,605 | ) | | (7,488 | ) | | (4,801 | ) | | — |
|
| Other than temporary loss on note receivable | (1,129 | ) | | — |
| | — |
| | — |
| | — |
|
| Adjusted EBITDA | $ | 161,709 |
| | $ | 107,216 |
| | $ | 89,544 |
| | $ | 172,736 |
| | $ | 378,010 |
|
| |
(1) | Amount in 2015 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.
|
| |
(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 (Note 2). 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 December2015 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, |
| 2020 | | 2019 | | 2018 | | 2017 | | 2016 |
| | | | | | | | | |
| Cash flows from operating activities | $ | 98,800 | | | $ | 169,669 | | | $ | 196,744 | | | $ | 51,638 | | | $ | 38,714 | |
| Less: Capital expenditures, net of proceeds from sale of assets | (19,281) | | | (138,304) | | | (137,058) | | | (221,127) | | | (173,310) | |
| Free cash flow | $ | 79,519 | | | $ | 31,365 | | | $ | 59,686 | | | $ | (169,489) | | | $ | (134,596) | |
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2015 | | 2014 |
| | | | | | | | | | |
| Cash flows from operating activities | $ | 196,744 |
| | $ | 51,638 |
| | $ | 38,714 |
| | $ | 110,805 |
| | $ | 359,485 |
|
| Less: Capital expenditures, net of proceeds from sale of assets | (137,058 | ) | | (221,127 | ) | | (173,310 | ) | | (302,719 | ) | | (323,338 | ) |
| Free cash flow | $ | 59,686 |
| | $ | (169,489 | ) | | $ | (134,596 | ) | | $ | (191,914 | ) | | $ | 36,147 |
|
Item 7. Management’s Discussion and Analysis of Financial Condition andResults of Operations
The following management’s discussion and analysis should be read in conjunction withour 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 ourcurrent views with respect to future events and financial performance. Our actualresults may differ materially from those anticipated in these forward-lookingstatements as a result of certain factors, such as those set forth under Item 1A. RiskFactors and located earlier in this Annual Report.
EXECUTIVE SUMMARY
Our StrategyBusiness
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 focusingThe services we offer to the oil and gas market cover the lifecycle of an offshore oil and gas field, and the services we offer to the renewable energy market are currently focused on these services will deliver favorable long-term financial returns. From time to time, we may make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. We expect ouroffshore wind farm projects and cable burial operations. Our well intervention fleet includes seven purpose-built well intervention vessels, six IRSs, three SILs and the ROAM. Our robotics equipment includes 44 work-class ROVs, four trenchers and one ROVDrill. We charter ROV support vessels on both long-term and spot bases to expand withfacilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the completion and delivery in 2019 ofworld. Our Production Facilities segment includes the Q7000, a newbuild semi-submersible vessel. Chartering newer vessels with additional capabilities, such as the three Grand Canyon vessels, should enable our robotics business to better serve the needs of our customers. From a longer-term perspective we also expect to benefit from our fixed fee agreement for the HP I, a dynamically positioned floating production vessel that processes production from the Phoenix field for the field operator until at least June 1, 2023.
In January 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V.HFRS and Schlumberger Oilfield Holdings Ltd. entered into a Strategic Alliance Agreementour ownership of oil and related agreements for the parties’ strategic alliance 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. We and OneSubsea jointly developed a 15K IRS, each owning a 50% interest. The 15K IRS was completed and placed into service in January 2018. Our total investment in the 15K IRS was approximately $17 million. In October 2016, we and OneSubsea launched the development of our first ROAM for an estimated cost of approximately $6 million for our 50% interest. At December 31, 2018, our total investment in the ROAM was $5.6 million. The ROAM is expected to be available in 2019.gas properties.
Economic Outlook and Industry Influences
Demand for our services is primarily influenced by the condition of the oil and gas industry, and the renewable energy markets, in particular, the willingness of oil and gasoffshore energy companies to spend on operational activities as well asand capital projects. The performance of our business is also largely dependent onaffected by the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, global health, and several other factors, including:
•worldwide economic activity and general economic and business conditions, including available access to global capital and capital markets;
•the global supply and demand for oil and natural gas, especially in the United States, Europe, China and India;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;OPEC and/or OPEC+;
•the availability and discovery rate of new oil and natural gas reserves in offshore areas;
•the exploration and production of onshore shale oil and natural gas;
•the cost of offshore exploration for and production and transportation of oil and natural gas;
•the level of excess production capacity;
•the ability of oil and gas companies to generate funds or otherwise obtain external capital for capital projects and production operations;
•the environmental and social sustainability of the oil and gas sector and the perception thereof, including within the investing community;
•the sale and expiration dates of offshore leases globally;
•governmental restrictions on oil and gas leases, including executive actions taken with respect to permitting in the United Statesconnection with oil and overseas;gas leases on federal land announced in January 2021;
•technological advances affecting energy exploration, production, transportation and consumption;
•potential acceleration of the development of alternative fuels;
•shifts in end-customer preferences toward fuel efficiency and the use of natural gas;gas or renewable energy alternatives;
•weather conditions, natural disasters, and natural disasters;epidemic and pandemic diseases, including the ongoing COVID-19 pandemic;
•laws, regulations and policies directly related to the industries in which we provide services, and their interpretation and enforcement;
•environmental and other governmental regulations; and
•domestic and international tax laws, regulations and policies.
West Texas IntermediateCrude oil prices rosedeclined significantly in 2014 and have been volatile since then, most recently experiencing a precipitous decline through April 2020 due to over $70 per barrelthe ongoing COVID-19 pandemic as well as the price war among OPEC+ nations during 2018 before decreasing to around $45 per barrel towardsthe first quarter 2020. Prices have since begun a modest recovery as OPEC+ nations have cut production, fears of vast oversupply and a lack of storage capacity have subsided, and economic shutdowns resulting from the pandemic have eased in certain regions. However, oil prices remained low through the end of the year. Volatility2020 and their recovery remains uncertain. The decline in oil prices createsand the volatility and uncertainty in prices have caused oil and gas explorationoperators to drastically reduce spending (on both operational activities and production activities. For instance, an increase in oilcapital projects), which has decreased the demand and gas exploration and production activities (shale oil production in particular) is expected when major oil producing countries including the U.S. increase output as a result of rising oil prices. Increased supply without adequate levels of increase in demand, however, may weaken oil prices and industry prospects. The resulting industry environment may continue to curtail investments in offshore exploration and production as well as other offshore operational activities. Increased competitionrates for limitedservices provided by offshore oil and gas projects has driven down rates thatservices providers. Historically, drilling rig contractors are charging for their services, which affects us, as drilling rigs historically have been the asset class used for offshore well intervention work. This rigwork, and our customers have used drilling rigs on existing long-term contracts to perform well intervention work instead of new drilling activities. Rig day rates are also a pricing indicator for our services. Rig overhang, combined with lower volumes of work may affectand lower day rates quoted by drilling rig contractors, affects the utilization and/or rates we can achieve for our assets. The currentassets and services. Furthermore, additional 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. In addition,
The ongoing COVID-19 pandemic has resulted in a new period of market weakness. While the full impact of the COVID-19 pandemic, including the duration of the decrease in economic activity and the resulting impact on the demand and price of oil, remains unknown, we expect that the industry will be challenged through 2021 and possibly longer. We have seen and expect to continue to see operators reducing spending and deferring work, driving down the rates they are presently willing to pay for services, asserting claims of force majeure and/or cancelling contracts and rig contractors likewise are lowering prices, stacking rigs, furloughing employees, and recognizing losses. We believe the uncertainty and other conditions of the current environment will make it more difficult for us to secure long-term contracts for our vessels and systems, as operators may be less willing to commit to future spending. These developments have also impacted, and are expected to continue to impact, many other aspects of our industry and the global economy, including limiting access to and use of capital across various sources and markets, disrupting supply chains and increasing costs, and negatively affecting human capital resources including complicating offshore crew changes due to health and travel restrictions as well as the overall health of the global workforce.
The COVID-19 pandemic and the decrease in the price of oil impacted our 2020 operating results. Most if not all of our oil and gas customers have drastically cut their spending, which has reduced the demand and rates for the services offered to our oil and gas customers. We warm-stacked two of our well intervention vessels in April 2020 as a result of decreased demand and government lock-downs: the Seawell in the North Sea and the Q7000, which completed a project offshore Nigeria in the first quarter 2020. The COVID-19 pandemic continues to pose challenges with, and increase costs related to, our supply chain, logistics and human capital resources, including minimizing the direct impact of COVID-19 on our offshore workforce and challenges with offshore crew changes due to travel restrictions and quarantine measures. The impact of COVID-19 on energy companies’ market values was a key contributor to our recognition of a goodwill impairment charge during the first quarter 2020. While these market disruptions may be temporary, we cannot reliably estimate the duration of the COVID-19 pandemic or current market conditions, or the ultimate impact they will have on our financial position, results of operations and cash flows.
Despite this current period of market weakness and volatility, over the longer term effects of the 2017 Tax Act on capital spending bywe expect oil and gas companies are still uncertain.
Many oil and gas companies areto increasingly focusingfocus on optimizing production of their existing subsea wells. We believe that we have a competitive advantage in terms of performing well intervention services efficiently. Furthermore, we believe that whenAs oil and gas companies begin to increase overall spending levels,re-assess and focus their budgetary spend allocations, we expect that it will likelymay be forweighted towards production enhancement activities rather than exploration projects as enhancement is less expensive per incremental barrel of oil than new exploration. Moreover, as the subsea tree base expands and ages, the demand for exploration projects.P&A services should persist. Our well intervention and robotics operations are intended to service the life spanlifecycle of an oil and gas field as well as to provide abandonmentP&A services at the end of the life of a field as required by governmental regulations. Thus,We believe that we have a competitive advantage in performing well intervention services efficiently and we believe that fundamentals for our business remain favorable over the longer term as the need for prolongation ofto prolong well life in oil and gas production is theand safely decommission end of life wells are primary driverdrivers of demand for our services. This belief is
Our current strategy is to be positioned for future recovery while managing a sustained period of weak activity. This strategy is based on the following factors:multiple factors, including: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as plug and abandonmentP&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. We could see the beginnings of an upturn in the demand
Demand for our services in the U.S. Gulfrenewable energy market is affected by various factors, including the pace of Mexico, which are primarily driven by two factors: (1) long-term rig contracts are not being renewed thus removing rig overhangconsumer shift towards renewable energy sources, global electricity demand, technological advancements that was considered by our customersincrease the production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to be a sunk cost;deeper water, and (2) work needed on aging wells, which has been deferred, is becoming less likely to be further deferred due to the decline in well performance.government subsidies for renewable energy projects.
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)August 2020), which has allowed us to strategically focus on our core well intervention and robotics businesses. After commencing operations for Petrobras in 2017, both
In January 2020, the Siem Helix1Q7000, a newbuild semi-submersible well intervention vessel built to U.K. North Sea standards, commenced operations.
During 2020, the COVID-19 pandemic and Siem Helix 2 vessels achieved a full year of operations with high utilization in 2018. Additionally in 2018 a third of our robotics revenues were derived from offshore renewables work involving seabed trenching (increased from prior years),related governmental shut-downs significantly affected oil and we expect the growinggas prices, which negatively affected customer demand for our services fromservices. Consequently, we warm-stacked the alternative (renewable) energy industry to continue. Our robotics business also benefited from cost savings such as reduced charter costsSeawell and the Q7000 during part of 2020 and focused on maintaining utilization on our other vessels and equipment. We implemented a number of health and safety protocols as a result of returning the Deep Cygnuspandemic, including significant measures to its ownerprotect personnel working in the offshore environment. The vast majority of our onshore personnel are working remotely during the first quarter of 2018. Furthermore, the 15K IRS, which was jointly developed and ordered by us and OneSubsea, was placed into service in January 2018.
RESULTS OF OPERATIONSpandemic.
We have three reportable business segments: Well Intervention, Roboticscontinued to expand our services and Production Facilities. All material intercompany transactions betweenofferings into the segments have been eliminatedoffshore renewable energy sector. During 2020, we completed a site clearance project in our consolidated financial statements,the North Sea as well as performed services for renewable energy customers in Asia and the U.S., including our consolidated results of operations.the first wind farm installed in U.S. federal waters.
Backlog
We seek to 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. In addition to serving the oil and gas market, our robotics assets are contracted for the development of offshore renewable energy projects (wind farms). We operateprovide services primarily in deepwater in the U.S. 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, 2018,2020, our consolidated backlog that is supported by written agreements or contracts totaled $1.1 billion,$407 million, of which $470$301 million is expected to be performed in 2019.2021. The substantial majority of our backlog is associated with our Well Intervention business segment. As of December 31, 2018,2020, our well intervention backlog was $0.9 billion, including $368$226 million, all of which is expected to be performed in 2019.2021. 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 Helix1 and Siem Helix2 chartered vessels, and our fixed fee agreement for the HP I represent approximately 90%69% of our total backlog. AtAs of December 31, 2017,2019, the total backlog associated with our operations was $1.6 billion.$796 million. 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.
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, 20182020 and 20172019
The following table details various financial and operational highlights for the periods presented (dollars in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, | | Increase/(Decrease) |
| 2020 | | 2019 | | Amount | | Percent |
| Net revenues — | | | | | | | |
| Well Intervention | $ | 539,249 | | | $ | 593,300 | | | $ | (54,051) | | | (9) | % |
| Robotics | 178,018 | | | 171,672 | | | 6,346 | | | 4 | % |
| Production Facilities | 58,303 | | | 61,210 | | | (2,907) | | | (5) | % |
| | | | | | | |
| Intercompany eliminations | (42,015) | | | (74,273) | | | 32,258 | | | |
| $ | 733,555 | | | $ | 751,909 | | | $ | (18,354) | | | (2) | % |
| | | | | | | |
| Gross profit (loss) — | | | | | | | |
| Well Intervention | $ | 41,037 | | | $ | 104,376 | | | $ | (63,339) | | | (61) | % |
| Robotics | 22,716 | | | 15,809 | | | 6,907 | | | 44 | % |
| Production Facilities | 17,883 | | | 19,222 | | | (1,339) | | | (7) | % |
| Corporate, eliminations and other | (1,727) | | | (1,569) | | | (158) | | | |
| $ | 79,909 | | | $ | 137,838 | | | $ | (57,929) | | | (42) | % |
| | | | | | | |
| Gross margin — | | | | | | | |
| Well Intervention | 8 | % | | 18 | % | | | | |
| Robotics | 13 | % | | 9 | % | | | | |
| Production Facilities | 31 | % | | 31 | % | | | | |
| Total company | 11 | % | | 18 | % | | | | |
| | | | | | | |
Number of vessels or robotics assets (1) / Utilization (2) | | | | | | | |
| Well intervention vessels | 7/67% | | 6/89% | | | | |
Robotics assets (3) | 49/34% | | 50/41% | | | | |
| Chartered robotics vessels | 2/94% | | 3/87% | | | | |
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, | | Increase/(Decrease) |
| | 2018 | | 2017 | | Amount | | Percent |
| Net revenues — | | | | | | | |
| Well Intervention | $ | 560,568 |
| | $ | 406,341 |
| | $ | 154,227 |
| | 38 | % |
| Robotics | 158,989 |
| | 152,755 |
| | 6,234 |
| | 4 | % |
| Production Facilities | 64,400 |
| | 64,352 |
| | 48 |
| | — | % |
| Intercompany eliminations | (44,139 | ) | | (42,065 | ) | | (2,074 | ) | | |
| | $ | 739,818 |
| | $ | 581,383 |
| | $ | 158,435 |
| | 27 | % |
| | | | | | | | |
| Gross profit (loss) — | | | | | | | |
| Well Intervention | $ | 101,129 |
| | $ | 66,515 |
| | $ | 34,614 |
| | 52 | % |
| Robotics | (4,978 | ) | | (31,986 | ) | | 27,008 |
| | 84 | % |
| Production Facilities | 27,626 |
| | 28,568 |
| | (942 | ) | | (3 | )% |
| Corporate, eliminations and other | (2,093 | ) | | (931 | ) | | (1,162 | ) | | |
| | $ | 121,684 |
| | $ | 62,166 |
| | $ | 59,518 |
| | 96 | % |
| | | | | | | | |
| Gross margin — | | | | | | | |
| Well Intervention | 18 | % | | 16 | % | | | | |
| Robotics | (3 | )% | | (21 | )% | | | | |
| Production Facilities | 43 | % | | 44 | % | | | | |
| Total company | 16 | % | | 11 | % | | | | |
(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 2020 and 2019 included 1,057 and 191 spot vessel days, respectively, at near full utilization.
(3)Consists of ROVs, trenchers and ROVDrill.
|
| | | | | | | |
| | Year Ended December 31, | | |
| | 2018 | | 2017 | | | | |
Number of vessels or robotics assets (1) / Utilization (2) | | | | | | | |
| Well Intervention vessels | 6/83% | | 6/77% | | | | |
| Robotics assets | 52/37% | | 55/42% | | | | |
| Chartered robotics vessels | 3/76% | | 4/69% | | | | |
| |
(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, vessels taken out of service prior to their disposition and vessels jointly owned with third parties. |
| |
(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 2018 and 2017 include 245 and 170 spot vessel days, respectively, at near full utilization. |
Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties.segments. Intercompany segment revenues are as follows (in thousands):
| | | | Year Ended December 31, | | Increase/ | | Year Ended December 31, | | Increase/ |
| | 2018 | | 2017 | | (Decrease) | | 2020 | | 2019 | | (Decrease) |
| | | | | | | | | | | | |
| Well Intervention | $ | 14,218 |
| | $ | 11,489 |
| | $ | 2,729 |
| Well Intervention | $ | 15,039 | | | $ | 43,484 | | | $ | (28,445) | |
| Robotics | 29,921 |
| | 30,576 |
| | (655 | ) | Robotics | 26,976 | | | 30,789 | | | (3,813) | |
| | $ | 44,139 |
| | $ | 42,065 |
| | $ | 2,074 |
| |
| | | $ | 42,015 | | | $ | 74,273 | | | $ | (32,258) | |
Net Revenues. Our totalconsolidated net revenues increaseddecreased by 27%2% in 20182020 as compared to 2017 primarily as a result of2019, reflecting lower revenues from our Well Intervention and Production Facilities segments, offset in part by higher revenues in our Well InterventionRobotics segment and Robotics segments.lower intercompany eliminations.
Our Well Intervention revenues increaseddecreased by 38%9% in 20182020 as compared to 20172019, primarily reflecting higher revenues in Brazil and the North Sea, partially offset by a decrease in the Gulf of Mexico. In Brazil, the Siem Helix1 commenced operations for Petrobras in mid-April 2017 and the Siem Helix 2 commenced operations for Petrobras in mid-December 2017. Both vessels had a full year of operations in 2018. The Siem Helix1 and the Siem Helix2 achieved 97% and 94%lower vessel utilization respectively, during 2018 as compared to 96% and 53% utilization, respectively, during 2017. Higher revenue in the North Sea and Gulf of Mexico, lower IRS rental utilization and lower foreign currency rates in 2018Brazil. The decrease in revenues was primarily attributable to rate improvements with more diving and higher margin work for both vessels, offset in part by lowerrevenues on the Q7000, which commenced operations offshore West Africa in January 2020. Vessel utilization forin the North Sea and Gulf of Mexico were negatively impacted by the downturn in the offshore oil and gas market due to the COVID-19 pandemic, which resulted in our warm-stacking the Seawell. The Seawell was 72% utilized and the Q7000 during 2018the year, as compared to being 78% utilized during 2017. The Well Enhancer was 79% utilized during 2018well as compared to being 74% utilized during 2017. Decreased revenuescheduled regulatory certification inspections in the Gulf of Mexico was primarily attributable to lower utilization forduring the Q5000. The vessel was 82% utilized during 2018 as compared to being 91% utilized during 2017. Revenue from the Q4000 remained flat as a result of marginally higher rates while vessel utilization was 72% during 2018 as compared to 75% during 2017. The addition of the 15K IRS as well as higher utilization offirst quarter 2020. Additionally, our other IRS rental also contributed to the increasedWell Intervention revenues in 2018.the Gulf of Mexico in 2019 included $27.5 million associated with intercompany P&A work for our Production Facilities segment and no such P&A work was performed in 2020. Our Well Intervention revenues in 2019 also included approximately $3.9 million of contractual adjustments related to increases in withholding taxes in Brazil.
Our Robotics revenues increased by 4% in 20182020 as compared to 2017. The increase2019, primarily reflects higher trenching activities that contributed to increasedreflecting improvements in chartered vessel utilization, of ROV support vessels (from 69% in 2017 to 76% in 2018), and was offset in part by lower ROV, trencher and ROVDrill utilization. Chartered vessel days included a significant increase in spot vessel days primarily due to an offshore wind farm site clearance project in the North Sea and a marine salvage project offshore Australia. Our results included 1,690 vessel days and 407 trenching days (including 161 days on third-party vessels) in 2020 as compared to 1,086 vessel days and 729 trenching days (including 245 days on third-party vessels) in 2019.
Our Production Facilities revenues were consistent year over year.decreased by 5% in 2020 as compared to 2019, primarily reflecting reduced revenues associated with the HFRS and a reduction in oil and gas production revenues.
The decrease in intercompany eliminations was primarily attributable to a $27.5 million elimination of revenues that our Well Intervention segment earned in 2019 associated with its P&A work on the Droshky oil and gas properties on behalf of our Production Facilities segment. There were no such P&A-related intercompany eliminations in 2020.
Gross Profit (Loss). Our 2018consolidated 2020 gross profit increaseddecreased by 96%$57.9 million, or 42%, as compared to 20172019, primarily reflecting improvementslower gross profit in our Well Intervention and Production Facilities segments, offset in part by higher gross profit in our Robotics segments.segment.
The gross profit related to our Well Intervention segment increaseddecreased by 52%$63.3 million, or 61%, in 20182020 as compared to 2017,2019, primarily reflecting lower revenues, which included the warm stacking of the Seawell, lower vessel utilization in the Gulf of Mexico and higher costs associated with the Q7000, which commenced operations in January 2020 and was warm stacked beginning in April 2020 and until commencing its mobilization to West Africa in mid-November 2020.
The gross profit related to our Robotics segment increased by $6.9 million, or 44%, in 2020 as compared to 2019, primarily reflecting higher revenues as well as a full year of operations in Brazil and improvements in our operating results in the North Sea, offset in part by lower gross profit in the Gulf of Mexico.
The gross loss associated with our Robotics segment decreased by 84% in 2018 as compared to 2017 primarily reflecting cost reductions relating to certain vessels, including the termination of the Grand Canyon charter in November2019 and higher trenching revenues with increased utilization for our ROV support vessels.the expiration of the Grand Canyon II hedge in July 2019 and the Grand Canyon III hedge in February 2020 (Note 21).
The gross profit related to our Production Facilities segment decreased by 3%7% in 20182020 as compared to 20172019, primarily reflecting higher fuel costsdecreases in 2018.revenues.
Goodwill Impairment. The $6.7 million charge in 2020 reflects the impairment of the entire goodwill balance associated with our acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) (Note 7).
Selling, General and Administrative Expenses. Our selling, general and administrative expenses increasedin 2020 included a $2.7 million provision for credit losses (Note 19). Excluding this charge, our selling, general and administrative expenses decreased by $7.0$11.4 million in 20182020 as compared to 20172019, primarily asreflecting a result of increasedreduction in employee compensation costs related to employee incentive compensation and other employee benefits.cost-saving measures during 2020.
Equity in LossesEarnings of Investments.Investment. Equity in lossesearnings of investmentsinvestment was $3.9$0.2 million in 2018 as compared to $2.42020 and $1.4 million in 20172019, primarily reflecting an increasereductions in our share of losses that were recorded by Independence Hubremaining obligations to decommission the “Independence Hub” platform (Note 5).
Net Interest Expense. Our net interest expense totaled $13.8$28.5 million in 20182020 as compared to $18.8$8.3 million in 20172019, primarily reflecting a decreaselower capitalized interest in 2020 and higher yields associated with the 2026 Notes issued in August 2020. Capitalized interest expense and an increasedecreased to $1.2 million in interest income, partially offset by a decrease2020 with the completion of the Q7000 in capitalized interest. The decrease in interest expense was primarily attributable to a significant reduction in our debt levels (long-term debt decreased from $495.6 million at December 31, 2017 to $440.3 million at December 31, 2018). Interest expense for 2017 also included charges of $1.6 million to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments in our revolving credit facility were reduced (Note 6). Interest income totaled $3.2 million for 2018January 2020 as compared to $2.6$20.2 million for 2017. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest decreased from $16.9 million for 2017 to $15.6 million for 2018.in 2019 (Note 8).
LossGain on Extinguishment of Long-term Debt. The $1.2$9.2 million lossgain on extinguishment of long-term debt in 20182020 was attributable to the write-off of the unamortized debt issuance costs related to the prepayment of $61 million of the Term Loan in March 2018 and costs associated with our repurchase of $59.3a portion of the 2022 and 2023 Notes (Note 8).
Other Income, Net. Net other income increased by $3.6 million in aggregate principal amount of the 2032 Notes (Note 6). The $0.4 million loss in 2017 was associated with the write-off of the unamortized debt issuance costs related to certain lenders exiting from our then outstanding term loan prior to its June 2017 amendment and restatement.
Other Expense, Net. Net other expense increased by $4.9 million for 20182020 as compared to 2017. Net other expense in 2018 and 2017 included foreign currency transaction losses of $4.3 million and $2.2 million, respectively. These amounts2019, primarily reflectreflecting foreign exchange fluctuations in our non-U.S. dollar currencies. AlsoNet other income in 2020 and 2019 included in the comparable year over year periods were net losses (gains)foreign currency transaction gains of $0.9$4.6 million and $1.5 million, respectively.
Royalty Income and Other. Royalty income and other decreased by $0.6 million in 20182020 as compared to 2019. The decrease was primarily attributable to the reduction in our overriding royalty income, which was affected by lower average oil prices and $(0.8) millionlower production volumes in 2017 associated with our foreign currency exchange contracts that were not designated2020 as cash flow hedges (Note 18). Net other expense for 2018 included a $1.1 million other than temporary loss on a note receivable (Note 3).compared to 2019.
Income Tax Provision (Benefit). Income tax benefit was $18.7 million for 2020 as compared to an income tax provision of $7.9 million for 2018 was $2.4 million. Excluding a net deferred2019. Our income tax benefit in 2020 included discrete benefits related to the restructuring of $51.6 million as a resultcertain of the effect of U.S.our foreign subsidiaries and our carrying back certain net operating losses to prior periods with higher income tax rates under tax law changes enacted in 2017 and a $6.3 million tax charge in 2017 attributable to a change in tax position related to our foreign taxes,associated with the CARES Act (Note 9). Excluding these discrete items, we had an income tax benefit of $5.1$2.8 million for 2017. The varianceand an effective tax rate of (200.5)% in our income taxes (excluding the 2017 tax changes) primarily reflects increased profitability in 20182020 as compared to 2017.an income tax provision of $7.9 million and an effective tax rate of 12.0% in 2019. The negative effective tax rate was 7.7% for 2018 as compared to 247.5% for 2017. The variance was primarily attributable to the effect of the tax law changes and the change in tax position related to our foreign taxes in 2017near break-even pre-tax income for 2020 as well as the earnings mix between our higher and lower tax rate jurisdictions (Note 7).jurisdictions.
Comparison of Years Ended December 31, 20172019 and 20162018
The following table details variousVarious financial and operational highlights for the periodsyears ended December 31, 2019 and 2018 were previously presented (dollars in thousands):
|
| | | | | | | | | | | | | | |
| | Year Ended December 31, | | Increase/(Decrease) |
| | 2017 | | 2016 | | Amount | | Percent |
| Net revenues — | | | | | | | |
| Well Intervention | $ | 406,341 |
| | $ | 294,000 |
| | $ | 112,341 |
| | 38 | % |
| Robotics | 152,755 |
| | 160,580 |
| | (7,825 | ) | | (5 | )% |
| Production Facilities | 64,352 |
| | 72,358 |
| | (8,006 | ) | | (11 | )% |
| Intercompany eliminations | (42,065 | ) | | (39,356 | ) | | (2,709 | ) | | |
| | $ | 581,383 |
| | $ | 487,582 |
| | $ | 93,801 |
| | 19 | % |
| | | | | | | | |
| Gross profit (loss) — | | | | | | | |
| Well Intervention | $ | 66,515 |
| | $ | 26,879 |
| | $ | 39,636 |
| | 147 | % |
| Robotics | (31,986 | ) | | (12,466 | ) | | (19,520 | ) | | 157 | % |
| Production Facilities | 28,568 |
| | 34,335 |
| | (5,767 | ) | | (17 | )% |
| Corporate, eliminations and other | (931 | ) | | (2,232 | ) | | 1,301 |
| | |
| | $ | 62,166 |
| | $ | 46,516 |
| | $ | 15,650 |
| | 34 | % |
| | | | | | | | |
| Gross margin — | | | | | | | |
| Well Intervention | 16 | % | | 9 | % | | | | |
| Robotics | (21 | )% | | (8 | )% | | | | |
| Production Facilities | 44 | % | | 47 | % | | | | |
| Total company | 11 | % | | 10 | % | | | | |
| | | | | | | | |
Number of vessels or robotics assets (1) / Utilization (2) | | | | | | | |
| Well Intervention vessels | 6/77% |
| | 5/54% |
| | | | |
| Robotics assets | 55/42% |
| | 59/48% |
| | | | |
| Chartered robotics vessels | 4/69% |
| | 3/64% |
| | | | |
| |
(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, vessels taken out of service prior to their disposition and vessels jointly owned with third parties. |
| |
(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. |
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/ |
| | 2017 | | 2016 | | (Decrease) |
| | | | | | |
| Well Intervention | $ | 11,489 |
| | $ | 8,442 |
| | $ | 3,047 |
|
| Robotics | 30,576 |
| | 30,914 |
| | (338 | ) |
| | $ | 42,065 |
| | $ | 39,356 |
| | $ | 2,709 |
|
Net Revenues. Our total net revenues increased by 19% in 2017 as compared to 2016. Increased revenues for 2017 reflected higher revenues in our Well Intervention segment, offset in part by revenue decreases in our Robotics and Production Facilities segments.2019 Annual Report on Form 10-K.
Well Intervention revenues increased by 38% in 2017 as compared to 2016 primarily reflecting higher revenues generated from all
Robotics revenues decreased by 5% in 2017 as compared to 2016. The decrease primarily reflected lower utilization of our robotics assets and performing work at reduced rates. Some of our ROV units have been affected by other industry participants laying up vessels or canceling work as a result of the oil and gas industry downturn.
Production Facilities revenues decreased by 11% in 2017 as compared to 2016, which reflected reduced retainer fees from the amended HFRS agreement which was effective February 1, 2017, no revenue from the HFRS for 33 days as the Q4000 underwent its regulatory dry dock, and lower revenues from the amendment of the agreement with the Phoenix field operator for the HP I to a fixed fee agreement that commenced June 1, 2016.
Gross Profit (Loss). Our 2017 gross profit increased by 34% as compared to 2016. The gross profit related to our Well Intervention segment increased by 147% in 2017 as compared to 2016, primarily reflecting higher revenues in our North Sea region.
The gross loss associated with our Robotics segment increased by 157% in 2017 as compared to 2016 primarily reflecting decreased utilization for our robotics assets and performing work with lower profit margins.
The gross profit related to our Production Facilities segment decreased by 17% in 2017 as compared to 2016 primarily reflecting revenue decreases for the HFRS and the HP I.
Goodwill Impairment. The $45.1 million impairment charge in 2016 reflects the write-off of the entire goodwill balance associated with our robotics reporting unit.
Gain on Disposition of Assets, Net. The $1.3 million net gain on disposition of assets in 2016 was attributable to the sale of the Helix 534 in December 2016.
Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by $2.7 million in 2017 as compared to 2016. The decrease was primarily attributable to a $4.7 million decrease associated with the provision for uncertain collection of a portion of our then existing trade and note receivables as well as our overriding royalty interest asset being fully depreciated in April 2017, offset in part by an increase in payroll related costs including share-based compensation associated with our long-term incentive plan (Note 12).
Equity in Losses of Investments. Equity in losses of investments was $2.4 million in 2017 as compared to $2.2 million in 2016 primarily reflecting an increase in our share of losses that were recorded by Independence Hub (Note 5).
Net Interest Expense. Our net interest expense totaled $18.8 million in 2017 as compared to $31.2 million in 2016 reflecting increases in interest income and capitalized interest and a decrease in interest expense. Interest income totaled $2.6 million for 2017 as compared to $2.1 million for 2016. Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $16.9 million for 2017 as compared to $11.8 million for 2016. The decrease in interest expense was primarily attributable to a significant reduction in our debt levels, including an $80 million principal reduction of our term loan in June 2017. Interest expense for 2017 and 2016 also included charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments in our revolving credit facility were reduced (Note 6).
Loss on Extinguishment of Long-term Debt. The $0.4 million loss in 2017 was associated with the write-off of the unamortized debt issuance costs related to certain lenders exiting from the term loan then outstanding under our credit agreement prior to its amendment and restatement in June 2017 (Note 6). The $3.5 million loss in 2016 was associated with the repurchases of $139.9 million in aggregate principal amount of our 2032 Notes in 2016.
Other Income (Expense), Net. We reported other expense, net, of $1.4 million for 2017 as compared to other income, net, of $3.5 million for 2016. Other income (expense), net, in 2017 and 2016 included foreign currency transaction gains (losses) of $(2.2) million and $0.2 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 gains of $0.8 million and $1.3 million associated with our foreign currency exchange contracts primarily reflecting gains related to the portions of the contracts that were not designated as cash flow hedges (Note 18). In addition, other income, net, for 2016 included a $2.0 million net foreign currency translation gain reclassified out of accumulated other comprehensive loss into earnings during the year.
Income Tax Benefit. Income taxes reflected a benefit of $50.4 million in 2017 as compared to $12.5 million in 2016 This variance is primarily due to the effect of U.S. tax law changes enacted in December 2017, offset in part by a decrease in pretax loss for the current year period and a tax charge in 2017 attributable to a change in tax position related to our foreign taxes. The effective tax rate was 247.5% for 2017 as compared to 13.3% for 2016. The increase was primarily attributable to the effect of the tax law changes, partially offset by the earnings mix between our higher and lower tax rate jurisdictions and the change in tax position related to our foreign taxes (Note 7).
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, |
| 2020 | | 2019 |
| | | |
Net working capital (1) | $ | 246,338 | | | $ | 153,508 | |
Long-term debt (1) | 258,912 | | | 306,122 | |
Liquidity (2) | 451,532 | | | 379,533 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Net working capital | $ | 259,440 |
| | $ | 186,004 |
|
Long-term debt (1) | 393,063 |
| | 385,766 |
|
Liquidity (2) | 426,813 |
| | 348,207 |
|
| |
(1) | 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 discount and debt issuance costs. See Note 6 for information relating to our existing debt. |
| |
(2) | Liquidity, as defined by us, is equal to cash and cash equivalents plus available capacity under our Revolving Credit Facility, which capacity is reduced by letters of credit drawn against that facility. 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 Revolving Credit Facility (Note 6). Our liquidity at December 31, 2017 included cash and cash equivalents of $266.6 million and $81.6 million of available borrowing capacity under our Revolving Credit Facility. |
(2)Liquidity, as defined by us, is equal to cash and cash equivalents, excluding restricted cash, plus available capacity under the Revolving Credit Facility. Our liquidity at December 31, 2020 included cash and cash equivalents of $291.3 million and $160.2 million of available borrowing capacity under the Revolving Credit Facility (Note 8). 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. Our liquidity at December 31, 2019 excluded $54.1 million of restricted cash (short-term).
The carrying amount of our long-term debt, including current maturities, net of unamortized debt discountdiscounts and debt issuance costs, is as follows (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| Term Loan (matures December 2021) | $ | 29,559 | | | $ | 32,869 | |
Nordea Q5000 Loan (matures January 2021) (1) | 53,532 | | | 89,031 | |
| MARAD Debt (matures February 2027) | 53,361 | | | 60,073 | |
2022 Notes (mature May 2022) (2) | 33,477 | | | 115,765 | |
2023 Notes (mature September 2023) (2) | 26,922 | | | 108,115 | |
2026 Notes (mature February 2026) (2) | 152,712 | | | — | |
| Total debt | $ | 349,563 | | | $ | 405,853 | |
(1)We repaid the Nordea Q5000 Loan in January 2021.
(2)Convertible Senior Notes Due 2022 (the “2022 Notes”), Convertible Senior Notes Due 2023 (the “2023 Notes”) and Convertible Senior Notes Due 2026 (the “2026 Notes”) will increase to their face amounts through accretion of their debt discounts and amortization of related debt issuance costs through their respective maturity dates (Note8).
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Term Loan (matures June 2020) | $ | 33,321 |
| | $ | 95,842 |
|
| Nordea Q5000 Loan (matures April 2020) | 123,980 |
| | 158,930 |
|
| MARAD Debt (matures February 2027) | 66,443 |
| | 72,487 |
|
2022 Notes (mature May 2022) (1) | 112,192 |
| | 108,829 |
|
2023 Notes (mature September 2023) (2) | 104,379 |
| | — |
|
| 2032 Notes (redeemed May 2018) | — |
| | 59,539 |
|
| Total debt | $ | 440,315 |
| | $ | 495,627 |
|
| |
(1) | The 2022 Notes will increase to their face amount through accretion of the debt discount through May 1, 2022. |
| |
(2) | The 2023 Notes will increase to their face amount through accretion of the debt discount through September 15, 2023. |
The following table provides summary data from our consolidated statements of cash flows (in thousands):
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| Cash provided by (used in): | | | | | | Cash provided by (used in): | | | | | |
| Operating activities | $ | 196,744 |
| | $ | 51,638 |
| | $ | 38,714 |
| Operating activities | $ | 98,800 | | | $ | 169,669 | | | $ | 196,744 | |
| Investing activities | (136,014 | ) | | (221,127 | ) | | (147,110 | ) | Investing activities | (19,281) | | | (142,385) | | | (136,014) | |
| Financing activities | (46,186 | ) | | 77,482 |
| | (25,524 | ) | Financing activities | (52,578) | | | (45,818) | | | (46,186) | |
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. Historically,
The ongoing COVID-19 pandemic, challenging market conditions and industry-wide spending cuts have impacted our current year revenues and we have fundedexpect these events to continue to impact our capital program withresults into the near future. Our operating cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives.
As a further responseare impacted to the industry-wide spending reductions,extent we continue tocannot reduce costs or replace those revenues. Despite these challenges, we remain focused on maintaining a strong balance sheet and adequate liquidity. Over the near term, we may seek to reduce, defer or cancelhave reduced, deferred and cancelled certain planned capital expenditures.expenditures and reduced our overall cost structure commensurate with our level of activities. Over the mid-term, we have extended our debt maturity profile through refinancing a portion of our 2022 Notes and 2023 Notes in favor of the 2026 Notes. We have reduced operating costs through various measures including warm stacking two of our vessels during the year. These costs should return with increases in activity. We believe that our cash on hand, internally generated cash flows and available borrowing capacityavailability under ourthe Revolving Credit Facility will be sufficient to fund our operations and service our debt over at least the next 12months.
In accordance withThe ongoing COVID-19 pandemic and its impact on the energy and financial markets have contributed to rising yields on our Credit Agreement,existing debt as well as volatility in our stock price, both of which increase our cost of capital. The COVID-19 pandemic has also contributed to limited access to certain capital markets. Despite those limitations, in August 2020, we refinanced a portion of our 2022 Notes and 2023 Notes in favor of the 2026 Notes. The yield on the 2026 Notes is significantly higher than that of the 2022 Notes theand 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. Our Credit Agreement also contains provisions that limit our ability to incur certain types of additional indebtedness. These provisions effectively prohibit us from incurring any additional secured indebtedness or indebtedness guaranteed by us. The Credit Agreement does permit us to incur certain unsecured indebtedness and also provides for our subsidiaries to incur project financing indebtedness (such as our MARAD Debt and our Nordea Q5000 Loan) secured by the underlying asset, provided that such indebtedness is not guaranteed by us. Our Credit Agreement also permits our Unrestricted Subsidiaries to incur indebtedness provided that it is not guaranteed by us or any of our Restricted Subsidiaries (as defined in our Credit Agreement). As of December 31, 2018 and 2017, we were in compliance with the covenants in our long-term debt agreements.Notes.
A prolongedAn ongoing period of weak, or continued decreases in, 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 activityCurrent global market conditions have increased the potential for that difficulty. Decreases in our revenues and reduced EBITDA, including as may be attributable to the fallout from the ongoing COVID-19 pandemic, may also limit our ability to fully access ourthe Revolving Credit Facility may be impacted.Facility. At December 31, 2018,2020, our available borrowing capacity under ourthe Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $147.4$160.2 million, net of $2.6$2.8 million of letters of credit issued under that facility. We currently have no plans or forecasted requirements to borrowdo not anticipate borrowing under ourthe 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. Ourcontrol, and 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 and restrictions of the Credit Agreement, we may borrow and/or obtain letters of credit up to $25 million under our Revolving Credit Facility. See Note 6 for additional information relating to our long-term debt, including more information regarding our 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.
We repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018 and redeemed the remaining $0.8 million on May 4, 2018.default.
Operating Cash Flows
Total cash flows from operating activities increaseddecreased by $145.1$70.9 million in 20182020 as compared to 20172019, primarily reflecting improvementslower operating income and larger increases in our operations, collection of accounts receivable and reductions in interest payments.working capital as compared to 2019.
Total cash flows from operating activities increaseddecreased by $12.9$27.1 million in 20172019 as compared to 20162018, primarily reflecting changes in our working capital.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.
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 (uses) of cash associated with investing activities are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Capital expenditures: | | | | | |
| Well Intervention | $ | (19,523) | | | $ | (139,212) | | | $ | (136,164) | |
| Robotics | (257) | | | (417) | | | (151) | |
| Production Facilities | — | | | (123) | | | (325) | |
| Other | (464) | | | (1,102) | | | (443) | |
| STL acquisition, net | — | | | (4,081) | | | — | |
Proceeds from sale of assets (1) | 963 | | | 2,550 | | | 25 | |
| Other | — | | | — | | | 1,044 | |
| Net cash used in investing activities | $ | (19,281) | | | $ | (142,385) | | | $ | (136,014) | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Capital expenditures: | | | | | |
| Well Intervention | $ | (136,164 | ) | | $ | (230,354 | ) | | $ | (185,892 | ) |
| Robotics | (151 | ) | | (648 | ) | | (720 | ) |
| Production Facilities | (325 | ) | | — |
| | (74 | ) |
| Other | (443 | ) | | (125 | ) | | 199 |
|
Distributions from equity investment (1) | — |
| | — |
| | 1,200 |
|
Proceeds from sale of equity investment (1) | — |
| | — |
| | 25,000 |
|
Proceeds from sale of assets (2) | 25 |
| | 10,000 |
| | 13,177 |
|
| Other | 1,044 |
| | — |
| | — |
|
| Net cash used in investing activities | $ | (136,014 | ) | | $ | (221,127 | ) | | $ | (147,110 | ) |
| |
(1) | Amounts in 2016 reflect cash received as a result of our former ownership interest in Deepwater Gateway (Note 5). |
| |
(2) | Amount in 2017 reflects cash received from the sale of our former spoolbase facility located in Ingleside, Texas. Amount in 2016 primarily reflects cash received from the sale of our office and warehouse property located in Aberdeen, Scotland and the sale of the Helix 534 (Note 4).
|
Our capital expenditures have primarily included payments associated with the construction and completion of our the Q7000 vessel (see below), the investmentwhich commenced operations in the topsideJanuary 2020, as well intervention equipment for the Siem Helix1 and Siem Helix2 vessels that we charter to perform our agreements with Petrobras (see below), andas the investment in the 15K IRS and the ROAM.
In September 2013, we executed a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% will be paid upon the delivery of the vessel, which at our option can be deferred until December31, 2019. We are also contractually committed to reimburse the shipyard for its costs in connection with the deferment of the Q7000’s delivery beyond 2017. At December 31, 2018, our total investment in the Q7000 was $403.8 million, including $276.8 million of installment payments to the shipyard. Currently equipment is being manufactured and installed for the completion of the vessel. We plan to incur approximately $112 million related to the Q7000 in 2019, which includes the final shipyard payment of $69.2 million.
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 from commencement of operations 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 mid-April 2017, and the Siem Helix 2, which commenced operations for Petrobras in mid-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 wereof $52.6 million in 2020 primarily reflect the repayment of $46.4 million of scheduled maturities related to our indebtedness (Note 8) as well as the net cash flow from our issuance of the 2026 Notes and the related capped call transactions (the “2026 Capped Calls”) and our repurchase of a portion of the 2022 and 2023 Notes (as described below). Net cash outflows from financing activities of $45.8 million in 2019 primarily reflect 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. Net cash outflows from financing activities of $46.2 million in 2018 as compared to net cash inflowsprimarily reflect the repayment of $77.5 million in 2017. In 2018, we repaid approximately $166$166.4 million of our indebtedness using cash and the net proceeds from the issuance in March 2018 of $125 million of ourthe 2023 Notes.
In August 2020, we issued the 2026 Notes, (Note 6). Cash inflows from financing activities in 2017 included the net proceedswhich have a principal amount of $200 million and a conversion price of approximately $220 million we received from our underwritten public equity offering in January 2017, offset in part by debt repayments in 2017.
Net cash inflows from financing activities were $77.5 million in 2017 as compared to net cash outflows of $25.5 million in2016.$6.97 per share. We received approximately $220 million of net proceeds from our underwritten public equity offering in January 2017 (Note 8) and $100 million from our Term Loan borrowings in June 2017, while making early repayments of approximately $180 million of term loan then outstanding underused the credit agreement prior to its June 2017 amendment and restatement (Note 6). In 2016, we received $96.5 million of net proceeds from the saleissuance to fund our repurchase of $90 million of the 2022 Notes and $95 million of the 2023 Notes, to acquire the 2026 Capped Calls to offset potential dilution of our common stock under two separate at-the-market equity offering programs and $125 million fromby increasing the issuance of our 2022 Notes, while making early repayments of $33 million on our term loan then outstanding and repurchasing $139.9 million in aggregate principal amounteffective conversion price of the 20322026 Notes includingto approximately $122 million with proceeds from$8.42 per share, and to fund the related debt issuance of the 2022 Notes.costs.
Free Cash Flow
Free cash flow increased by $229.2to $79.5 million in 2018 as compared2020 from $31.4 million in 2019. The increase was due to 2017the decrease in capital expenditures with the completion of the Q7000, offset in part by the reduction in operating cash flows.
Free cash flow decreased to $31.4 million in 2019 from $59.7 million in 2018. The decrease was primarily attributable to higherthe decrease in operating cash flows and reducedhigher capital expenditures in 2018 as a result of the completion of the Siem Helix 1 and Siem Helix 2 vessels during 2017.2019.
Free cash flow decreased by $34.9 million in 2017 as compared to 2016 primarily attributable to higher capital expenditures 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 66. Selected Financial Data of this Annual Report for the definition and calculation of free cash flow.
Outlook
We anticipate that our capital expenditures, including capitalized interest, and deferred dry dock costs for 2019 will approximate $140 million. We believe that cash on hand, internally generated cash flows and availability under our Revolving Credit Facility will provide the capital necessary to continue funding our 2019 capital obligations and to meet our debt obligations due in 2019. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the level of our planned capital expenditures given a prolonged industry downturn.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 20182020 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 | $ | 29,750 | | | $ | 29,750 | | | $ | — | | | $ | — | | | $ | — | |
| Nordea Q5000 Loan | 53,572 | | | 53,572 | | | — | | | — | | | — | |
| MARAD debt | 56,410 | | | 7,560 | | | 16,270 | | | 17,935 | | | 14,645 | |
2022 Notes (2) | 35,000 | | | — | | | 35,000 | | | — | | | — | |
2023 Notes (3) | 30,000 | | | — | | | 30,000 | | | — | | | — | |
2026 Notes (4) | 200,000 | | | — | | | — | | | — | | | 200,000 | |
Interest related to debt (5) | 85,654 | | | 20,842 | | | 33,499 | | | 29,198 | | | 2,115 | |
| Property and equipment | 6,200 | | | 6,071 | | | 129 | | | — | | | — | |
Operating leases (6) | 260,487 | | | 92,239 | | | 153,553 | | | 10,641 | | | 4,054 | |
| Total cash obligations | $ | 757,073 | | | $ | 210,034 | | | $ | 268,451 | | | $ | 57,774 | | | $ | 220,814 | |
(1)Excludes unsecured letters of credit outstanding at December 31, 2020 totaling $2.8 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 20days in the period of 30consecutive 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, 2020, 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 20days in the period of 30consecutive 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, 2020, the conversion trigger was not met. See Note 8 for additional information.
(4)Notes mature in February 2026. The 2026 Notes can be converted prior to their stated maturity if the closing price of our common stock for at least 20days in the period of 30consecutive trading days ending on the last trading day of the preceding fiscal quarter exceeds $9.06 per share, which is 130% of the conversion price. At December 31, 2020, the conversion trigger was not met. See Note 8 for additional information.
(5)Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at December 31, 2020 for variable rate debt.
(6)Operating leases include vessel charters and facility and equipment leases. At December 31, 2020, our commitment related to long-term vessel charters totaled approximately $233.3 million, of which $89.5 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, 2020.
|
| | | | | | | | | | | | | | | | | | | |
| | Total (1) | | Less Than 1 Year | | 1-3 Years | | 3-5 Years | | More Than 5 Years |
| | | | | | | | | | |
| Term Loan | $ | 33,693 |
| | $ | 4,680 |
| | $ | 29,013 |
| | $ | — |
| | $ | — |
|
| Nordea Q5000 Loan | 125,000 |
| | 35,714 |
| | 89,286 |
| | — |
| | — |
|
| MARAD debt | 70,468 |
| | 6,858 |
| | 14,760 |
| | 16,270 |
| | 32,580 |
|
2022 Notes (2) | 125,000 |
| | — |
| | — |
| | 125,000 |
| | — |
|
2023 Notes (3) | 125,000 |
| | — |
| | — |
| | 125,000 |
| | — |
|
Interest related to debt (4) | 68,298 |
| | 22,013 |
| | 29,202 |
| | 14,458 |
| | 2,625 |
|
Property and equipment (5) | 85,900 |
| | 85,617 |
| | 283 |
| | — |
| | — |
|
Operating leases (6) | 480,724 |
| | 122,501 |
| | 196,541 |
| | 151,234 |
| | 10,448 |
|
| Total cash obligations | $ | 1,114,083 |
| | $ | 277,383 |
| | $ | 359,085 |
| | $ | 431,962 |
| | $ | 45,653 |
|
| |
(1) | Excludes unsecured letters of credit outstanding at December 31, 2018 totaling $2.6 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, 2018, the conversion trigger was not met. See Note 6 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, 2018, the conversion trigger was not met. See Note 6 for additional information. |
| |
(4) | Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at December 31, 2018 for variable rate debt. |
| |
(5) | Primarily reflects costs associated with our Q7000 semi-submersible well intervention vessel currently under completion (Note 14).
|
| |
(6) | Operating leases include vessel charters and facility leases. At December 31, 2018, our vessel charter commitments totaled approximately $444 million. |
Contingencies
CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our discussion and analysis of our financial condition and results of operations, and financial condition, as reflected in the accompanying consolidated financial statements and related footnotes included in Item 8.Financial Statements and Supplementary Data of this Annual Report, are prepared in conformity with accounting principles generally accepted in the United States.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 to our consolidated financial statements for a detailed discussion on the application of our accounting policies.
Property and Equipment
We review our property and equipment for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We base our evaluation onevaluate impairment indicators such asconsidering the nature of the asset (oror asset group),group, the future economic benefits of the asset (oror asset group),group, historical and estimated future profitability measures, and other external market conditions ofor factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and comparing those cash flows to the asset’s carrying value. ImpairmentIf the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. The expected future cash flows used for the assessment of recoverability are based on judgmental assessments of operating costs, project margins and capital project decisions,spending, considering allinformation available information at the date of review. Because there usually is a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates believed to be consistent with those used by principal market participants or based on a multiple of operating cash flows validated with historical market transactions of similar assets where possible.
The review of property and equipment for impairment indicators, the determination of the appropriate asset groups at which to evaluate impairment, the review of property and equipment for impairment indicators, the projection of future cash flows of property and equipment, and the estimated fair value of any property and equipment that may be deemed unrecoverable involve significant judgment and estimation on the part ofby 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. TaxesIncome 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, and in our operations and/or legal structure could impact our income tax liabilities. Furthermore, our tax filings are subject to regular audits and examination by the local taxing authorities. It is our policy toWe provide for uncertain tax positions and the 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 thea 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.but may be subject to changes in future tax legislation that may result in taxation. As of December 31, 2018,2020, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $93.2$62.2 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 and our Nordea Q5000 Loan.operations. We have not accrued forprovided deferred income taxes on the possibility of withholding taxes.accumulated earnings and profits as we consider them permanently reinvested. The computation of the potential deferred tax liability associated with the amount of reinvested earnings and other basis differencedifferences is not practicable.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2018,2020, we were exposed to market risk in two areas:risks associated with interest rates and foreign currency exchange rates.
Interest Rate Risk. As of December 31, 2018, $158.72020, $83.3 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 our Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. As of December 31, 2018, $93.8 million of our Nordea Q5000 Loan was hedged, and debt subject to variable rates after considering hedging activities was $64.9 million. The impact of interest rate risk is estimated using a hypothetical increase in interest rates ofby 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 $0.9 million in interest expense for the year ended December 31, 2018.2020.
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 United States,U.S., we generallyendeavor to pay a portion of our expenses in local currencies to partially offset revenues that are denominated in the same local currencies. In addition, a substantial portion of our contracts are denominated, and provide for collections from our customers, in U.S. dollars.
Assets and liabilities of our subsidiaries that do not have the U.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of our consolidated balance sheets. At December 31, 2018,2020, approximately 14%40% of our net assets were impacted by changes in foreign currencies in relation to the U.S. dollar. WeFor the years ended December 31, 2020, 2019 and 2018, we recorded foreign currency translation gains (losses) of $12.8 million, $5.4 million and $(7.2) million, $16.3 million and $(35.9) millionrespectively, to accumulated other comprehensive loss for the years ended December 31, 2018, 2017 and 2016, respectively.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.
We also have other foreign subsidiaries with a majority of their operations in U.S. dollars, which is their functional currency. When currencies other than the U.S. dollarfunctional currency are to be paid or received, the resulting transaction gain or loss associated with changes in the applicable foreign currency exchange rate is recognized in the consolidated statements of operations as a component of “Other income (expense), net.” For the years ended December 31, 2020, 2019 and 2018, 2017 and 2016, these amounts resulted inwe recorded foreign currency transaction gains (losses) of $4.6 million, $1.5 million and $(4.3) million, $(2.2) million and $0.2 million, respectively.
Our cash flows are subject to fluctuations resulting from changes in foreign currency exchange rates. Fluctuations in exchange rates are likely to impact our results of operations and cash flows. As a result, we entered into various foreign currency exchange contracts to stabilize expected cash outflowsrespectively, primarily related to certain vessel charters denominatedour subsidiaries in Norwegian kroners. In February 2013, we entered into 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 Norwegian kroner through July 2019 and February 2020, respectively. A portionU.K.
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, 20182020 and 2017,2019, the related consolidated statements of operations, comprehensive income, (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018,2020, 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, 20182020 and 2017,2019, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2018,2020, 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, 2018,2020, based on criteria established in Internal Control—Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 22, 201925, 2021 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 has 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 judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Evaluation of property and equipment impairment triggering events
As discussed in Note 2 to the consolidated financial statements, the Company evaluates property and equipment for impairment at least quarterly or whenever events or changes in circumstances indicate that the carrying amount of an asset or asset group may not be recoverable, or triggering events. The Company performs this evaluation considering the future economic benefits of the asset or asset groups, historical and estimated future profitability measures, and other factors that may be present, such as extended periods of idle time or the inability to contract the Company’s equipment at economical rates. The carrying value of property and equipment as of December 31, 2020 was $1,783 million.
We identified the evaluation of property and equipment impairment triggering events as a critical audit matter. Sustained decreases in commodity prices and uncertainty regarding spending trends by customers in the industry may lead to periods of low utilization and low day rates for those assets or asset groups not under a long-term contract, and the evaluation of the impact of these factors required a higher degree of subjective auditor judgment.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the evaluation of property and equipment for impairment. This included controls related to the Company’s process to identify and evaluate triggering events that indicate that the carrying value of an asset or asset group may not be recoverable, including the consideration of forecasted to actual results and market conditions in determination of a triggering event. We evaluated the Company’s identification of triggering events, including consideration of future expected revenues from executed contracts. We compared data used by the Company against analyst and industry reports. We compared the Company’s historical forecasts to actual results by asset group to assess the Company’s ability to accurately forecast.
/s/ KPMG LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 22, 201925, 2021
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 December31, 2018,2020, based on criteria established in Internal Control—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 December31, 2018,2020, 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, 20182020 and 2017,2019, the related consolidated statements of operations, comprehensive income, (loss), shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2018,2020, and the related notes (collectively, the consolidated financial statements), and our report dated February 22, 201925, 2021 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 22, 201925, 2021
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
| | | | December 31, | | December 31, |
| | 2018 | | 2017 | | 2020 | | 2019 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | | | | Current assets: | |
| Cash and cash equivalents | $ | 279,459 |
| | $ | 266,592 |
| Cash and cash equivalents | $ | 291,320 | | | $ | 208,431 | |
| Accounts receivable: | | | | |
| Trade, net of allowance for uncollectible accounts of $0 and $2,752, respectively | 67,932 |
| | 113,336 |
| |
| Unbilled and other | 51,943 |
| | 29,947 |
| |
| Restricted cash | | Restricted cash | 0 | | | 54,130 | |
| Accounts receivable, net of allowance for credit losses of $3,469 and $0, respectively | | Accounts receivable, net of allowance for credit losses of $3,469 and $0, respectively | 132,233 | | | 125,457 | |
| Other current assets | 51,594 |
| | 41,768 |
| Other current assets | 102,092 | | | 50,450 | |
| Total current assets | 450,928 |
| | 451,643 |
| Total current assets | 525,645 | | | 438,468 | |
| Property and equipment | 2,785,778 |
| | 2,695,772 |
| Property and equipment | 2,948,907 | | | 2,922,274 | |
| Less accumulated depreciation | (959,033 | ) | | (889,783 | ) | Less accumulated depreciation | (1,165,943) | | | (1,049,637) | |
| Property and equipment, net | 1,826,745 |
| | 1,805,989 |
| Property and equipment, net | 1,782,964 | | | 1,872,637 | |
| | Operating lease right-of-use assets | | Operating lease right-of-use assets | 149,656 | | | 201,118 | |
| Other assets, net | 70,057 |
| | 105,205 |
| Other assets, net | 40,013 | | | 84,508 | |
| Total assets | $ | 2,347,730 |
| | $ | 2,362,837 |
| Total assets | $ | 2,498,278 | | | $ | 2,596,731 | |
| | | | | | | | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY | LIABILITIES AND SHAREHOLDERS’ EQUITY |
| Current liabilities: | | | | Current liabilities: | |
| Accounts payable | $ | 54,813 |
| | $ | 81,299 |
| Accounts payable | $ | 50,022 | | | $ | 69,055 | |
| Accrued liabilities | 85,594 |
| | 71,680 |
| Accrued liabilities | 87,035 | | | 62,389 | |
| Income tax payable | 3,829 |
| | 2,799 |
| |
| | Current maturities of long-term debt | 47,252 |
| | 109,861 |
| Current maturities of long-term debt | 90,651 | | | 99,731 | |
| Current operating lease liabilities | | Current operating lease liabilities | 51,599 | | | 53,785 | |
| Total current liabilities | 191,488 |
| | 265,639 |
| Total current liabilities | 279,307 | | | 284,960 | |
| Long-term debt | 393,063 |
| | 385,766 |
| Long-term debt | 258,912 | | | 306,122 | |
| Operating lease liabilities | | Operating lease liabilities | 101,009 | | | 151,827 | |
| Deferred tax liabilities | 105,862 |
| | 103,349 |
| Deferred tax liabilities | 110,821 | | | 112,132 | |
| Other non-current liabilities | 39,538 |
| | 40,690 |
| Other non-current liabilities | 3,878 | | | 38,644 | |
| Total liabilities | 729,951 |
| | 795,444 |
| Total liabilities | 753,927 | | | 893,685 | |
| | | | | |
| Redeemable noncontrolling interests | | Redeemable noncontrolling interests | 3,855 | | | 3,455 | |
| Shareholders’ equity: | | | | Shareholders’ equity: | |
| Common stock, no par, 240,000 shares authorized, 148,203 and 147,740 shares issued, respectively | 1,308,709 |
| | 1,284,274 |
| |
| Common stock, no par, 240,000 shares authorized, 150,341 and 148,888 shares issued, respectively | | Common stock, no par, 240,000 shares authorized, 150,341 and 148,888 shares issued, respectively | 1,327,592 | | | 1,318,961 | |
| Retained earnings | 383,034 |
| | 352,906 |
| Retained earnings | 464,524 | | | 445,370 | |
| Accumulated other comprehensive loss | (73,964 | ) | | (69,787 | ) | Accumulated other comprehensive loss | (51,620) | | | (64,740) | |
| Total shareholders’ equity | 1,617,779 |
| | 1,567,393 |
| Total shareholders’ equity | 1,740,496 | | | 1,699,591 | |
| Total liabilities and shareholders’ equity | $ | 2,347,730 |
| | $ | 2,362,837 |
| |
| Total liabilities, redeemable noncontrolling interests and shareholders’ equity | | Total liabilities, redeemable noncontrolling interests and shareholders’ equity | $ | 2,498,278 | | | $ | 2,596,731 | |
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share amounts)
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Net revenues | $ | 739,818 |
| | $ | 581,383 |
| | $ | 487,582 |
| Net revenues | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | |
| | Cost of sales | 618,134 |
| | 519,217 |
| | 441,066 |
| Cost of sales | 653,646 | | | 614,071 | | | 618,134 | |
| | Gross profit | 121,684 |
| | 62,166 |
| | 46,516 |
| Gross profit | 79,909 | | | 137,838 | | | 121,684 | |
| Gain on disposition of assets, net | | Gain on disposition of assets, net | 889 | | | 0 | | | 146 | |
| Goodwill impairment | — |
| | — |
| | (45,107 | ) | Goodwill impairment | (6,689) | | | 0 | | | 0 | |
| Gain (loss) on disposition of assets, net | 146 |
| | (39 | ) | | 1,290 |
| |
| Selling, general and administrative expenses | (70,287 | ) | | (63,257 | ) | | (65,934 | ) | Selling, general and administrative expenses | (61,084) | | | (69,841) | | | (70,287) | |
| Income (loss) from operations | 51,543 |
| | (1,130 | ) | | (63,235 | ) | |
| Equity in losses of investment | (3,918 | ) | | (2,368 | ) | | (2,166 | ) | |
| Income from operations | | Income from operations | 13,025 | | | 67,997 | | | 51,543 | |
| Equity in earnings (losses) of investment | | Equity in earnings (losses) of investment | 216 | | | 1,439 | | | (3,918) | |
| Net interest expense | (13,751 | ) | | (18,778 | ) | | (31,239 | ) | Net interest expense | (28,531) | | | (8,333) | | | (13,751) | |
| Loss on extinguishment of long-term debt | (1,183 | ) | | (397 | ) | | (3,540 | ) | |
| Gain (loss) on extinguishment of long-term debt | | Gain (loss) on extinguishment of long-term debt | 9,239 | | | (18) | | | (1,183) | |
| Other income (expense), net | (6,324 | ) | | (1,434 | ) | | 3,510 |
| Other income (expense), net | 4,724 | | | 1,165 | | | (6,324) | |
| Other income – oil and gas | 4,631 |
| | 3,735 |
| | 2,755 |
| |
| Income (loss) before income taxes | 30,998 |
| | (20,372 | ) | | (93,915 | ) | |
| Royalty income and other | | Royalty income and other | 2,710 | | | 3,306 | | | 4,631 | |
| Income before income taxes | | Income before income taxes | 1,383 | | | 65,556 | | | 30,998 | |
| Income tax provision (benefit) | 2,400 |
| | (50,424 | ) | | (12,470 | ) | Income tax provision (benefit) | (18,701) | | | 7,859 | | | 2,400 | |
| Net income (loss) | $ | 28,598 |
| | $ | 30,052 |
| | $ | (81,445 | ) | |
| Net income | | Net income | 20,084 | | | 57,697 | | | 28,598 | |
| Net loss attributable to redeemable noncontrolling interests | | Net loss attributable to redeemable noncontrolling interests | (2,090) | | | (222) | | | 0 | |
| Net income attributable to common shareholders | | Net income attributable to common shareholders | $ | 22,174 | | | $ | 57,919 | | | $ | 28,598 | |
| | | | | | | | | | | | |
| Earnings (loss) per share of common stock: | | | | | | |
| Earnings per share of common stock: | | Earnings per share of common stock: | |
| Basic | $ | 0.19 |
| | $ | 0.20 |
| | $ | (0.73 | ) | Basic | $ | 0.13 | | | $ | 0.39 | | | $ | 0.19 | |
| Diluted | $ | 0.19 |
| | $ | 0.20 |
| | $ | (0.73 | ) | Diluted | $ | 0.13 | | | $ | 0.38 | | | $ | 0.19 | |
| | | | | | | | | | | | |
| Weighted average common shares outstanding: | | | | | | Weighted average common shares outstanding: | |
| Basic | 146,702 |
| | 145,295 |
| | 111,612 |
| Basic | 148,993 | | | 147,536 | | | 146,702 | |
| Diluted | 146,830 |
| | 145,300 |
| | 111,612 |
| Diluted | 149,897 | | | 149,577 | | | 146,830 | |
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Net income (loss) | $ | 28,598 |
| | $ | 30,052 |
| | $ | (81,445 | ) |
| Other comprehensive income (loss), net of tax: | | | | | |
| Net unrealized gain (loss) on hedges arising during the period | (847 | ) | | 3,323 |
| | 2,366 |
|
| Reclassifications to net income (loss) | 7,201 |
| | 12,915 |
| | 12,851 |
|
| Income taxes on hedges | (1,338 | ) | | (5,724 | ) | | (5,347 | ) |
| Net change in hedges, net of tax | 5,016 |
| | 10,514 |
| | 9,870 |
|
| 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) arising during the period | (7,166 | ) | | 16,264 |
| | (33,899 | ) |
| Reclassification adjustment for net translation gain realized upon liquidation | — |
| | — |
| | (2,044 | ) |
| Foreign currency translation gain (loss) | (7,166 | ) | | 16,264 |
| | (35,943 | ) |
| Other comprehensive income (loss), net of tax | (2,647 | ) | | 27,187 |
| | (26,073 | ) |
| Comprehensive income (loss) | $ | 25,951 |
| | $ | 57,239 |
| | $ | (107,518 | ) |
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Net income | $ | 20,084 | | | $ | 57,697 | | | $ | 28,598 | |
| Other comprehensive income (loss), net of tax: | | | | | |
| Net unrealized loss on hedges arising during the period | (95) | | | (680) | | | (847) | |
| Reclassifications into earnings | 452 | | | 5,470 | | | 7,201 | |
| Income taxes on hedges | (72) | | | (966) | | | (1,338) | |
| Net change in hedges, net of tax | 285 | | | 3,824 | | | 5,016 | |
| Unrealized loss on note receivable arising during the period | 0 | | | 0 | | | (629) | |
| Income taxes on note receivable | 0 | | | 0 | | | 132 | |
| Unrealized loss on note receivable, net of tax | 0 | | | 0 | | | (497) | |
| | | | | |
| | | | | |
| Foreign currency translation gain (loss) | 12,835 | | | 5,400 | | | (7,166) | |
| Other comprehensive income (loss), net of tax | 13,120 | | | 9,224 | | | (2,647) | |
| Comprehensive income | 33,204 | | | 66,921 | | | 25,951 | |
| Less comprehensive loss attributable to redeemable noncontrolling interests: | | | | | |
| Net loss | (2,090) | | | (222) | | | 0 | |
| Foreign currency translation gain | 90 | | | 138 | | | 0 | |
| Comprehensive loss attributable to redeemable noncontrolling interests | (2,000) | | | (84) | | | 0 | |
| Comprehensive income attributable to common shareholders | $ | 35,204 | | | $ | 67,005 | | | $ | 25,951 | |
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)
| | | | | | | | | | | | | Common Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss | | Total
Shareholders’
Equity | | Redeemable
Noncontrolling
Interests |
| | Common Stock | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total Shareholders’ Equity | | Shares | | Amount | |
| | Shares | | Amount | | |
| Balance, December 31, 2015 | 106,289 |
| | $ | 945,565 |
| | $ | 404,299 |
| | $ | (70,901 | ) | | $ | 1,278,963 |
| |
| Net loss | — |
| | — |
| | (81,445 | ) | | — |
| | (81,445 | ) | |
| Foreign currency translation adjustments | — |
| | — |
| | — |
| | (35,943 | ) | | (35,943 | ) | |
| Unrealized gain on hedges, net of tax | — |
| | — |
| | — |
| | 9,870 |
| | 9,870 |
| |
| Equity component of debt discount on convertible senior notes | — |
| | 10,719 |
| | — |
| | — |
| | 10,719 |
| |
| Re-acquisition of equity component of debt discount on convertible senior notes | — |
| | (1,625 | ) | | — |
| | — |
| | (1,625 | ) | |
| Issuance of common stock, net of transaction costs | 13,019 |
| | 96,547 |
| | — |
| | — |
| | 96,547 |
| |
| Activity in company stock plans, net and other | 1,322 |
| | 463 |
| | — |
| | — |
| | 463 |
| |
| Share-based compensation | — |
| | 5,767 |
| | — |
| | — |
| | 5,767 |
| |
| Cumulative share-based compensation in excess of fair value of modified liability awards | — |
| | 203 |
| | — |
| | — |
| | 203 |
| |
| Excess tax from share-based compensation | — |
| | (1,705 | ) | | — |
| | — |
| | (1,705 | ) | |
| 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 |
| Balance, December 31, 2017 | 147,740 | | | $ | 1,284,274 | | | $ | 352,906 | | | $ | (69,787) | | | $ | 1,567,393 | | | $ | — | |
| Net income | — |
| | — |
| | 28,598 |
| | — |
| | 28,598 |
| Net income | — | | | — | | | 28,598 | | | — | | | 28,598 | | | — | |
| Reclassification of stranded tax effect to retained earnings | — |
| | — |
| | 1,530 |
| | (1,530 | ) | | — |
| Reclassification of stranded tax effect to retained earnings | — | | | — | | | 1,530 | | | (1,530) | | | — | | | — | |
| Foreign currency translation adjustments | — |
| | — |
| | — |
| | (7,166 | ) | | (7,166 | ) | Foreign currency translation adjustments | — | | | — | | | — | | | (7,166) | | | (7,166) | | | — | |
| Unrealized gain on hedges, net of tax | — |
| | — |
| | — |
| | 5,016 |
| | 5,016 |
| Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 5,016 | | | 5,016 | | | — | |
| Unrealized loss on note receivable, net of tax | — |
| | — |
| | — |
| | (497 | ) | | (497 | ) | Unrealized loss on note receivable, net of tax | — | | | — | | | — | | | (497) | | | (497) | | | — | |
| Equity component of debt discount on convertible senior notes | — |
| | 15,411 |
| | — |
| | — |
| | 15,411 |
| Equity component of debt discount on convertible senior notes | — | | | 15,411 | | | — | | | — | | | 15,411 | | | — | |
| | Activity in company stock plans, net and other | 463 |
| | (746 | ) | | — |
| | — |
| | (746 | ) | Activity in company stock plans, net and other | 463 | | | (746) | | | — | | | — | | | (746) | | | — | |
| Share-based compensation | — |
| | 9,770 |
| | — |
| | — |
| | 9,770 |
| Share-based compensation | — | | | 9,770 | | | — | | | — | | | 9,770 | | | — | |
| Balance, December 31, 2018 | 148,203 |
| | $ | 1,308,709 |
| | $ | 383,034 |
| | $ | (73,964 | ) | | $ | 1,617,779 |
| Balance, December 31, 2018 | 148,203 | | | $ | 1,308,709 | | | $ | 383,034 | | | $ | (73,964) | | | $ | 1,617,779 | | | $ | — | |
| Net income | | Net income | — | | | — | | | 57,919 | | | — | | | 57,919 | | | (222) | |
| Reclassification of deferred gain from sale leaseback transaction to retained earnings | | Reclassification of deferred gain from sale leaseback transaction to retained earnings | — | | | — | | | 4,560 | | | — | | | 4,560 | | | — | |
| Foreign currency translation adjustments | | Foreign currency translation adjustments | — | | | — | | | — | | | 5,400 | | | 5,400 | | | 138 | |
| Unrealized gain on hedges, net of tax | | Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 3,824 | | | 3,824 | | | — | |
| Issuance of redeemable noncontrolling interests | | Issuance of redeemable noncontrolling interests | — | | | — | | | — | | | — | | | — | | | 3,396 | |
| Accretion of redeemable noncontrolling interests | | Accretion of redeemable noncontrolling interests | — | | | — | | | (143) | | | — | | | (143) | | | 143 | |
| Activity in company stock plans, net and other | | Activity in company stock plans, net and other | 685 | | | (1,032) | | | — | | | — | | | (1,032) | | | — | |
| Share-based compensation | | Share-based compensation | — | | | 11,284 | | | — | | | — | | | 11,284 | | | — | |
| Balance, December 31, 2019 | | Balance, December 31, 2019 | 148,888 | | | $ | 1,318,961 | | | $ | 445,370 | | | $ | (64,740) | | | $ | 1,699,591 | | | $ | 3,455 | |
| Net income | | Net income | — | | | — | | | 22,174 | | | — | | | 22,174 | | | (2,090) | |
| Credit losses recognized in retained earnings upon adoption of ASU No. 2016-13 | | Credit losses recognized in retained earnings upon adoption of ASU No. 2016-13 | — | | | — | | | (620) | | | — | | | (620) | | | — | |
| Foreign currency translation adjustments | | Foreign currency translation adjustments | — | | | — | | | — | | | 12,835 | | | 12,835 | | | 90 | |
| Unrealized gain on hedges, net of tax | | Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 285 | | | 285 | | | — | |
| Accretion of redeemable noncontrolling interests | | Accretion of redeemable noncontrolling interests | — | | | — | | | (2,400) | | | — | | | (2,400) | | | 2,400 | |
| Equity component of convertible senior notes | | Equity component of convertible senior notes | — | | | 33,336 | | | — | | | — | | | 33,336 | | | — | |
| Re-acquisition of equity component of convertible senior notes | | Re-acquisition of equity component of convertible senior notes | — | | | (18,006) | | | — | | | — | | | (18,006) | | | — | |
| Capped call transactions | | Capped call transactions | — | | | (10,625) | | | — | | | — | | | (10,625) | | | — | |
| Activity in company stock plans, net and other | | Activity in company stock plans, net and other | 1,453 | | | (4,345) | | | — | | | — | | | (4,345) | | | — | |
| Share-based compensation | | Share-based compensation | — | | | 8,271 | | | — | | | — | | | 8,271 | | | — | |
| Balance, December 31, 2020 | | Balance, December 31, 2020 | 150,341 | | | $ | 1,327,592 | | | $ | 464,524 | | | $ | (51,620) | | | $ | 1,740,496 | | | $ | 3,855 | |
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities: | | | | | | Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 28,598 |
| | $ | 30,052 |
| | $ | (81,445 | ) | |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | |
| Net income | | Net income | $ | 20,084 | | | $ | 57,697 | | | $ | 28,598 | |
| Adjustments to reconcile net income to net cash provided by operating activities: | | Adjustments to reconcile net income to net cash provided by operating activities: | |
| Depreciation and amortization | 110,522 |
| | 108,745 |
| | 114,187 |
| Depreciation and amortization | 133,709 | | | 112,720 | | | 110,522 | |
| Non-cash goodwill impairment | — |
| | — |
| | 45,107 |
| |
| Goodwill impairment | | Goodwill impairment | 6,689 | | | 0 | | | 0 | |
| Amortization of debt discounts | 5,735 |
| | 4,688 |
| | 5,905 |
| Amortization of debt discounts | 6,964 | | | 6,261 | | | 5,735 | |
| Amortization of debt issuance costs | 3,592 |
| | 6,154 |
| | 7,733 |
| Amortization of debt issuance costs | 3,177 | | | 3,600 | | | 3,592 | |
| Share-based compensation | 9,925 |
| | 10,877 |
| | 5,862 |
| Share-based compensation | 8,568 | | | 11,469 | | | 9,925 | |
| Deferred income taxes | (2,430 | ) | | (54,585 | ) | | 14,849 |
| Deferred income taxes | (3,883) | | | 3,485 | | | (2,430) | |
| Equity in losses of investment | 3,918 |
| | 2,368 |
| | 2,166 |
| |
| (Gain) loss on disposition of assets, net | (146 | ) | | 39 |
| | (1,290 | ) | |
| Loss on extinguishment of long-term debt | 1,183 |
| | 397 |
| | 3,540 |
| |
| Unrealized (gains) losses and ineffectiveness on derivative contracts, net | (2,324 | ) | | (4,423 | ) | | (8,800 | ) | |
| Changes in operating assets and liabilities: | |
| | |
| | |
| |
| Equity in (earnings) losses of investment | | Equity in (earnings) losses of investment | (216) | | | (1,439) | | | 3,918 | |
| Gain on disposition of assets, net | | Gain on disposition of assets, net | (889) | | | 0 | | | (146) | |
| (Gain) loss on extinguishment of long-term debt | | (Gain) loss on extinguishment of long-term debt | (9,239) | | | 18 | | | 1,183 | |
| Unrealized gain on derivative contracts, net | | Unrealized gain on derivative contracts, net | (601) | | | (3,383) | | | (2,324) | |
| Unrealized foreign currency (gain) loss | | Unrealized foreign currency (gain) loss | (2,665) | | | (628) | | | 1,466 | |
| Changes in operating assets and liabilities, net of acquisitions: | | Changes in operating assets and liabilities, net of acquisitions: | | | | | |
| Accounts receivable, net | 20,920 |
| | (28,424 | ) | | (22,437 | ) | Accounts receivable, net | (8,419) | | | (3,050) | | | 20,920 | |
| Income tax receivable, net of income tax payable | | Income tax receivable, net of income tax payable | (22,124) | | | (4,456) | | | 964 | |
| Other current assets | (9,904 | ) | | (15,680 | ) | | (2,386 | ) | Other current assets | (28,664) | | | 25,383 | | | (9,904) | |
| Income tax payable | 964 |
| | 3,949 |
| | (4,571 | ) | |
| | Accounts payable and accrued liabilities | (352 | ) | | 33,381 |
| | (630 | ) | Accounts payable and accrued liabilities | 10,830 | | | (31,265) | | | (1,818) | |
| Other non-current, net | 26,543 |
| | (45,900 | ) | | (39,076 | ) | |
| Other, net | | Other, net | (14,521) | | | (6,743) | | | 26,543 | |
| Net cash provided by operating activities | 196,744 |
| | 51,638 |
| | 38,714 |
| Net cash provided by operating activities | 98,800 | | | 169,669 | | | 196,744 | |
| | | | | | | | | | | | |
| Cash flows from investing activities: | |
| | |
| | |
| Cash flows from investing activities: | | | | | |
| Capital expenditures | (137,083 | ) | | (231,127 | ) | | (186,487 | ) | Capital expenditures | (20,244) | | | (140,854) | | | (137,083) | |
| Distributions from equity investment | — |
| | — |
| | 1,200 |
| |
| Proceeds from sale of equity investment | — |
| | — |
| | 25,000 |
| |
| STL acquisition, net | | STL acquisition, net | 0 | | | (4,081) | | | 0 | |
| Proceeds from sale of assets | 25 |
| | 10,000 |
| | 13,177 |
| Proceeds from sale of assets | 963 | | | 2,550 | | | 25 | |
| Other | 1,044 |
| | — |
| | — |
| Other | 0 | | | 0 | | | 1,044 | |
| Net cash used in investing activities | (136,014 | ) | | (221,127 | ) | | (147,110 | ) | Net cash used in investing activities | (19,281) | | | (142,385) | | | (136,014) | |
| | | | | | | | | | | | |
| Cash flows from financing activities: | |
| | |
| | |
| Cash flows from financing activities: | | | | | |
| Issuance of convertible senior notes | 125,000 |
| | — |
| | 125,000 |
| |
| Repurchase of convertible senior notes | (60,365 | ) | | — |
| | (138,401 | ) | |
| | Proceeds from convertible senior notes | | Proceeds from convertible senior notes | 200,000 | | | 0 | | | 125,000 | |
| Repayment of convertible senior notes | | Repayment of convertible senior notes | (183,150) | | | 0 | | | (60,365) | |
| Proceeds from term loan | — |
| | 100,000 |
| | — |
| Proceeds from term loan | 0 | | | 35,000 | | | 0 | |
| Repayment of term loans | (63,807 | ) | | (194,758 | ) | | (62,742 | ) | Repayment of term loans | (3,500) | | | (35,442) | | | (63,807) | |
| Repayment of Nordea Q5000 Loan | (35,714 | ) | | (35,715 | ) | | (35,714 | ) | Repayment of Nordea Q5000 Loan | (35,714) | | | (35,714) | | | (35,714) | |
| Repayment of MARAD Debt | (6,532 | ) | | (6,222 | ) | | (5,926 | ) | Repayment of MARAD Debt | (7,200) | | | (6,858) | | | (6,532) | |
| Capped call transactions | | Capped call transactions | (10,625) | | | 0 | | | 0 | |
| Debt issuance costs | (3,867 | ) | | (3,717 | ) | | (4,655 | ) | Debt issuance costs | (7,747) | | | (1,586) | | | (3,867) | |
| Net proceeds from issuance of common stock | — |
| | 219,504 |
| | 96,547 |
| |
| | Payments related to tax withholding for share-based compensation | (1,407 | ) | | (2,042 | ) | | (341 | ) | Payments related to tax withholding for share-based compensation | (5,264) | | | (1,680) | | | (1,407) | |
| Proceeds from issuance of ESPP shares | 506 |
| | 432 |
| | 708 |
| Proceeds from issuance of ESPP shares | 622 | | | 462 | | | 506 | |
| Net cash provided by (used in) financing activities | (46,186 | ) | | 77,482 |
| | (25,524 | ) | |
| Net cash used in financing activities | | Net cash used in financing activities | (52,578) | | | (45,818) | | | (46,186) | |
| | | | | | | | | | | | |
| Effect of exchange rate changes on cash and cash equivalents | (1,677 | ) | | 1,952 |
| | (3,625 | ) | |
| Net increase (decrease) in cash and cash equivalents | 12,867 |
| | (90,055 | ) | | (137,545 | ) | |
| Cash and cash equivalents: | |
| | |
| | |
| |
| Effect of exchange rate changes on cash and cash equivalents and restricted cash | | Effect of exchange rate changes on cash and cash equivalents and restricted cash | 1,818 | | | 1,636 | | | (1,677) | |
| Net increase (decrease) in cash and cash equivalents and restricted cash | | Net increase (decrease) in cash and cash equivalents and restricted cash | 28,759 | | | (16,898) | | | 12,867 | |
| Cash and cash equivalents and restricted cash: | | Cash and cash equivalents and restricted cash: | | | | | |
| Balance, beginning of year | 266,592 |
| | 356,647 |
| | 494,192 |
| Balance, beginning of year | 262,561 | | | 279,459 | | | 266,592 | |
| Balance, end of year | $ | 279,459 |
| | $ | 266,592 |
| | $ | 356,647 |
| Balance, end of year | $ | 291,320 | | | $ | 262,561 | | | $ | 279,459 | |
The accompanying notes are an integral part of these consolidated financial statements.
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization
Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix Energy Solutions Group, Inc. and its subsidiaries (“Helix” or the “Company”). We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We provide services primarily in deepwater in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions.
Our Operations
We seek to provide services and methodologies that we believe are critical to maximizing production economics. Our “life of field” services are segregated into three3 reportable business segments: Well Intervention, Robotics and Production Facilities (Note 13)15).
Our Well Intervention segment includes our vessels andand/or equipment used to performaccess offshore wells for the purpose of performing well intervention servicesenhancement or decommissioning operations primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our well intervention vessels include the Q4000, the Q5000, the SeawellQ7000, the Seawell, the Well Enhancer, and two2 chartered monohull vessels, the Siem Helix1 and the Siem Helix2. We also have a semi-submersible well intervention vessel under completion, the Q7000. Our well intervention equipment includes intervention riser systems (“IRSs”), subsea intervention lubricators (“SILs”) and the Riserless Open-water Abandonment Module (“ROAM”), some of which we provide on a stand-alone basis, and subsea intervention lubricators (“SILs”).basis.
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills,a ROVDrill, which are designed to complement offshore construction and well intervention services and three ROVoffshore construction to both the oil and gas and the renewable energy markets globally. Our Robotics segment also includes 2 robotics support vessels under long-term charter:charter, the Grand Canyon, the Grand Canyon II, and the Grand CanyonIII. We also utilize, as well as spot vessels as needed. We returned the Deep Cygnus to its owner during the first quarter of 2018.
Our Production Facilities segment includes the Helix ProducerI (the “HP I”), a ship-shaped dynamically positioned floating production vessel, and the Helix Fast Response System (the “HFRS”), which combinesand our HP I, Q4000ownership of oil and Q5000 vessels with certain well control equipment that can be deployed to respond to a well control incidentgas properties. All of our current Production Facilities activities are located in the Gulf of Mexico. On January 16, 2019, we renewed the agreements that provide various operators with access to the HFRS for well control purposes through March 31, 2020. These agreements automatically renew on an annual basis absent proper notice of termination by one of the parties. 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. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) (Note 5). On January 18, 2019, we purchased from Marathon Oil Corporation (“Marathon Oil”) certain operating depths associated with the Droshky Prospect on offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure. As part of the transaction, Marathon Oil will pay us certain agreed upon amounts for the required plug and abandonment of the acquired assets, which we can perform as our schedules permit subject to regulatory timelines. There also is a limited amount of production associated with two wells that were acquired as part of the transaction.
Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of majority ownedour 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.
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.
AccountsRestricted Cash
We classify cash as restricted when there are legal or contractual restrictions for its withdrawal. We had no restricted cash as of December 31, 2020. As of December 31, 2019, we had restricted cash of $54.1 million, which served as collateral for a letter of credit and Noteswas restricted for less than one year. In January 2021, we reclassified $73.4 million to restricted cash, which serves as collateral for a letter of credit for a temporary importation permit for work offshore Nigeria that is expected to be less than one year.
Accounts Receivable and Allowance for Uncollectible AccountsCredit Losses
Accounts and notesreceivable are recognized when our right to consideration becomes unconditional. Accounts receivable are stated at the historical carrying amount, net of write-offs and allowance for uncollectible accounts.credit losses. We establish an allowance for uncollectibleestimate current expected credit losses on our accounts receivable at each reporting date. We estimate current expected credit losses based on historical experience as well as any specific collection issues that we have identified.our credit loss history, adjusted for current factors including global economic and business conditions, offshore energy industry and market conditions, customer mix, contract payment terms and past due accounts receivable. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will not be collected (Note 16)19).
Property and Equipment
Property and equipment is recorded at historical cost.cost, net of accumulated depreciation. Property and equipment is depreciated on a straight-line basis over theits estimated useful life of an asset.life. The cost of improvements is capitalized whereas the cost of repairs and maintenance is expensed as incurred. For the years ended December 31, 2018, 2017 and 2016, repair and maintenance expense totaled $27.3 million, $28.1 million and $25.5 million, respectively.
Assets used in operations are assessed for impairment whenever events or changes in facts and 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 upon review, the sumcarrying amount of undiscounted future cash flows expected to be generated by the asset or asset group is less than its carrying amountnot recoverable and the carrying amount 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 groupedevaluated 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,spending, considering all available information at the date of review. 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. These fair value measurements fall within Level 3 of the fair value hierarchy.
Assets are classified as held for sale when a formal plan to dispose of the assets exists and those assets meet the held for sale criteria. Assets held for sale are reviewed for potential loss on sale when we commit to a plan to sell and thereafter while those assets are held for sale. Losses are measured as the difference between an asset’s fair value less costs to sell and the asset’s carrying amount. Estimates of anticipated sales prices are judgmental and subject to revision in future periods, although initial estimates are typically based on sales prices for similar assets and other valuation data.
Capitalized Interest
Interest from external borrowings is capitalized on major projects under development until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset. Capitalized interest is excluded from our interest expense (Note 6).8) and is included as an investing cash outflow in the consolidated statements of cash flows.
Equity Investment
With respect to our investment accounted for using the equity method of accounting, in the event we incur losses in excess of the carrying amount of our equity investment and reduce our investment balance to zero, we would not record additional losses unlessare 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 resultingLosses in a negativeexcess of the carrying amount of our equity method investment which isare presented as a liability.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 previously had $45.1 millionhave 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 relatedat least annually as of November 1 or more frequently whenever events or circumstances occur indicating that goodwill might be impaired. Our goodwill balance attributable to our robotics reporting unit. Asthe acquisition of a result of our 2016 goodwill impairment analysis,controlling interest in Subsea Technologies Group Limited (“STL”) was fully impaired during 2020, and we recorded an impairment charge to write off the entire goodwill balance. We had no goodwill remaining on ourin the accompanying consolidated balance sheetssheet at December 31, 2018 and 2017.2020 (Note 7).
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. In addition, routine repairs and maintenance are performed, and at times, major replacements and improvements may also be made. We expense routine repairs and maintenance costs as they are incurred. We defer and amortize recertification costs, including vessel dry dock costs, over the length of time for which we expect to receive benefits fromperiod that the recertification,certification applies, which generally ranges from 30 to 60 months if the appropriate permitting is obtained. A recertification process, including vessel dry dock, typically lasts between one to three months, a period during which a vessel or 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.
As of December 31, 20182020 and 2017,2019, deferred recertification and dry dock costs, which were included within “Other assets, net” in the accompanying consolidated balance sheets (Note 3), totaled $8.5$21.5 million and $12.8$16.1 million (net of accumulated amortization of $15.4$21.8 million and $7.3$15.7 million), respectively. During the years ended December 31, 2018, 20172020, 2019 and 2016,2018, amortization expense related to deferred recertification and dry dock costs was $8.3$14.3 million, $7.0$12.4 million and $14.0$8.3 million, respectively.
Revenue Recognition
Revenue from Contracts with Customers
We generate revenue in our Well Intervention segment by supplying vessels, personnel, and equipment to provide well intervention services, which involve providing marine access, serving as a deployment mechanism to the subsea well, connecting to and maintaining a secure connection to the subsea well and maintaining well control through the duration of the intervention services. We may also perform down-hole intervention work and provide certain engineering services. We generate revenue in our Robotics segment by operating ROVs, trenchers and ROVDrillsa 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.markets. We also provide integrated robotic services by supplying vessels that deploy the ROVs and trenchers. Our Production Facilities segment generates revenue by providingsupplying vessels, personnel vessel and equipment for oil and natural gas processing, as well as well control response services.services, and oil and gas production from owned properties.
Our revenues are derived from short-term and long-term service contracts with customers. Our service contracts generally contain either provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We record revenues net of taxes collected from customers and remitted to governmental authorities. Contracts are classified as long-term if all or part of the contract is to be performed over a period extending beyond 12 months from the effective date of the contract. Long-term contracts may include multi-year agreements whereby the commitment for services in any one year may be short in duration.
We generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration for these activities as well asreceived under a contract fulfillment activities 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 generally 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. The estimated amount ofEstimated variable consideration, if any, is considered to be constrained and therefore is onlynot included in the transaction price to the extent thatuntil 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). The invoicesInvoices 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 andand/or demobilizing equipment and personnel. Mobilization and demobilization fees are associated withconsidered contract fulfillment activities, and related revenuefees (subject to any constraint on estimates of variable consideration) isare allocated to the single performance obligation and recognized ratably over the initial 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. See further discussion on contract liabilities under “Contract balances” below.
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 uncertainty is resolved, which typically occurs when 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 additional 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 revenueIncome from contracts with customers upon the adoption of Accounting Standards Update (“ASU”) No. 2014-09 on January 1, 2018. See “New Accounting Standards” belowOil and Note 10 for additional disclosures.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 areis recognized according to our share of monthly oil and gas production on an entitlement basis. Income for royalty interestsvolumes and is reflected in “Other“Royalty income - oil and gas”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.
It is our policy toWe provide for uncertain tax positions and the 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 taxlocal taxing authorities. At December 31, 2018,2020, 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 establishedhas been recognized 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.
The estimated fair value of performance share units (“PSUs”) is determined using a Monte Carlo simulation model. Compensation cost for PSUs thatour performance share unit (“PSU”) awards, which have a service condition and a market condition and are accounted for as equity awards, is measured based on the estimated grant date estimated 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 theeach balance sheet date, and subsequent changes in fair value of the awards are recognized in earnings.earnings for the portion of the award for which the requisite service period has elapsed. Cumulative compensation cost for vested liability PSU awards equals the actual payout value upon vesting. To the extent the recognized
Asset Retirement Obligations
Asset retirement obligations (“AROs”) are recorded at fair value and consist of the modified liability awards at the end of a reporting period is less than the compensation costestimated costs for subsea infrastructure plug and abandonment (“P&A”) activities associated with our oil and gas properties. The estimated costs are discounted to present value using a credit-adjusted risk-free discount rate. After its initial recognition, an ARO liability is increased for the grant date fair valuepassage 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 original equity awards, the higher amount is recorded as share-based compensation. The amount of cumulative compensation cost recognized in excess of the fair value of the modified liability awards is recorded in equity.obligations.
Foreign Currency
Because we operate in various regions around the world, we conduct a portion of our business in currencies other than the U.S. dollar. Results of operations for our non-U.S. dollar subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these non-U.S. dollar subsidiaries are translated into U.S. dollars using the exchange rate in effect, at December 31, 2018 and 2017, and the resulting translation adjustments which were unrealized gains (losses) of $(7.2) million and $16.3 million, respectively, 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, 2018, 20172020, 2019 and 2016,2018, our foreign currency transaction gains (losses) totaled $(4.3)$4.6 million, $(2.2)$1.5 million and $0.2$(4.3) 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 hedgemitigate 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 certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. AllInterest rate and foreign currency derivative instruments are reflected in the accompanying consolidated balance sheets at fair value. The capped call transactions (the “2026 Capped Calls”) we entered into in connection with the issuance of Convertible Senior Notes Due 2026 are recorded in shareholders’ equity and are not accounted for as derivatives (Note 8).
We engage solely in cash flow hedges. Cash flow hedges are entered into to hedge the variability of cash flows related to a forecasted transaction or to be received or paid related to a recognized asset or liability. Changes in the fair value of derivative instruments that are designated as cash flow hedges are reported in OCI to the extent that the hedges are effective.OCI. These changes are subsequently reclassified into earnings when the hedged transactions settle. The ineffective portion of changesaffect earnings. Changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change in the fair value of ainterest rate and foreign currency derivative instrumentinstruments that doesdo not qualify for hedge accounting isare recorded in earnings in the period in which the change occurs.earnings.
We formally document all relationships between hedging instruments and the related hedged items, as well as our risk management objectives, strategies for undertaking various hedge transactions and our methods for assessing and testing correlation and hedge ineffectiveness. All hedging instruments are linked to the hedged asset, liability, firm commitment or forecasted transaction. We also assess, both at the inception of the hedge and on an on-goingongoing 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. 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. Changes in the fair value of interest rate swaps are reported in accumulated OCI to the extent the swaps are effective. These changes are subsequently reclassified into earnings when the anticipated interest is recognized as interest expense. The ineffective portion of the interest rate swaps, if any, is recognized immediately in earnings within “Net 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 our vessel charters that are denominated in foreign currencies. 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. Changes in the fair value of foreign currency exchange contracts are reported in accumulated OCI to the extent the contracts are effective. These changes are subsequently reclassified into earnings when the forecasted vessel charter payments are made and recorded as cost of sales. The ineffective portion of these foreign currency exchange contracts, if any, and 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.”
Earnings Per Share
The presentation of basicBasic earnings per share (“EPS”) amounts on the face of the accompanying consolidated statements of operations is computed by dividing net income or loss attributable to common shareholders by the weighted average shares of our common stock outstanding. The calculation of diluted EPS is similar to that for basic EPS, except that the denominator includes dilutive common stock equivalents and the numerator excludes the effects of dilutive common stock equivalents, if any. We have shares of restricted stock issued and outstanding that are currently unvested. HoldersBecause 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 shares of restricted stock are thus considered participating securities.two-class method in periods in which we have earnings. Under applicable accounting guidance,the two-class method, the undistributed earnings available to common shareholders 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 both the liquidation and dividend rights are identical, the undistributed earnings are allocated on a proportionate basis. Further, we are required to compute EPS under the two class method in periods in which we have earnings. For periods in which we have a net loss we do not use the two classtwo-class method as holders of our restricted shares are not obligated to share in such losses.
Major Customers and Concentration of Credit Risk
The market forWe offer our products and services is primarily in the offshore oil and gas and renewable industries.markets. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and gas prices and volatility, which are subject to many external factors that may contribute to significant volatility.factors. Our customers consist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, alternative (renewable)renewable energy companies and offshore engineering and construction firms. We perform ongoing credit evaluations of our customers and provide allowances for probable credit losses when necessary.losses. The percentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) isare as follows: 2020 — Petrobras (28%) and BP (17%); 2019 — Petrobras (29%), BP (15%) and Shell (13%); and 2018 — Petrobras (28%) and BP (15%), 2017 — BP (19%), Petrobras (13%) and Talos (10%), and 2016 — BP (17%) and Shell (11%). Most of the concentration of revenues was generated byare in our Well Intervention business.segment.
Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:
•Level 1. Observable inputs such as quoted prices in active markets;
•Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and
•Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.
Assets and liabilities measured at fair value are based on one or more of three valuation approaches as described in Note 17.20.
New Accounting Standards
New accounting standards adopted
In May 2014,February 2016, the Financial Accounting Standards Board (the “FASB”) issued ASUAccounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606)” (“ASC 606”). The FASB also issued several subsequent updates to promote more consistent interpretation and application of the principles outlined in the standard. ASC 606 provides a five-step approach to account for revenue arising from contracts with customers in order for an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.
We adopted ASC 606 effective January 1, 2018 using the modified retrospective method by applying the five-step model to all contracts that were not completed as of the date of adoption. For contracts that were modified before the date of adoption, we have considered the modification guidance within the new standard and determined that the revenues recognized prior to adoption for such modified contracts were not impacted. We did not record any cumulative effect adjustment to the opening balance of our retained earnings as of January 1, 2018 as the adoption of ASC 606 had an insignificant impact on our prior year earnings. On our consolidated balance sheet, contract assets that were previously presented as “Other accounts receivable” are now a component of “Other current assets.” The comparative information is not being restated and continues to be reported under the accounting standards in effect for those periods. ASC 606 requires additional disclosures with regard to the nature, amount, timing and uncertainty of revenue and cash flows arising from contracts with customers. We do not expect the adoption of this guidance to have a material impact on the measurement or recognition of our revenues on an ongoing basis. The impact of ASC 606 for the year ended December 31, 2018 is as follows (in thousands):
|
| | | | | | | | | | | |
| | December 31, 2018 |
| | As Reported | | Pro Forma Without Adoption of ASC 606 | | Effect of Change |
| Balance Sheet | | | | | |
| Assets | | | | | |
| Unbilled and other | $ | 51,943 |
| | $ | 57,772 |
| | $ | (5,829 | ) |
| Other current assets | 51,594 |
| | 45,765 |
| | 5,829 |
|
| Liabilities | | | | | |
| Accrued liabilities | 85,594 |
| | 85,491 |
| | 103 |
|
| Deferred tax liabilities | 105,862 |
| | 105,884 |
| | (22 | ) |
| Equity | | | | | |
| Retained earnings | 383,034 |
| | 383,115 |
| | (81 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, 2018 |
| | As Reported | | Pro Forma Without Adoption of ASC 606 | | Effect of Change |
| Statement of Operations | | | | | |
| Net revenues | $ | 739,818 |
| | $ | 739,921 |
| | $ | (103 | ) |
| Income from operations | 51,543 |
| | 51,646 |
| | (103 | ) |
| Income before income taxes | 30,998 |
| | 31,101 |
| | (103 | ) |
| Income tax provision | 2,400 |
| | 2,422 |
| | (22 | ) |
| Net income | 28,598 |
| | 28,679 |
| | (81 | ) |
In February 2018, the FASB issued ASU No. 2018-02, “Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income.” This ASU allows a reclassification from accumulated OCI to retained earnings for stranded tax effects resulting from the U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”) that was enacted on December 22, 2017. We adopted this guidance as of January 1, 2018 by making the election to reclassify $1.5 million of net stranded tax benefits from accumulated OCI to retained earnings (Note 8). On an ongoing basis, we release the income tax effects of individual items in accumulated OCI as those items are sold or settled at the applicable statutory rate.
New accounting standards issued but not yet effective
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic842)” (“ASC842”). The FASB also issued several, which was updated by subsequent updates to the new guidance. The new guidanceamendments. ASC842 requires a lessee to recognize a lease right-of-useROU asset and related lease liability for most leases, including those classified as operating leases under current GAAP.leases. ASC 842 also changes the definition of a lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. Management’s assessment based on our current portfolioWe adopted ASC842 as of leases (a significant componentJanuary 1, 2019 using the modified retrospective method. We also elected the package of which is our vessel charters) ispractical expedients permitted under the transition guidance that, our assets and liabilities will increase between $250 and $270 million upon ouramong other things, allows companies to carry forward their historical lease classification. Our adoption of ASC 842.842 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 oura 2016 sale and leaseback transaction of $5.1 million (Notes 3 and 4) will be reclassified to retained earnings and no longer amortized into earnings. Additionally,Subsequent to adoption, leases in foreign currencycurrencies will generate foreign currency gains and losses, that would not have been reported under legacy GAAP.and we will no longer amortize the deferred gain from the aforementioned sale and leaseback transaction. Aside from these changes, we doASC842 has not expect the new guidancehad, and is not expected to have, a significantmaterial impact on our net earnings or cash flows. We will adopt ASC 842 by applying the new guidance in the first quarter of 2019 and recognizing a cumulative-effect adjustment to the opening balance of retained earnings on January 1, 2019.See Note 6 for additional information regarding our leases.
In June 2016, the FASB issued ASU No.2016-13, “Measurement of Credit Losses on Financial Instruments.Instruments,” which was updated by subsequent amendments. This ASU replaces the current incurred loss model for measurement of credit losses on financial assets including(including trade receivablesreceivables) with a forward-looking expected loss model based on historical experience, current conditions, and reasonable and supportable forecasts. Upon adoption of ASU No.2016-13 on January 1, 2020, we recognized $0.6 million (net of deferred taxes of $0.2 million) related to the provision for current expected credit losses on our accounts receivable through a cumulative effect offset to retained earnings. The guidancecredit loss standard also resulted in the recognition of an additional $0.7 million in credit loss reserves on our accounts receivable for the year ended December 31, 2020. See Note 19 for additional information regarding allowance for credit losses on our accounts receivable.
New accounting standards issued but not yet effective
In August 2020, the FASB issued ASU No.2020-06, “Accounting for Convertible Instruments and Contracts in an Entity's Own Equity,” which simplifies the accounting for certain financial instruments with characteristics of liabilities and equity, including convertible instruments and contracts in an entity’s own equity. Among other changes, this ASU removes from GAAP the requirement to separate certain convertible instruments, such as our Convertible Senior Notes Due 2022, Convertible Senior Notes Due 2023 and Convertible Senior Notes Due 2026 (Note 8), into liability and equity components. Consequently, those convertible instruments will be accounted for in their entirety as liabilities measured at their amortized cost. We have elected to early adopt ASU No.2020-06 on a modified retrospective basis as of January 1, 2021. The adoption of this ASU will increase our long-term debt and decrease common stock by approximately $44.1 million and$41.5 million,respectively, as we reclassify the conversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of this ASU will also increase our retained earnings and decrease deferred tax liabilities by approximately $6.7 million and $9.3 million, respectively. The embedded conversion feature will no longer be amortized into income as interest expense over the life of the instrument. Subsequent to its adoption, the ASU is effectivealso expected to reduce our interest expense as there will no longer be debt discounts associated with our outstanding convertible senior notes. Additionally, the ASU no longer permits the treasury stock method for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluatingconvertible instruments and instead requires the application of the if-converted method to calculate the impact this guidance will haveof our convertible senior notes on our consolidated financial statements.diluted EPS.
We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.
Note 3 — Details of Certain Accounts
Other current assets consist of the following (in thousands):
| | | | | | | | December 31, |
| | December 31, | | 2020 | | 2019 |
| | 2018 | | 2017 | | | | |
| | | | | |
| Contract assets (Note 10) | $ | 5,829 |
| | $ | — |
| |
| Contract assets (Note 12) | | Contract assets (Note 12) | $ | 2,446 | | | $ | 740 | |
| Prepaids | 10,306 |
| | 10,102 |
| Prepaids | 15,904 | | | 12,635 | |
| Deferred costs (Note 10) | 27,368 |
| | 27,204 |
| |
| Deferred costs (Note 12) | | Deferred costs (Note 12) | 23,522 | | | 28,340 | |
| Income tax receivable (Note 9) | | Income tax receivable (Note 9) | 20,787 | | | 1,261 | |
| Other receivable (Note 16) | | Other receivable (Note 16) | 29,782 | | | 0 | |
| Other | 8,091 |
| | 4,462 |
| Other | 9,651 | | | 7,474 | |
| Total other current assets | $ | 51,594 |
| | $ | 41,768 |
| Total other current assets | $ | 102,092 | | | $ | 50,450 | |
Other assets, net consist of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| | | |
| Deferred recertification and dry dock costs, net (Note 2) | $ | 21,464 | | | $ | 16,065 | |
| Deferred costs (Note 12) | 861 | | | 14,531 | |
Charter deposit (1) | 12,544 | | | 12,544 | |
| Other receivable (Note 16) | 0 | | | 27,264 | |
| Goodwill (Note 7) | 0 | | | 7,157 | |
| Intangible assets with finite lives, net (Note 2) | 3,809 | | | 3,847 | |
| Other | 1,335 | | | 3,100 | |
| Total other assets, net | $ | 40,013 | | | $ | 84,508 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
Note receivable, net (1) | $ | — |
| | $ | 3,758 |
|
| Prepaids | 5,896 |
| | 7,666 |
|
| Deferred recertification and dry dock costs, net (Note 2) | 8,525 |
| | 12,769 |
|
| Deferred costs (Note 10) | 38,574 |
| | 63,767 |
|
Charter fee deposit (2) | 12,544 |
| | 12,544 |
|
| Other | 4,518 |
| | 4,701 |
|
| Total other assets, net | $ | 70,057 |
| | $ | 105,205 |
|
| |
(1) | The amount at December 31, 2017 reflects the fair value of a note receivable that was issued to us by a customer as part of a payment forgiveness arrangement. On July 6, 2018, a third party acquired this note receivable for $2.0 million. During the year ended December 31, 2018, we reversed a $0.6 million unrealized gain previously recorded in accumulated OCI and recorded a $1.1 million other than temporary loss to account for the reduction in the fair value of our note receivable. |
| |
(2) | This amount was deposited with the vessel owner and is to be used to reduce our final charter payments for the Siem Helix2.
|
Accrued liabilities consist of the following (in thousands):
| | | | December 31, | | December 31, |
| | 2018 | | 2017 | | 2020 | | 2019 |
| | | | | | | | |
| Accrued payroll and related benefits | $ | 43,079 |
| | $ | 30,685 |
| Accrued payroll and related benefits | $ | 24,768 | | | $ | 31,417 | |
| Deferred revenue (Note 10) | 10,103 |
| | 12,609 |
| |
| Derivative liability (Note 18) | 9,311 |
| | 10,625 |
| |
| Accrued interest | | Accrued interest | 7,098 | | | 3,942 | |
| Investee losses in excess of investment (Note 5) | | Investee losses in excess of investment (Note 5) | 1,499 | | | 4,069 | |
| Deferred revenue (Note 12) | | Deferred revenue (Note 12) | 8,140 | | | 11,568 | |
| AROs (Note 16) | | AROs (Note 16) | 30,913 | | | 0 | |
| | Other | 23,101 |
| | 17,761 |
| Other | 14,617 | | | 11,393 | |
| Total accrued liabilities | $ | 85,594 |
| | $ | 71,680 |
| Total accrued liabilities | $ | 87,035 | | | $ | 62,389 | |
Other non-current liabilities consist of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| | | |
| | | |
| Deferred revenue (Note 12) | $ | 1,869 | | | $ | 8,286 | |
| AROs (Note 16) | 0 | | | 28,258 | |
| | | |
| Other | 2,009 | | | 2,100 | |
| Total other non-current liabilities | $ | 3,878 | | | $ | 38,644 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Investee losses in excess of investment (Note 5) | $ | 6,035 |
| | $ | 7,567 |
|
| Deferred gain on sale of property (Note 4) | 5,052 |
| | 5,838 |
|
| Deferred revenue (Note 10) | 15,767 |
| | 8,744 |
|
| Derivative liability (Note 18) | 884 |
| | 8,150 |
|
| Other | 11,800 |
| | 10,391 |
|
| Total other non-current liabilities | $ | 39,538 |
| | $ | 40,690 |
|
Note 4 — Property and Equipment
The following is a summary of the gross components of property and equipment (dollars in thousands):
| | | | | December 31, | | December 31, |
| | Estimated Useful Life | | 2018 | | 2017 | | Estimated Useful Life | | 2020 | | 2019 |
| | | | | | | | | | | |
| Vessels | 15 to 30 years | | $ | 2,185,409 |
| | $ | 2,083,267 |
| Vessels | 15 to 30 years | | $ | 2,349,752 | | | $ | 2,323,314 | |
| ROVs, trenchers and ROVDrills | 10 years | | 284,172 |
| | 298,227 |
| |
| ROVs, trenchers and ROVDrill | | ROVs, trenchers and ROVDrill | 10 years | | 263,968 | | | 270,004 | |
| Machinery, equipment and leasehold improvements | 5 to 15 years | | 316,197 |
| | 314,278 |
| Machinery, equipment and leasehold improvements | 5 to 15 years | | 335,187 | | | 328,956 | |
| Total property and equipment | | $ | 2,785,778 |
| | $ | 2,695,772 |
| Total property and equipment | | $ | 2,948,907 | | | $ | 2,922,274 | |
In January 2016, we sold our office and warehouse property located in Aberdeen, Scotland for approximately $11 million and entered into a separate agreement with the same party to lease back the facility for a lease term of 15 years with two five-year options to extend the lease at our option. A gain of approximately $7.6 million from the sale of this property is deferred and amortized over the 15-year minimum lease term. See Note 2 for the effect of the adoption of ASC 842 on this deferred gain.
In December 2016, we sold the Helix534 vessel to a third party for approximately $2.8 million, including $0.4 million held in escrow, which was not subsequently realized. We recorded a gain of approximately $1.3 million from the sale, net of selling expenses.
Note 5 — Equity Method Investments
We have a 20% ownership interest in Independence Hub, LLC (“Independence Hub”) that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform, located in Mississippi Canyon Block 920 inwhich is nearing the U.S. Gulfcompletion of Mexico in a water depth of 8,000 feet. Since we are committed to providing our pro-rata portion of the necessary level of financial support for Independence Hub to pay its obligations as they become due, we recorded adecommissioning. The remaining liability of $11.2 million and $9.8 million at December 31, 2018 and 2017, respectively,balances for our share of theIndependence Hub’s estimated obligations, net of remaining working capital. This liability is reflected in “Accrued liabilities”capital, were $1.5 million and “Other non-current liabilities”$4.1 million at December 31, 2020 and 2019, respectively.
Note 6 — Leases
We charter vessels and lease facilities and equipment under non-cancelable contracts that expire on various dates through 2031. We also sublease some of our facilities under non-cancelable sublease agreements. As of December 31, 2020, the minimum sublease income to be received in the accompanying consolidated balance sheets. future totaled $2.1 million.
The following table details the components of our lease cost in 2020 and 2019 (in thousands):
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
| | | |
| Operating lease cost | $ | 64,742 | | | $ | 70,860 | |
| Variable lease cost | 15,021 | | | 13,780 | |
| Short-term lease cost | 37,524 | | | 20,384 | |
| Sublease income | (1,286) | | | (1,391) | |
| Net lease cost | $ | 116,001 | | | $ | 103,633 | |
For the yearsyear ended December 31, 2018, 2017 and 2016, we recorded losses totaling $3.9 million, $2.4total rental expense was approximately $147.8 million and $2.2 million, respectively, to account for our share of losses from Independence Hub. We did not receive any cash distributions from Independence Hub in 2016, 2017 or 2018.total sublease rental income was $1.4 million.
Maturities of our operating lease liabilities as of December 31, 2020 are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Vessels | | Facilities and Equipment | | Total |
| | | | | |
| Less than one year | $ | 54,621 | | | $ | 6,028 | | | $ | 60,649 | |
| One to two years | 52,106 | | | 5,435 | | | 57,541 | |
| Two to three years | 34,580 | | | 4,649 | | | 39,229 | |
| Three to four years | 2,470 | | | 4,374 | | | 6,844 | |
| Four to five years | 0 | | | 2,340 | | | 2,340 | |
| Over five years | 0 | | | 4,054 | | | 4,054 | |
| Total lease payments | $ | 143,777 | | | $ | 26,880 | | | $ | 170,657 | |
| Less: imputed interest | (13,352) | | | (4,697) | | | (18,049) | |
| Total operating lease liabilities | $ | 130,425 | | | $ | 22,183 | | | $ | 152,608 | |
| | | | | |
| Current operating lease liabilities | $ | 46,748 | | | $ | 4,851 | | | $ | 51,599 | |
| Non-current operating lease liabilities | 83,677 | | | 17,332 | | | 101,009 | |
| Total operating lease liabilities | $ | 130,425 | | | $ | 22,183 | | | $ | 152,608 | |
Maturities of our operating lease liabilities as of December 31, 2019 are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Vessels | | Facilities and Equipment | | Total |
| | | | | |
| Less than one year | $ | 60,210 | | | $ | 6,610 | | | $ | 66,820 | |
| One to two years | 54,564 | | | 5,888 | | | 60,452 | |
| Two to three years | 52,106 | | | 5,257 | | | 57,363 | |
| Three to four years | 34,580 | | | 4,622 | | | 39,202 | |
| Four to five years | 2,470 | | | 4,349 | | | 6,819 | |
| Over five years | 0 | | | 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:
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| Weighted average remaining lease term | 3.1 years | | 4.0 years |
| Weighted average discount rate | 7.53 | % | | 7.54 | % |
The following table presents other information related to our operating leases (in thousands):
| | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 |
| | | |
| Cash paid for operating lease liabilities | $ | 66,026 | | | $ | 71,698 | |
| ROU assets obtained in exchange for new operating lease obligations | 516 | | | 1,168 | |
Note 7 — Business Combinations and Goodwill
In May 2019, we acquired a 50% ownership70% controlling interest in Deepwater Gateway,STL, a subsea engineering firm based in Aberdeen, Scotland, for $5.1 million. The holders of the ownerremaining 30% noncontrolling interest currently have the right to put their shares to us in June 2024. These redeemable noncontrolling interests have been recognized as temporary equity. STL is included in our Well Intervention segment (Note 15) and its revenue and earnings are immaterial to our consolidated results.
As a result of the decline in oil prices as well as energy and energy services valuations during the first quarter 2020 due to the ongoing COVID-19 pandemic and the OPEC+ price war, we impaired all of our goodwill, which consisted entirely of our goodwill in STL.
The changes in the carrying amount of goodwill are as follows (in thousands):
| | | | | |
| Well Intervention |
| |
| Balance at December 31, 2018 | $ | 0 | |
Additions (1) | 6,855 | |
| |
Other adjustments (2) | 302 | |
| Balance at December 31, 2019 | 7,157 | |
| |
Other adjustments (2) | (468) | |
Impairment loss (3) | (6,689) | |
| |
| Balance at December 31, 2020 | $ | 0 | |
(1)Relates to goodwill arising from the acquisition of a tension leg platform production hub primarily for Anadarko Petroleum Corporation’s Marco Polofield in the Deepwater Gulf of Mexico. In February 2016, we received a cash distribution of $1.2 million and sold our ownershipcontrolling interest in Deepwater Gateway for $25 million.STL in May2019.
(2)Relates to foreign currency adjustments.
(3)Relates to the impairment of the entire STL goodwill balance in March2020.
Note 68 —Long-Term Debt
Long-term debt consists of the following (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| | | |
| Term Loan (matures December 2021) | $ | 29,750 | | | $ | 33,250 | |
| 2022 Notes (mature May 2022) | 35,000 | | | 125,000 | |
| 2023 Notes (mature September 2023) | 30,000 | | | 125,000 | |
| 2026 Notes (mature February 2026) | 200,000 | | | 0 | |
| MARAD Debt (matures February 2027) | 56,410 | | | 63,610 | |
Nordea Q5000 Loan (matures January 2021) (1) | 53,572 | | | 89,286 | |
| Unamortized debt discounts | (45,692) | | | (22,540) | |
| Unamortized debt issuance costs | (9,477) | | | (7,753) | |
| Total debt | 349,563 | | | 405,853 | |
| Less current maturities | (90,651) | | | (99,731) | |
| Long-term debt | $ | 258,912 | | | $ | 306,122 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Term Loan (matures June 2020) | $ | 33,693 |
| | $ | 97,500 |
|
| 2022 Notes (mature May 2022) | 125,000 |
| | 125,000 |
|
| 2023 Notes (mature September 2023) | 125,000 |
| | — |
|
| 2032 Notes (redeemed May 2018) | — |
| | 60,115 |
|
| MARAD Debt (matures February 2027) | 70,468 |
| | 77,000 |
|
| Nordea Q5000 Loan (matures April 2020) | 125,000 |
| | 160,714 |
|
| Unamortized debt discounts | (28,802 | ) | | (14,406 | ) |
| Unamortized debt issuance costs | (10,044 | ) | | (10,296 | ) |
| Total debt | 440,315 |
| | 495,627 |
|
| Less current maturities | (47,252 | ) | | (109,861 | ) |
| Long-term debt | $ | 393,063 |
| | $ | 385,766 |
|
Credit Agreement
On June 30, 2017, we entered into an Amended and Restated Credit Agreement (theWe have a 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”). The amended and restated credit facilityCredit Agreement is comprised of a $100Term Loan with a remaining balance of $29.8 million term loan (the “Term Loan”)as of December 31, 2020 and a revolving credit facility (the “RevolvingRevolving Credit Facility”)Facility with a maximum availability of up to $150$175 million (the “Revolving Loans”).that matures on December 31, 2021. The Revolving Credit Facility permits us to obtain letters of credit up to a sublimit of $25 million. 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, additional term loans or a combination thereof. The $100 million proceeds from the Term Loan as well as cash on hand were used to repay the approximately $180 million term loan then outstanding under the credit facility prior to its June 2017 amendment and restatement.Facility. As of December 31, 2018,2020, the Term Loan is classified as current in the accompanying consolidated balance sheet. As of December 31, 2020, we had no borrowings under the Revolving Credit Facility, and our available borrowing capacity under that facility, based on the applicable leverage ratio covenant,ratios, totaled $147.4$160.2 million, net of $2.6$2.8 million of letters of credit issued under that facility.
The Term Loan andBorrowings under the Revolving Loans (together, the “Loans”),Credit Agreement bear interest, at our election, bear interest at theeither Bank of America’s base rate, tothe LIBOR or a LIBORcomparable 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 3.25%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 4.25%3.25%. The interest rate on the Term Loan was 6.77%3.40% as of December 31, 2018. The2020. Borrowings under the Revolving LoansCredit 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 1.75%1.50% to 3.25%2.50%. TheBorrowings under the Revolving LoansCredit 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 2.75%2.50% to 4.25%3.50%. A letter of credit fee is payable by us equal to itsthe applicable margin for LIBOR rate Loans timesloans multiplied by the daily amount available to be drawn under the applicable letter of credit. Margins on borrowings under the Revolving LoansCredit 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 ourthe Revolving Credit Facility.
The Term Loan principal is required to be repaid in quarterly installments totaling 5% in the first loan year, 10% in the second loan year and 15% in the third loan year,of 2.5% of its aggregate principal amount, with a balloon payment at maturity. Installment amountsInstallments are subject to adjustment for any prepayments on the Term Loan.prepayments. We may elect to 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 ofavailable under the Revolving Credit Facility. The Loans mature on June 30, 2020.
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 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 (restricted subsidiaries).
The Credit Agreement and the other loan documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, whichthat we consider customary for this type of facility.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 ratiosratio requirements of EBITDA to interest charges (“Consolidated(Consolidated Interest Coverage Ratio”) andRatio), funded debt to EBITDA (“Consolidated(Consolidated Total Leverage Ratio”),Ratio) and provided there are no Loans outstanding, thesecured funded debt ratio requirement permits us to offset a certain amount of cash against the funded debt used in the calculation (“Consolidated Net Leverage Ratio”). After the Term Loan is repaid in full, if there are any Loans outstanding, including unreimbursed draws under letters of credit issued under the Revolving Credit Facility, we also are required to ensure that the ratio of our total secured indebtedness to EBITDA (“Consolidated(Consolidated Secured Leverage Ratio”) does not exceed a maximum permitted ratio. The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness that is outstanding.Ratio).
We may from time to time 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 Unrestricted Subsidiaries are not pledged as collateral under the Credit Agreement, and 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 except forto the debt and EBITDAextent of Helix Q5000 Holdings, S.a.r.l., a wholly ownedany cash actually distributed by such subsidiary incorporatedto Helix.
In June 2019, in Luxembourg (“Q5000 Holdings”). Our obligations underconnection with an amendment of the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I - Title XI, Inc.) and by Canyon Offshore Limited,we wrote off the remaining unamortized debt issuance costs associated with a wholly owned Scottish subsidiary. Our obligations underlender exiting the Credit Agreement, and 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 Canyon Offshore Limited, and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and of Canyon Offshore Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.
Agreement. In March 2018, we prepaid $61 million of the Term Loanthen-existing term loan with a portion of the net proceeds from the 2023 Notes. We recognized aNotes and wrote off $0.9 million loss to write off the relatedof unamortized debt issuance costs. In June 2017, we recognized a $0.4 million loss to write off the unamortized debt issuance costs related to certain lenders exiting from the term loan then outstanding under our principal corporate credit facility prior to its June 2017 amendment and restatement. These losseswrite-offs are presented as “Loss on early extinguishment of long-term debt” in the accompanying consolidated statements of operations. In connection with decreases in lenders’ commitments under our revolving credit facility, in June 2017 and February 2016, we recorded interest charges of $1.6 million and $2.5 million, respectively, to accelerate the amortization of a pro-rata portion of debt issuance costs related to the lenders whose commitments were reduced.
On January 18, 2019, contemporaneously with our purchase from Marathon Oil of certain operating depths associated with the Droshky Prospect on offshore Gulf of Mexico Green Canyon Block 244, along with several wells and related infrastructure, we entered into an amendment to our Credit Agreement which permits us to issue certain security to third parties for required plug and abandonment obligations and to make certain capital expenditures in connection with the acquired assets (Note 1).
Convertible Senior Notes Due 2022 (“2022 Notes”)
On November 1, 2016, we completed a public offering and sale of our Convertible Senior Notes due 2022 (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 arewere not redeemable. On or afterBeginning 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 Indentureindenture 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 are accounted for by separatingwere initially separated between the net proceeds betweenequity component recognized in shareholders’ equity and the debt component, which is presented as long-term debt, net of the unamortized debt discount and shareholders’ equity. In connection with thedebt issuance costs.
On August 14, 2020, we repurchased $90 million in aggregate principal amount of the 2022 Notes we recorded afor $89.1 million. We applied $81.7 million of the repurchase price to the acquisition of the debt component of the 2022 Notes and recognized an extinguishment gain of $3.3 million. The remaining unamortized debt discount of the 2022 Notes was $1.3 million and $8.0 million at December 31, 2020 and 2019, respectively. We applied the remaining $7.4 million of the repurchase price to the re-acquisition of the equity component. The remaining equity component of the 2022 Notes was $9.5 million ($5.3 million net of tax) and $16.9 million ($11.0 million net of tax) as a result of separating the equity component. at December 31, 2020 and 2019, respectively.
The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that representedover the equity componentterm of the 2022 Notes at their inception.Notes. For the years ended December 31, 2018, 20172020, 2019 and 2016,2018, interest expense (including amortization of the debt discount) related to the 2022 Notes totaled $6.2 million, $8.4 million and $8.1 million, $7.9 million and $1.3 million, respectively. The remaining unamortized amountWith the adoption of the debt discount ofASU No.2020-06 beginning January 1, 2021, the 2022 Notes was $11.0 million and $13.9 millionwill no longer be reported at December 31, 2018 and 2017, respectively.a discount. See Note 2 for the effect of ASU No.2020-06.
Convertible Senior Notes Due 2023
On March 20, 2018, we completed a public offering and sale of our (“2023 Notes in the aggregate principal amount of $125 million. The net proceeds from the issuance of the 2023 Notes were approximately $121 million, after deducting the underwriters’ discounts and commissions and offering expenses. We used the net proceeds from the issuance of the 2023 Notes to fund the required repurchase of $59.3 million in principal of the 2032 Notes and to prepay $61 million of our Term Loan.Notes”)
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.
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).
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 are accounted for by separatingwere initially separated between the net proceeds betweenequity component recognized in shareholders’ equity and the debt component, which is presented as long-term debt, net of the unamortized debt discount and shareholders’ equity. In connection with thedebt issuance costs.
On August 14, 2020, we repurchased $95 million in aggregate principal amount of the 2023 Notes we recorded afor $94.1 million. We applied $78.2 million of the repurchase price to the re-acquisition of the debt component of the 2023 Notes and recognized an extinguishment gain of $5.9 million. The remaining unamortized debt discount of the 2023 Notes was $2.7 million and $14.5 million at December 31, 2020 and 2019, respectively. We applied the remaining $15.9 million of the repurchase price to the re-acquisition of the equity component. The remaining equity component of the 2023 Notes was $4.2 million ($3.6 million net of tax) and $20.1 million ($15.9 million net of tax) as a result of separating the equity component. at December 31, 2020 and 2019, respectively.
The effective interest rate for the 2023 Notes is 7.8% after considering the effect of the accretion of the related debt discount that representedover the equity componentterm of the 2023 Notes at their inception.Notes. For the yearyears ended December 31, 2020, 2019 and 2018,, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled$6.4 $6.1 million, $8.4 million and $6.4 million, respectively. With the adoption of ASU No.2020-06 beginning January 1, 2021, the 2023 Notes will no longer be reported at a discount. See Note 2 for the effect of ASU No.2020-06.
Convertible Senior Notes Due 2026 (“2026 Notes”)
On August 14, 2020, we issued $200 million in aggregate principal amount of the 2026 Notes. The net proceeds from the issuance of the 2026 Notes were approximately $192.5 million, after deducting the underwriting discounts and commissions and estimated offering expenses. As discussed further in Note 10, we used approximately $10.5 million of the net proceeds to enter into the 2026 Capped Calls. We used the remainder of the net proceeds, together with cash on hand, to repurchase $90 million in aggregate principal amount of the 2022 Notes and $95 million in aggregate principal amount of the 2023 Notes (see “Convertible Senior Notes Due 2022” and “Convertible Senior Notes Due 2023” above) in privately negotiated transactions.
The 2026 Notes bear interest at a rate of 6.75% per annum and are payable semi-annually in arrears on February15 and August15 of each year, beginning on February 15, 2021. The 2026 Notes mature on February 15, 2026 unless earlier converted, redeemed or repurchased. During certain periods and subject to certain conditions, the 2026 Notes are convertible by the holders into shares of our common stock at an initial conversion rate of 143.3795 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $6.97 per share of common stock), subject to adjustment in certain circumstances. In order to reduce the potential dilution of the 2026 Notes to shareholders’ equity, we entered into the 2026 Capped Calls, which effectively increase the conversion price of the 2026 Notes to approximately $8.42 per share. However, the 2026 Capped Calls are separate transactions from the 2026 Notes and do not change the holders’ rights under the 2026 Notes, and holders of the 2026 Notes do not have any rights with respect to the 2026 Capped Calls (Note 10). We have the right and the intention to settle the principal amount of any such future conversions in cash.
Prior to August15, 2023, the 2026 Notes are not redeemable. On or after August15, 2023, if certain conditions are met, we may redeem all or any portion of the 2026 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 2026 Notes). Holders of the 2026 Notes may require us to repurchase the notes following a “fundamental change” (as defined in the indenture governing the 2026 Notes).
The indenture governing the 2026 Notes contains customary terms and covenants, including that upon certain events of default 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 2026 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 2026 Notes together with any accrued and unpaid interest thereon will become immediately due and payable.
The 2026 Notes are separated between the equity component of $43.8 million ($34.6 million net of tax) recognized in shareholders’ equity and the debt component which is presented as long-term debt, net of the unamortized debt discount and debt issuance costs. The effective interest rate for the 2026 Notes is 12.4% after considering the effect of the accretion of the related debt discount over the term of the 2026 Notes. For the year ended December 31, 2020, interest expense (including amortization of the debt discount) related to the 2026 Notes was $7.2 million. The remaining unamortized amount of the debt discount of the 20232026 Notes was $17.8$41.7 million at December 31, 2018.2020. With the adoption of ASU No.2020-06 beginning January 1, 2021, the 2026 Notes will no longer be reported at a discount. See Note 2 for the effect of ASU No.2020-06.
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. The parent company of Q5000 Holdings, Helix Vessel Finance S.à r.l., alsoQ5000 Holdings's parent, which is a wholly owned Luxembourg subsidiary of Helix, has 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.
TheWe amended the Nordea Credit Agreement on March 11, 2020. Prior to the amendment, the Nordea Q5000 Loan bearsincurred interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and iswas repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. Q5000 Holdings may electon April 30, 2020. The amendment increased the margin to prepay indebtedness outstanding under2.75%, maintained the existing quarterly amortization requirements, and extended the final maturity to January 31, 2021 with a balloon payment on that date of $53.6 million. The remaining principal balance and unamortized debt issuance costs related to 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. In June 2015, we entered into various interest rate swap contracts to fixclassified as current in the one-month LIBOR rate on a portionaccompanying consolidated balance sheets. We repaid the remaining balance of our borrowings under the Nordea Q5000 Loan (Note 18). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.at its maturity on January 29, 2021.
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
Convertible Senior Notes Due 2032
InWe previously issued additional convertible senior notes in March 2012, we issued $200 million of 3.25% Convertible Senior Notes, which were originally scheduled to mature on March 15, 2032 (the “2032 Notes”). We elected to repurchase $7.3 million, $7.6 million and $125In 2018, we fully redeemed the remaining $60.1 million in aggregate principal amount of the 2032 Notes in June, July and November of 2016, respectively. In March 2018, we maderecognized a tender offer for the repurchase of the 2032 Notes outstanding on the first repurchase date as required by the indenture governing the 2032 Notes, and as a result we repurchased $59.3 million in aggregate principal amount of the 2032 Notes on March 20, 2018. The total repurchase price was $59.5 million, includingcorresponding $0.2 million in fees. For the years ended December 31, 2018 and 2016, we recognized net losses of $0.2 million and $3.5 million, respectively, related to the repurchases of the 2032 Notes. These losses areloss. The loss is presented as “Loss on early extinguishment of long-term debt” in the accompanying consolidated statementsstatement of operations. On May 4, 2018, we redeemed the remaining $0.8 million in aggregate principal amount of the 2032 Notes.
Other
In accordance with ourthe Credit Agreement, the 2022 Notes, the 2023 Notes, the 2026 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 variousa consolidated secured leverage ratios,ratio, as well as the maintenance of minimum cash balance, net worth, working capital and debt-to-equity requirements. As of December 31, 2018,2020, we were in compliance with these covenants.
Scheduled maturities of our long-term debt outstanding as of December 31, 20182020 are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Term
Loan | | 2022
Notes | | 2023
Notes | | 2026
Notes | | MARAD
Debt | | Nordea
Q5000
Loan | | Total |
| | | | | | | | | | | | | |
| Less than one year | $ | 29,750 | | | $ | 0 | | | $ | 0 | | | $ | 0 | | | $ | 7,560 | | | $ | 53,572 | | | $ | 90,882 | |
| One to two years | 0 | | | 35,000 | | | 0 | | | 0 | | | 7,937 | | | 0 | | | 42,937 | |
| Two to three years | 0 | | | 0 | | | 30,000 | | | 0 | | | 8,333 | | | 0 | | | 38,333 | |
| Three to four years | 0 | | | 0 | | | 0 | | | 0 | | | 8,749 | | | 0 | | | 8,749 | |
| Four to five years | 0 | | | 0 | | | 0 | | | 0 | | | 9,186 | | | 0 | | | 9,186 | |
| Over five years | 0 | | | 0 | | | 0 | | | 200,000 | | | 14,645 | | | 0 | | | 214,645 | |
| Gross debt | 29,750 | | | 35,000 | | | 30,000 | | | 200,000 | | | 56,410 | | | 53,572 | | | 404,732 | |
Unamortized debt discounts (1) | 0 | | | (1,325) | | | (2,651) | | | (41,716) | | | 0 | | | 0 | | | (45,692) | |
Unamortized debt issuance costs (2) | (191) | | | (198) | | | (427) | | | (5,572) | | | (3,049) | | | (40) | | | (9,477) | |
| Total debt | 29,559 | | | 33,477 | | | 26,922 | | | 152,712 | | | 53,361 | | | 53,532 | | | 349,563 | |
| Less current maturities | (29,559) | | | 0 | | | 0 | | | 0 | | | (7,560) | | | (53,532) | | | (90,651) | |
| Long-term debt | $ | 0 | | | $ | 33,477 | | | $ | 26,922 | | | $ | 152,712 | | | $ | 45,801 | | | $ | 0 | | | $ | 258,912 | |
(1)The 2022 Notes, the 2023 Notes and the 2026 Notes will increase to their face amounts through accretion of their debt discounts to interest expense through May 2022, September 2023 and February 2026, respectively. See Note 2 for future accounting changes related to these discounts.
(2)Debt issuance costs are amortized to interest expense over the term of the applicable debt agreement.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Term Loan (1) | | 2022 Notes | | 2023 Notes | | MARAD Debt | | Nordea Q5000 Loan | | Total |
| | | | | | | | | | | | |
| Less than one year | $ | 4,680 |
| | $ | — |
| | $ | — |
| | $ | 6,858 |
| | $ | 35,714 |
| | $ | 47,252 |
|
| One to two years | 29,013 |
| | — |
| | — |
| | 7,200 |
| | 89,286 |
| | 125,499 |
|
| Two to three years | — |
| | — |
| | — |
| | 7,560 |
| | — |
| | 7,560 |
|
| Three to four years | — |
| | 125,000 |
| | — |
| | 7,937 |
| | — |
| | 132,937 |
|
| Four to five years | — |
| | — |
| | 125,000 |
| | 8,333 |
| | — |
| | 133,333 |
|
| Over five years | — |
| | — |
| | — |
| | 32,580 |
| | — |
| | 32,580 |
|
| Gross debt | 33,693 |
| | 125,000 |
| | 125,000 |
| | 70,468 |
| | 125,000 |
| | 479,161 |
|
Unamortized debt discounts (2) | — |
| | (11,043 | ) | | (17,759 | ) | | — |
| | — |
| | (28,802 | ) |
Unamortized debt issuance costs (3) | (372 | ) | | (1,765 | ) | | (2,862 | ) | | (4,025 | ) | | (1,020 | ) | | (10,044 | ) |
| Total debt | 33,321 |
| | 112,192 |
| | 104,379 |
| | 66,443 |
| | 123,980 |
| | 440,315 |
|
| Less current maturities | (4,680 | ) | | — |
| | — |
| | (6,858 | ) | | (35,714 | ) | | (47,252 | ) |
| Long-term debt | $ | 28,641 |
| | $ | 112,192 |
| | $ | 104,379 |
| | $ | 59,585 |
| | $ | 88,266 |
| | $ | 393,063 |
|
| |
(1) | Term Loan borrowing pursuant to the Credit Agreement matures in June 2020. Scheduled principal repayments of the Term Loan have been adjusted to reflect prepayments made in March 2018. |
| |
(2) | The 2022 Notes will increase to their face amount through accretion of the debt discount through May 2022. The 2023 Notes will increase to their face amount through accretion of the debt discount through September 2023. |
| |
(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, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Interest expense | $ | 30,538 | | | $ | 31,186 | | | $ | 32,617 | |
Capitalized interest (1) | (1,182) | | | (20,246) | | | (15,629) | |
| Interest income | (825) | | | (2,607) | | | (3,237) | |
| Net interest expense | $ | 28,531 | | | $ | 8,333 | | | $ | 13,751 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Interest expense | $ | 32,617 |
| | $ | 38,274 |
| | $ | 45,110 |
|
| Interest income | (3,237 | ) | | (2,590 | ) | | (2,086 | ) |
| Capitalized interest | (15,629 | ) | | (16,906 | ) | | (11,785 | ) |
| Net interest expense | $ | 13,751 |
| | $ | 18,778 |
| | $ | 31,239 |
|
Note 79 — 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).
We recognized the income tax effects of the 2017 Tax Act in accordance with Staff Accounting Bulletin No. 118, “Income Tax Accounting Implications of the Tax Cuts and Jobs Act” (“SAB 118”), which provided SEC staff guidance for the application of ASC Topic 740, Income Taxes, to the 2017 Tax Act. SAB 118 allowed for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. Due to the changes to U.S. tax laws as a result of the 2017 Tax Act, we recorded a provisional $51.6 million net income tax benefit during the fourth quarter of 2017 for the estimated tax impacts. 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 provisional $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 provisional 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 provisional 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.
In the fourth quarter of 2017, we recorded tax charges for the impact of the 2017 Tax Act using the current available information and technical guidance on the interpretations of the 2017 Tax Act. As permitted by SAB118, we recorded provisional estimates and have subsequently finalized our accounting analysis based on guidance, interpretations, and data available as of December 31, 2018. Adjustments made in 2018 upon finalization of our accounting analysis were immaterial to our consolidated financial statements.
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, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Current | $ | (14,818) | | | $ | 4,374 | | | $ | 4,830 | |
| Deferred | (3,883) | | | 3,485 | | | (2,430) | |
| $ | (18,701) | | | $ | 7,859 | | | $ | 2,400 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Current | $ | 4,830 |
| | $ | 4,161 |
| | $ | (27,319 | ) |
| Deferred | (2,430 | ) | | (54,585 | ) | | 14,849 |
|
| | $ | 2,400 |
| | $ | (50,424 | ) | | $ | (12,470 | ) |
| | | Domestic | $ | (3,161 | ) | | $ | (53,044 | ) | | $ | (9,631 | ) | Domestic | $ | (15,074) | | | $ | 3,715 | | | $ | (3,161) | |
| Foreign | 5,561 |
| | 2,620 |
| | (2,839 | ) | Foreign | (3,627) | | | 4,144 | | | 5,561 | |
| | $ | 2,400 |
| | $ | (50,424 | ) | | $ | (12,470 | ) | | $ | (18,701) | | | $ | 7,859 | | | $ | 2,400 | |
Components of income (loss) before income taxes are as follows (in thousands):
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Domestic | $ | (28,838 | ) | | $ | (221 | ) | | $ | (61,484 | ) | Domestic | $ | (3,406) | | | $ | 2,219 | | | $ | (28,838) | |
| Foreign | 59,836 |
| | (20,151 | ) | | (32,431 | ) | Foreign | 4,789 | | | 63,337 | | | 59,836 | |
| | $ | 30,998 |
| | $ | (20,372 | ) | | $ | (93,915 | ) | | $ | 1,383 | | | $ | 65,556 | | | $ | 30,998 | |
The U.S. Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), which was signed into law on March 27, 2020, is an economic stimulus package designed to aid in offsetting the economic damage caused by the ongoing COVID-19 pandemic and includes various changes to U.S. income tax regulations. The CARES Act permits the carryback of certain net operating losses, which previously had been required to be carried forward, at the tax rates applicable in the relevant carryback year. As a result of these changes, we recognized a $7.6 million net tax benefit in the year ended December 31, 2020, consisting of an $18.9 million current tax benefit, which is reflected in our income tax receivable at December 31, 2020, and a $11.3 million deferred tax expense. This $7.6 million net tax benefit resulted from our deferred tax assets related to our net operating losses in the U.S. being utilized at the previous higher income tax rate applicable to the carryback periods.
During the year ended December 31, 2020, we migrated 2 of our foreign subsidiaries into our U.S. consolidated tax group. Subsequent to the migration, these subsidiaries are disregarded and no longer subject to certain branch profits taxes. Consequently, we recognized net deferred tax benefits of $8.3 million due to the reduction in the overall tax rate associated with these subsidiaries.
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 income tax provision (benefit) at the U.S. statutory rate and our effective rateactual income tax provision (benefit) are as follows:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | | | | | | | |
| Taxes at U.S. statutory rate | $ | 290 | | | 21.0 | % | | $ | 13,767 | | | 21.0 | % | | $ | 6,510 | | | 21.0 | % |
| Foreign tax provision | (3,426) | | | (247.7) | | | (6,557) | | | (10.0) | | | (4,941) | | | (15.9) | |
| CARES Act | (7,596) | | | (549.2) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Subsidiary restructuring | (8,333) | | | (602.5) | | | 0 | | | 0 | | | 0 | | | 0 | |
| Other | 364 | | | 26.2 | | | 649 | | | 1.0 | | | 831 | | | 2.6 | |
| Income tax provision (benefit) | $ | (18,701) | | | (1,352.2) | % | | $ | 7,859 | | | 12.0 | % | | $ | 2,400 | | | 7.7 | % |
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Statutory rate | 21.0 | % | | 35.0 | % | | 35.0 | % |
| Foreign provision | (15.9 | ) | | (6.2 | ) | | (5.1 | ) |
Change in U.S. statutory rate (1) | — |
| | 293.1 |
| | — |
|
Mandatory U.S. repatriation (1) | — |
| | (39.7 | ) | | — |
|
Change in tax position (2) | — |
| | (31.1 | ) | | — |
|
| Goodwill impairment | — |
| | — |
| | (16.8 | ) |
| Other | 2.6 |
| | (3.6 | ) | | 0.2 |
|
| Effective rate | 7.7 | % | | 247.5 | % | | 13.3 | % |
| |
(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, | | December 31, |
| | 2018 | | 2017 | | 2020 | | 2019 |
| Deferred tax liabilities: | | | | Deferred tax liabilities: | | | |
| Depreciation | $ | 149,974 |
| | $ | 135,824 |
| Depreciation | $ | 153,226 | | | $ | 166,239 | |
| Debt discount on 2022 Notes, 2023 Notes and 2032 Notes | 5,902 |
| | 7,727 |
| |
| Prepaid and other | 1,309 |
| | 437 |
| |
| Debt discounts on 2022 Notes, 2023 Notes and 2026 Notes | | Debt discounts on 2022 Notes, 2023 Notes and 2026 Notes | 9,298 | | | 4,643 | |
| | Total deferred tax liabilities | $ | 157,185 |
| | $ | 143,988 |
| Total deferred tax liabilities | $ | 162,524 | | | $ | 170,882 | |
| Deferred tax assets: | | | | Deferred tax assets: | | | |
| Net operating losses | $ | (47,916 | ) | | $ | (33,480 | ) | Net operating losses | $ | (59,794) | | | $ | (64,178) | |
| Reserves, accrued liabilities and other | (21,347 | ) | | (19,496 | ) | Reserves, accrued liabilities and other | (11,631) | | | (13,203) | |
| Total deferred tax assets | (69,263 | ) | | (52,976 | ) | Total deferred tax assets | (71,425) | | | (77,381) | |
| Valuation allowance | 17,940 |
| | 12,337 |
| Valuation allowance | 19,722 | | | 18,631 | |
| Net deferred tax liabilities | $ | 105,862 |
| | $ | 103,349 |
| Net deferred tax liabilities | $ | 110,821 | | | $ | 112,132 | |
At December 31, 2018,2020, our U.S. net operating losses available for carryforward totaled $165.6 million.$197.4 million, of which $85.1 million occurred after the passage of the 2017 Tax Act and are not subject to expiration. The U.S. net operating loss carryforwards generated prior to 2018 in the amount of $112.3 million will begin to expire in 2035 if unused. Realization of net operating losses 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, 2018,2020, we had a $3.0$2.9 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.
At December 31, 2018,2020, we had a $15.0$16.8 million valuation allowance related to certain non-U.S. deferred tax assets, primarily net operating losses generated in Brazil and from our oil and gas operationsRobotics 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, 2018,2020, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $93.2$62.2 million. Due to the enactment of the 2017U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”), repatriations of foreign earnings will generally be free of U.S. federal tax but may be subject to changes in future tax legislation that may result in other withholding taxes or state taxes.taxation. 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 and foreign credit facility.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 recorded an uncertain tax position of $0.7 million in 2020 related to a research and development credit taken on our 2019 U.S. Federal Income Tax Return and certain expenses not reversed for tax purposes. We account for tax-related interest in interest expense and tax penalties in selling, general and administrative expenses. No significant penalties orWe did not record any interest expense were accruedrelated to these positions in 2020 as the amount was immaterial. The statute of limitations on our$0.3 million of uncertain tax positions. We hadpositions expired in 2019. Therefore, as of December 31, 2019, there were no unrecognized tax benefits of $0.3 million related to uncertain tax positions as of December 31, 2018, 2017 and 2016, which if recognized would affect the annual effective tax rate.
A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2018 and 2017 is as follows (in thousands):
|
| | | | | | | | | | | |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Balance at January 1, | $ | 318 |
| | $ | 343 |
| | $ | — |
|
| Additions for tax positions of prior years | — |
| | — |
| | 343 |
|
| Reductions for tax positions of prior years | (12 | ) | | (25 | ) | | — |
|
| Balance at December 31, | $ | 306 |
| | $ | 318 |
| | $ | 343 |
|
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. In 2016, we received $28.4 million in U.S. and foreign income tax refunds for losses that were carried back to prior years. The tax periods from 20152013, 2014, and 2018 through 20182020 remain open to review and examination by the Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2013 through 2018.2020.
Note 810 —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,In connection with the 2026 Notes offering (Note 8), we completedentered into the 2026 Capped Calls with three separate option counterparties. The 2026 Capped Calls are separate transactions from the 2026 Notes and do not change the holders' rights under the 2026 Notes. Holders of the 2026 Notes do not have any rights with respect to the 2026 Capped Calls.
The 2026 Capped Calls are for an underwritten public offering (the “Offering”)aggregate of 26,450,00028,675,900 shares of our common stock, at a public offeringwhich corresponds to the shares into which the 2026 Notes are initially convertible. The capped call shares are subject to certain anti-dilution adjustments. Each capped call option has an initial strike price of $8.65approximately $6.97 per share, which corresponds to the initial conversion price of the 2026 Notes, and an initial cap price of approximately $8.42 per share. The strike and cap prices are subject to certain adjustments. The 2026 Capped Calls are intended to offset some or all of the potential dilution to Helix common shares caused by any conversion of the 2026 Notes up to the cap price. The 2026 Capped Calls can be settled in either net proceeds from the Offering approximated $220 million, after deducting underwriting discountsshares or cash at our option in components commencing December 15, 2025 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.ending February 12, 2026, which could be extended under certain circumstances.
The 2026 Capped Calls are subject to either adjustment or termination upon the occurrence of specified extraordinary events affecting Helix, including a merger, tender offer, nationalization, insolvency or delisting. In 2016, we soldaddition, certain events may result in a totaltermination of 13,018,732 sharesthe 2026 Capped Calls, including changes in law, insolvency filings and hedging disruptions. The 2026 Capped Calls are recorded at their aggregate cost of $10.6 million as a reduction to common stock in the shareholders’ equity section of our common stock for $100 million under an at-the-market (“ATM”) equity offering program. The proceeds from this ATM program totaled $96.5 million, net of transaction costs, including commissions of $2.3 million to Wells Fargo Securities, LLC.consolidated balance sheet.
The components of accumulated OCI are as follows (in thousands):
| | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| | | |
| Cumulative foreign currency translation adjustment | $ | (51,620) | | | $ | (64,455) | |
Net unrealized loss on hedges, net of tax (1) | 0 | | | (285) | |
| | | |
| Accumulated OCI | $ | (51,620) | | | $ | (64,740) | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Cumulative foreign currency translation adjustment | $ | (69,855 | ) | | $ | (62,689 | ) |
Net unrealized loss on hedges, net of tax (1) | (4,109 | ) | | (7,507 | ) |
Unrealized gain on note receivable, net of tax (2) | $ | — |
| | $ | 409 |
|
| Accumulated other comprehensive loss | $ | (73,964 | ) | | $ | (69,787 | ) |
| |
(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 (Note18). Balance at December 31, 2018 was net of deferred income taxes totaling $1.0 million. Balance at December 31, 2017 was net of deferred income taxes of $4.0 million, $1.6 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 2).
|
| |
(2) | Balance at December 31, 2017 was net of deferred income taxes of $0.2 million, $0.1 million of which was reclassified to retained earnings on January 1, 2018 pursuant to the adoption of ASU No. 2018-02 (Note 2). |
Note 911 — Stock Buyback Program
Our Board of Directors (the(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 issued under our existing long-term incentive plans and shares issued to our employees under our employee stock purchase plansEmployee Stock Purchase Plan (the “ESPP”) (Note 12)14). We may continue to make repurchases pursuant to this authority from time to time as additional equity is issued under our stock basedstock-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, 2018, 3,931,0762020, 6,913,705 shares of our common stock were available for repurchase under the program.
Note 1012 —Revenue from Contracts with Customers
Disaggregation of revenueRevenue
The following table provides information about disaggregated revenue by contract duration for the year ended December 31, 2018 (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Well Intervention | | Robotics | | Production Facilities | | Intercompany Eliminations (1) | | Total Revenue |
| Year ended December 31, 2020 | | | | | | | | | |
| Short-term | $ | 206,812 | | | $ | 117,439 | | | $ | 0 | | | $ | 0 | | | $ | 324,251 | |
| Long-term | 332,437 | | | 60,579 | | | 58,303 | | | (42,015) | | | 409,304 | |
| Total | $ | 539,249 | | | $ | 178,018 | | | $ | 58,303 | | | $ | (42,015) | | | $ | 733,555 | |
| | | | | | | | | |
| Year ended December 31, 2019 | | | | | | | | | |
| Short-term | $ | 214,926 | | | $ | 94,501 | | | $ | 0 | | | $ | 0 | | | $ | 309,427 | |
| Long-term | 378,374 | | | 77,171 | | | 61,210 | | | (74,273) | | | 442,482 | |
| Total | $ | 593,300 | | | $ | 171,672 | | | $ | 61,210 | | | $ | (74,273) | | | $ | 751,909 | |
| | | | | | | | | |
| Year ended December 31, 2018 | | | | | | | | | |
| Short-term | $ | 199,294 | | | $ | 89,072 | | | $ | 0 | | | $ | 0 | | | $ | 288,366 | |
| Long-term | 361,274 | | | 69,917 | | | 64,400 | | | (44,139) | | | 451,452 | |
| Total | $ | 560,568 | | | $ | 158,989 | | | $ | 64,400 | | | $ | (44,139) | | | $ | 739,818 | |
|
| | | | | | | | | | | | | | | | | | | |
| | Well Intervention | | Robotics | | Production Facilities | | Intercompany Eliminations (1) | | Total Revenue |
| | | | | | | | | | |
| 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 between Robotics and Well Intervention 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(1)Intercompany revenues among our business segments are under agreements that are considered long-term.
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.
Contract Balances
Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditionalconditioned 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” onin the accompanying condensed consolidated balance sheet.sheets (Note 3). Contract assets as of January 1, 2018 were immaterial while contract assets as of December 31, 20182020 and 2019 were $5.8 million. Impairment$2.4 million and $0.7 million, respectively. We had no credit losses recognized on our accounts receivable were immaterialcontract assets for the yearyears ended December 31, 2020, 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 thea single performance obligation and recognized ratably over the contract term andand/or (ii) the amountamounts 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” onin the accompanying condensed consolidated balance sheet.sheets (Note 3). Contract liabilities as of January 1, 2018 and December 31, 20182020 and 2019 totaled $21.4$10.0 million and $25.9$19.9 million, respectively. Revenue recognized for the yearyears ended December 31, 2020, 2019 and 2018 included $11.6 million, $10.1 million and $11.6 million, respectively, that were included in the contract liability balance as the beginning of January 1, 2018.each period.
We report the net contract asset or contract liability position on a contract-by-contract basis asat the end of December 31, 2018.each reporting period.
Performance obligationsObligations
As of December 31, 2018, $1.1 billion2020, $406.7 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $470.1$301.2 million in 2019, $396.32021, $72.9 million in 20202022 and $277.6$32.6 million in 20212023 and thereafter. These amounts includedinclude 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 withinof 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, 2018.2020.
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 years ended December 31, 2020 and 2018, revenues recognized from performance obligations satisfied (or partially satisfied) in previous years were immaterial.
Contract costsFulfillment 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” onin the accompanying condensed consolidated balance sheets (Note 3). Our deferred contract costs totaled $65.9 million as of December 31, 2018.2020 and 2019 totaled $24.4 million and $42.9 million, respectively. For the yearyears ended December 31, 2020, 2019 and 2018, we recorded $35.8 million, $31.5 million and $33.1 million, respectively, related to amortization of deferred contract costs existing as of January 1, 2018 and therecosts. There were no associated impairment losses.losses for any period presented.
Note 1113 — 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, |
| 2020 | | 2019 | | 2018 |
| Income | | Shares | | Income | | Shares | | Income | | Shares |
| Basic: | | | | | | | | | | | |
| Net income attributable to common shareholders | $ | 22,174 | | | | | $ | 57,919 | | | | | $ | 28,598 | | | |
| Less: Undistributed earnings allocated to participating securities | (140) | | | | | (487) | | | | | (273) | | | |
| Accretion of redeemable noncontrolling interests | (2,400) | | | | | (143) | | | | | 0 | | | |
| Net income available to common shareholders, basic | $ | 19,634 | | | 148,993 | | | $ | 57,289 | | | 147,536 | | | $ | 28,325 | | | 146,702 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | Income | | Shares | | Income | | Shares | | Income | | Shares |
| Basic: | | | | | | | | | | | |
| Net income (loss) | $ | 28,598 |
| | | | $ | 30,052 |
| | | | $ | (81,445 | ) | | |
| Less: Undistributed earnings allocated to participating securities | (273 | ) | | | | (356 | ) | | | | — |
| | |
| Undistributed earnings (loss) allocated to common shares | $ | 28,325 |
| | 146,702 |
| | $ | 29,696 |
| | 145,295 |
| | $ | (81,445 | ) | | 111,612 |
|
| | | | | | Diluted: | | | | | | | | | | | | Diluted: | |
| Undistributed earnings (loss) allocated to common shares | $ | 28,325 |
| | 146,702 |
| | $ | 29,696 |
| | 145,295 |
| | $ | (81,445 | ) | | 111,612 |
| |
| Net income available to common shareholders, basic | | Net income available to common shareholders, basic | $ | 19,634 | | | 148,993 | | | $ | 57,289 | | | 147,536 | | | $ | 28,325 | | | 146,702 | |
| Effect of dilutive securities: | | | | | | | | | | | | Effect of dilutive securities: | |
| Share-based awards other than participating securities | — |
| | 128 |
| | — |
| | 5 |
| | — |
| | — |
| Share-based awards other than participating securities | 0 | | | 904 | | | 0 | | | 2,041 | | | 0 | | | 128 | |
| Undistributed earnings reallocated to participating securities | 1 |
| | — |
| | — |
| | — |
| | — |
| | — |
| Undistributed earnings reallocated to participating securities | 1 | | | — | | | 6 | | | — | | | 1 | | | — | |
| Net income (loss) | $ | 28,326 |
| | 146,830 |
| | $ | 29,696 |
| | 145,300 |
| | $ | (81,445 | ) | | 111,612 |
| |
| Net income available to common shareholders, diluted | | Net income available to common shareholders, diluted | $ | 19,635 | | | 149,897 | | | $ | 57,295 | | | 149,577 | | | $ | 28,326 | | | 146,830 | |
We had a net loss for the year ended December 31, 2016. Accordingly, our diluted EPS calculation for this period was equivalent to our basic EPS calculation since diluted EPS excluded any assumed exercise or conversion of common stock equivalents. These common stock equivalents were excluded because they were deemed to be anti-dilutive, meaning their inclusion would have reduced the reported net loss per share in the applicable period. Shares that otherwise would have been included in the diluted EPS calculation assuming we had earnings are as follows (in thousands):
|
| | |
| Year Ended December 31, |
| 2016 |
| |
Diluted shares (as reported) | 111,612 |
|
Share-based awards | 440 |
|
Total | 112,052 |
|
In addition, theThe following weighted average potentially dilutive shares related to the 2022 Notes, the 2023 Notes, the 2026 Notes and the 2032 Notes were excluded from the diluted EPS calculation as they were anti-dilutive (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| 2022 Notes | 6,537 | | | 8,997 | | | 8,997 | |
| 2023 Notes | 9,391 | | | 13,202 | | | 10,344 | |
| 2026 Notes | 10,891 | | | 0 | | | 0 | |
2032 Notes (1) | 0 | | | 0 | | | 524 | |
|
| | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| 2022 Notes | 8,997 |
| | 8,997 |
| | 1,475 |
|
| 2023 Notes | 10,344 |
| | — |
| | — |
|
2032 Notes (1) | 524 |
| | 2,403 |
| | 6,891 |
|
| |
(1) | The 2032 Notes were fully redeemed in May 2018. |
Note 1214 — Employee Benefit Plans
Defined Contribution Plan
We sponsor a defined contribution 401(k) retirement plan. We suspended ourOur discretionary contributions for an indefinite period beginning February 2016.are in the form of cash and consist of a 50% match of each participant’s contribution up to 5% of the participant’s salary. For the years ended December 31, 2020 and 2019, we made discretionary employer contributions of $1.6 million and $1.0 million, respectively, to the 401(k) plan.
Employee Stock Purchase Plan
We haveOn May 15, 2019, our shareholders approved an employee stock purchase plan (the “ESPP”). Theamendment to and restatement of the ESPP has 1.5 millionto: (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 which 0.5December 31, 2020, 1.8 million shares were available for issuance as of December 31, 2018.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 (i) its fair market value on (i)the first trading day of the purchase period or (ii) its fair market value on the last trading day of the purchase period. In February2016, we suspendedThe ESPP purchases for the January through April2016 purchase period and indefinitely imposedcurrently has a purchase limit of 130260 shares per employee for subsequentper purchase periods.period.
Long-Term Incentive Plan
We currently have one1 active long-term incentive plan, the 2005 Long-Term Incentive Plan, as amended and restated effective January 1, 2017 (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 (“RSUs”), PSUs and cash awards. Awards that have been granted to employees under the 2005 Incentive Plan have a vesting period of three years (or 33% per year) with the exception of PSUs, which vest 100% on the third anniversary date of the grant.
On May 15, 2019, our shareholders approved an amendment to and restatement of the 2005 Incentive Plan to: (i)authorize 7.0 million additional shares for issuance pursuant to our equity incentive compensation strategy, (ii)establish a maximum award limit applicable to independent members of our Board under the 2005 Incentive Plan, (iii)require, subject to certain exceptions, that all awards under the 2005 Incentive Plan have a minimum vesting or restriction period of one year and (iv)remove certain requirements with respect to performance-based compensation under Section 162(m) of the Internal Revenue Code that were repealed by the 2017 Tax Act. The 2005 Incentive Plan currently has 10.317.3 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, 2018,2020, there were 1.76.8 million shares available for issuance under the 2005 Incentive Plan.Plan and no incentive stock options are currently outstanding.
The following grants of share-based awards were made in 20182020 under the 2005 Incentive Plan:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Date of Grant | | | Shares/
Units | | | Grant Date
Fair Value
Per Share/Unit | | Vesting Period |
| | | | | | | | | | |
January 2, 2020 (1) | | | 369,938 | | | | | $ | 9.63 | | | | 33% per year over three years |
January 2, 2020 (2) | | | 369,938 | | | | | $ | 13.15 | | | | 100% on January 2, 2023 |
January 2, 2020 (3) | | | 5,679 | | | | | $ | 9.63 | | | | 100% on January 1, 2022 |
April 1, 2020 (3) | | | 43,351 | | | | | $ | 1.64 | | | | 100% on January 1, 2022 |
July 1, 2020 (3) | | | 19,407 | | | | | $ | 3.47 | | | | 100% on January 1, 2022 |
October 1, 2020 (3) | | | 24,831 | | | | | $ | 2.41 | | | | 100% on January 1, 2022 |
December 10, 2020 (4) | | | 204,546 | | | | | $ | 4.40 | | | | 100% on December 10, 2021 |
|
| | | | | | | | | | | | | |
| Date of Grant | | | Shares | | | Grant Date Fair Value Per Share/Unit | | Vesting Period |
| | | | | | | | | | | |
January 2, 2018 (1) | | | 449,271 |
| | | | $ | 7.54 |
| | | 33% per year over three years |
January 2, 2018 (2) | | | 449,271 |
| | | | $ | 10.44 |
| | | 100% on January 2, 2021 |
January 2, 2018 (3) | | | 8,247 |
| | | | $ | 7.54 |
| | | 100% on January 1, 2020 |
April 2, 2018 (3) | | | 11,064 |
| | | | $ | 5.79 |
| | | 100% on January 1, 2020 |
July 2, 2018 (3) | | | 6,565 |
| | | | $ | 8.33 |
| | | 100% on January 1, 2020 |
August 21, 2018 (4) | | | 6,093 |
| | | | $ | 8.97 |
| | | 100% on August 21, 2019 |
October 1, 2018 (3) | | | 6,104 |
| | | | $ | 9.88 |
| | | 100% on January 1, 2020 |
December 13, 2018 (5) | | | 126,942 |
| | | | $ | 7.09 |
| | | 100% on December 13, 2019 |
| |
(1) | (1)Reflects grants of restricted stock to our executive officers. |
| |
(2) | Reflects grants of PSUs to our executive officers. 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 made an election to take their quarterly fees in stock in lieu of cash. |
| |
(4) | Reflects a grant of restricted stock made to an independent member of our Board upon his joining our Board. |
| |
(5) | Reflects annual equity grants to each independent member of our Board. |
In January 2019, we granted our executive officers and select management employees 688,540employees.
(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 annual equity grants to each independent member of our Board.
In January 2021, we granted our executive officers 452,381 RSUs and 688,540452,381 PSUs under the 2005 Incentive Plan. The marketgrant date fair value of the restricted sharesRSUs was $5.41$4.20 per shareunit or $3.7$1.9 million. The grant date fair value of the PSUs was $7.60$5.33 per share.unit or $2.4 million. Also in January 2019,2021, we granted $4.4$3.4 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, |
| 2020 | | 2019 | | 2018 |
| Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) |
| | | | | | | | | | | |
| Awards outstanding at beginning of year | 1,173,045 | | | $ | 6.81 | | | 1,320,989 | | | $ | 7.40 | | | 1,579,218 | | | $ | 7.63 | |
| Granted | 667,752 | | | 7.06 | | | 846,835 | | | 6.02 | | | 614,286 | | | 7.46 | |
Vested (2) | (631,498) | | | 7.52 | | | (993,361) | | | 6.92 | | | (823,310) | | | 7.88 | |
| Forfeited | (32,348) | | | 5.41 | | | (1,418) | | | 8.82 | | | (49,205) | | | 7.62 | |
| Awards outstanding at end of year | 1,176,951 | | | $ | 6.61 | | | 1,173,045 | | | $ | 6.81 | | | 1,320,989 | | | $ | 7.40 | |
|
| | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) |
| | | | | | | | | | | | |
| Awards outstanding at beginning of year | 1,579,218 |
| | $ | 7.63 |
| | 1,577,973 |
| | $ | 7.86 |
| | 661,124 |
| | $ | 16.28 |
|
| Granted | 614,286 |
| | 7.46 |
| | 829,143 |
| | 8.39 |
| | 1,298,121 |
| | 5.70 |
|
Vested (2) | (823,310 | ) | | 7.88 |
| | (817,791 | ) | | 8.84 |
| | (305,588 | ) | | 16.94 |
|
| Forfeited | (49,205 | ) | | 7.62 |
| | (10,107 | ) | | 7.01 |
| | (75,684 | ) | | 7.76 |
|
| Awards outstanding at end of year | 1,320,989 |
| | $ | 7.40 |
| | 1,579,218 |
| | $ | 7.63 |
| | 1,577,973 |
| | $ | 7.86 |
|
| |
(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, 2018, 2017 and 2016 was $6.4 million, $6.9 million and $2.2 million, respectively. |
(2)Total fair value of restricted stock that vested during the years ended December 31, 2020, 2019 and 2018 was $5.4 million, $6.5 million and $6.4 million, respectively.
For the years ended December 31, 2020, 2019 and 2018, 2017 and 2016, $6.0$4.2 million, $7.9$6.2 million and $5.8$6.0 million, respectively, were recognized as share-based compensation related to restricted stock. Future compensation cost associated with unvested restricted stock at December 31, 20182020 totaled approximately $5.0$4.4 million. The weighted average vesting period related to unvested restricted stock at December 31, 20182020 was approximately 1.0 year.1.2 years.
Performance Share UnitsUnit Awards
We grant PSUs to our executive officers and from time to time select management employees. PSUs granted in 2020, 2019 and 2018 are to be settled solely in shares of our common stock and therefore are accounted for as equity awards. The payout at vesting of these 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 could be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee of our Board. As a result of our Board’s decision to cash settle the vesting of the 2012 PSU awards in 2015, PSUs granted before 2017, including those that were previously accounted for as equity awards, are treated 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.0.
We issued 449,271 PSUs in 2018 with a
The following table summarizes information about our equity PSU awards:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| 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 | 1,565,044 | | | $ | 10.17 | | | 1,006,360 | | | $ | 11.76 | | | 613,665 | | | $ | 12.64 | |
| Granted | 369,938 | | | 13.15 | | | 688,540 | | | 7.60 | | | 449,271 | | | 10.44 | |
| Vested | (589,335) | | | 12.64 | | | 0 | | | 0 | | | 0 | | | 0 | |
| Forfeited | (48,521) | | | 7.60 | | | (129,856) | | | 8.91 | | | (56,576) | | | 10.83 | |
| Equity PSU awards outstanding at end of year | 1,297,126 | | | $ | 9.99 | | | 1,565,044 | | | $ | 10.17 | | | 1,006,360 | | | $ | 11.76 | |
(1)Represents the weighted average grant date fair value, of $10.44 per unit, 671,771 PSUs in 2017 withwhich is determined using a grant date fair value of $12.64 per unit and 1,161,672 PSUs in 2016 with a grant date fair value of $7.13 per unit. Monte Carlo simulation model.
For the years ended December 31, 2020, 2019 and 2018, 2017 and 2016, $4.7$4.0 million, $7.4$5.1 million and $6.8$3.8 million, respectively, were recognized as share-based compensation related to PSUs. equity PSU awards. Future compensation cost associated with unvested equity PSU awards at December 31, 2020 totaled approximately $4.6 million. The weighted average vesting period related to unvested equity PSU awards at December 31, 2020 was approximately 1.0 year. In January 2021, 368,038 equity PSU awards granted in 2018 vested at 200%, representing 736,075 shares of our common stock with a total market value of $3.1 million. In January 2020, 589,335 equity 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 year ended December 31, 2016, we recorded $0.22018, $0.9 million in equity reflecting the cumulativewere recognized as share-based compensation cost recognized in excess of the estimated fair value of the modifiedrelated to liability PSU awards. At December 31, 2018 and 2017, the liability balance for unvested PSUs was $11.1 million. During 2016, 20172019 and 2018, we paid $0.2 million, $0.6cash settled liabilities of $11.1 million and $0.9 million, respectively, related to cash settle the PSUsPSU awards granted in 2013, 20142016 and 2015. We paid $11.1 million to cash settle the 2016 grant of PSUs when they vested in January 2019.2015, respectively.
Cash Awards
In 2020, 2019 and 2018, we granted $4.7 million, $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 yearyears ended December 31, 2020, 2019 and 2018, we recognized compensation costs of $4.4 million and $3.2 million and $1.7 million, was recognized as compensation cost,respectively, which reflects the liability balance as of December 31, 2018 forreflected the cash payoutpayouts made in January 2019.2021, 2020 and 2019, respectively.
Note 1315 — Business Segment Information
We have three3 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 segment includes our vessels andand/or equipment used to performaccess offshore wells for the purpose of performing well intervention servicesenhancement or decommissioning operations primarily in the U.S. Gulf of Mexico, Brazil, the North Sea and West Africa. Our well intervention vessels include the Q4000, the Q5000, the SeawellQ7000, the Seawell, the Well Enhancer, and the chartered Siem Helix1 and Siem Helix2 chartered vessels. The Siem Helix1 commenced well intervention operations for Petrobras offshore Brazil in April 2017 and the Siem Helix2 commenced operations for Petrobras in December 2017. We returned the Skandi Constructor to its owner in March 2017 upon the expiration of the vessel charter. Our well intervention equipment includes IRSs, SILs and the ROAM, some of which we provide on a stand-alone basis, and SILs.basis. Our Robotics segment includes ROVs, trenchers and ROVDrills,a ROVDrill, which are designed to complement offshore construction and well intervention services and three ROVoffshore construction to both the oil and gas and the renewable energy markets globally. Our Robotics segment also includes 2 robotics support vessels under long-term charter:charter, the Grand Canyon, the Grand Canyon II and the Grand Canyon III. We returned the Deep Cygnus to its owner during the first quarter of 2018., as well as spot vessels as needed. Our Production Facilities segment includes the HP I, the HFRS and our investment in Independence Hub that is accounted for under the equity method.ownership of oil and gas properties (Note 16). All material intercompany transactions between the segments have been eliminated.
We evaluate our performance based on operating income of each reportable segment. Certain financial data by reportable segment are summarized as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| Net revenues — | | | | | |
| Well Intervention | $ | 539,249 | | | $ | 593,300 | | | $ | 560,568 | |
| Robotics | 178,018 | | | 171,672 | | | 158,989 | |
| Production Facilities | 58,303 | | | 61,210 | | | 64,400 | |
| Intercompany eliminations | (42,015) | | | (74,273) | | | (44,139) | |
| Total | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | |
| | | | Year Ended December 31, | |
| | 2018 | | 2017 | | 2016 | |
| Net revenues — | | | | | | |
| Income (loss) from operations — | | Income (loss) from operations — | |
| Well Intervention | $ | 560,568 |
| | $ | 406,341 |
| | $ | 294,000 |
| Well Intervention | $ | 26,855 | | | $ | 89,564 | | | $ | 87,643 | |
| Robotics | 158,989 |
| | 152,755 |
| | 160,580 |
| Robotics | 13,755 | | | 7,261 | | | (14,054) | |
| Production Facilities | 64,400 |
| | 64,352 |
| | 72,358 |
| Production Facilities | 15,975 | | | 17,160 | | | 27,263 | |
| Intercompany eliminations | (44,139 | ) | | (42,065 | ) | | (39,356 | ) | |
| Segment operating income | | Segment operating income | 56,585 | | | 113,985 | | | 100,852 | |
Goodwill impairment (1) | | Goodwill impairment (1) | (6,689) | | | 0 | | | 0 | |
| Corporate, eliminations and other | | Corporate, eliminations and other | (36,871) | | | (45,988) | | | (49,309) | |
| Total | $ | 739,818 |
| | $ | 581,383 |
| | $ | 487,582 |
| Total | 13,025 | | | 67,997 | | | 51,543 | |
| Net interest expense | | Net interest expense | (28,531) | | | (8,333) | | | (13,751) | |
| Other non-operating income (expense), net | | Other non-operating income (expense), net | 16,889 | | | 5,892 | | | (6,794) | |
| Income before income taxes | | Income before income taxes | $ | 1,383 | | | $ | 65,556 | | | $ | 30,998 | |
| | | | | | | | | | | | | | | | | |
| |
| | | | | |
| | | | | |
| Capital expenditures — | | | | | |
| Well Intervention | $ | 19,523 | | | $ | 139,212 | | | $ | 136,164 | |
| Robotics | 257 | | | 417 | | | 151 | |
| Production Facilities | 0 | | | 123 | | | 325 | |
| Corporate and other | 464 | | | 1,102 | | | 443 | |
| Total | $ | 20,244 | | | $ | 140,854 | | | $ | 137,083 | |
|
| | | | | | | | | | | |
| Income (loss) from operations — | | | | | |
Well Intervention (1) | $ | 87,643 |
| | $ | 52,733 |
| | $ | 14,910 |
|
Robotics (2) | (14,054 | ) | | (42,289 | ) | | (72,250 | ) |
| Production Facilities | 27,263 |
| | 28,172 |
| | 33,861 |
|
| Segment operating income | 100,852 |
| | 38,616 |
| | (23,479 | ) |
| Corporate, eliminations and other | (49,309 | ) | | (39,746 | ) | | (39,756 | ) |
| Total | 51,543 |
| | (1,130 | ) | | (63,235 | ) |
| Net interest expense | (13,751 | ) | | (18,778 | ) | | (31,239 | ) |
| Other non-operating income (expense), net | (6,794 | ) | | (464 | ) | | 559 |
|
| Income (loss) before income taxes | $ | 30,998 |
| | $ | (20,372 | ) | | $ | (93,915 | ) |
| | | | | | | | | | | | | | | | | |
| Depreciation and amortization — | | | | | |
| Well Intervention | $ | 101,756 | | | $ | 80,153 | | | $ | 76,943 | |
| Robotics | 15,952 | | | 16,459 | | | 19,175 | |
| Production Facilities | 15,652 | | | 15,658 | | | 14,070 | |
| Corporate and eliminations | 349 | | | 450 | | | 334 | |
| Total | $ | 133,709 | | | $ | 112,720 | | | $ | 110,522 | |
(1)Relates to the impairment of the entire STL goodwill balance (Note 7).
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| Capital expenditures — | | | | | |
| Well Intervention | $ | 136,164 |
| | $ | 230,354 |
| | $ | 185,892 |
|
| Robotics | 151 |
| | 648 |
| | 720 |
|
| Production Facilities | 325 |
| | — |
| | 74 |
|
| Corporate and other | 443 |
| | 125 |
| | (199 | ) |
| Total | $ | 137,083 |
| | $ | 231,127 |
| | $ | 186,487 |
|
|
| | | | | | | | | | | |
| Depreciation and amortization — | | | | | |
| Well Intervention | $ | 76,943 |
| | $ | 68,301 |
| | $ | 68,392 |
|
| Robotics | 19,175 |
| | 23,626 |
| | 25,848 |
|
| Production Facilities | 14,070 |
| | 13,936 |
| | 13,952 |
|
| Corporate and eliminations | 334 |
| | 2,882 |
| | 5,995 |
|
| Total | $ | 110,522 |
| | $ | 108,745 |
| | $ | 114,187 |
|
| |
(1) | Amount in 2016 included a $1.3 million gain on the sale of the Helix 534 in December 2016.
|
| |
(2) | Amount in 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit. |
Intercompany segment amounts are derived primarily from equipment and services provided to other business segments at rates consistent with those charged to third parties.segments. Intercompany segment revenues are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
Well Intervention (1) | $ | 15,039 | | | $ | 43,484 | | | $ | 14,218 | |
| Robotics | 26,976 | | | 30,789 | | | 29,921 | |
| Total | $ | 42,015 | | | $ | 74,273 | | | $ | 44,139 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 |
| | | | | | |
| Well Intervention | $ | 14,218 |
| | $ | 11,489 |
| | $ | 8,442 |
|
| Robotics | 29,921 |
| | 30,576 |
| | 30,914 |
|
| Total | $ | 44,139 |
| | $ | 42,065 |
| | $ | 39,356 |
|
Revenues by individually significant geographic location are as follows (in thousands):
| | | | | | | | | | Year Ended December 31, |
| | Year Ended December 31, | | 2020 | | 2019 | | 2018 |
| | 2018 | | 2017 | | 2016 | | | | | | |
| | | | | | | |
| United States | $ | 271,260 |
| | $ | 283,933 |
| | $ | 298,279 |
| |
| United Kingdom | 194,434 |
| | 155,954 |
| | 123,581 |
| |
| U.S. | | U.S. | $ | 304,563 | | | $ | 297,162 | | | $ | 271,260 | |
| U.K. | | U.K. | 133,005 | | | 193,903 | | | 194,434 | |
| Brazil | 208,054 |
| | 70,710 |
| | 2,543 |
| Brazil | 208,565 | | | 216,796 | | | 208,054 | |
| Other | 66,070 |
| | 70,786 |
| | 63,179 |
| Other | 87,422 | | | 44,048 | | | 66,070 | |
| Total | $ | 739,818 |
| | $ | 581,383 |
| | $ | 487,582 |
| Total | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | |
Our operational assets primarily our vessels, work throughout the year in various regions around the world such as the U.S. 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, |
| 2020 | | 2019 |
| | | |
| U.S. | $ | 750,986 | | | $ | 808,683 | |
U.K. (1) | 764,070 | | | 782,246 | |
| Brazil | 267,896 | | | 281,698 | |
| Singapore | 12 | | | 10 | |
| | | |
| Total | $ | 1,782,964 | | | $ | 1,872,637 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| United States | $ | 862,334 |
| | $ | 894,680 |
|
United Kingdom (1) | 236,512 |
| | 270,499 |
|
| Brazil | 324,083 |
| | 334,454 |
|
Singapore (2) | 403,816 |
| | 295,798 |
|
| Other | — |
| | 10,558 |
|
| Total | $ | 1,826,745 |
| | $ | 1,805,989 |
|
| |
(1) | Includes certain assets that are based in the United Kingdom but may operate in the North Sea and West Africa regions. |
| |
(2) | Primarily includes the Q7000 vessel currently under completion at the shipyard in Singapore. The vessel may be deployed globally once completed.
|
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, |
| 2020 | | 2019 |
| | | |
| Well Intervention | $ | 2,134,081 | | | $ | 2,180,180 | |
| Robotics | 132,550 | | | 151,478 | |
| Production Facilities | 129,773 | | | 142,624 | |
| Corporate and other | 101,874 | | | 122,449 | |
| Total | $ | 2,498,278 | | | $ | 2,596,731 | |
|
| | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | | | |
| Well Intervention | $ | 1,916,638 |
| | $ | 1,830,733 |
|
| Robotics | 147,602 |
| | 179,853 |
|
| Production Facilities | 120,845 |
| | 138,292 |
|
| Corporate and other | 162,645 |
| | 213,959 |
|
| Total | $ | 2,347,730 |
| | $ | 2,362,837 |
|
Note 1416 — Asset Retirement Obligations
The following table describes the changes in our AROs (both current and long-term) for the years ended December 31, 2020 and 2019 (in thousands):
| | | | | | | | | | | |
| 2020 | | 2019 |
| | | |
| AROs at January 1, | $ | 28,258 | | | $ | 0 | |
| Liability incurred during the period | 0 | | | 53,294 | |
| Liability settled during the period | 0 | | | (28,296) | |
| Revisions in estimated cash flows | 0 | | | 822 | |
| Accretion expense | 2,655 | | | 2,438 | |
| AROs at December 31, | $ | 30,913 | | | $ | 28,258 | |
Our AROs relate to our Droshky oil and gas properties that we acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019. In connection with assuming the P&A of those assets, we are entitled to receive agreed-upon amounts from Marathon Oil as the P&A work is completed.
Note 17 — Commitments and Contingencies and Other Matters
Commitments
Commitments Related to Our Fleet
We have long-term charter agreements with Siem Offshore AS (“Siem”) for the Siem Helix1 and Siem Helix2 vessels, which are currently 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, from the respective vessel delivery dates with options to extend. The Siem Helix1 charter expires June 2023 and the Siem Helix2 charter expires February 2024. We have time charter agreements for the Grand Canyon, II and Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. The charter agreements expire in October 2019 forexpiration date of the Grand Canyon,II charter was extended in February 2021 from April 2021 foruntil December 2021, with an option to renew. The Grand CanyonIII charter expires May 2023.
We took delivery of the Grand Canyon IIQ7000 in November 2019, and in May 2023 for the Grand Canyon III. We also had a charter agreement for the Deep Cygnus. On February 9, 2018, we terminated our charter for the vessel and returned it to its owner. The charter had originally been scheduled to end on March 31, 2018.
In September 2013, we executed a contract for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, to be built to North Sea standards. Pursuant to the contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contractcommenced operations in 2013, 20% was paid in each of 2016, 2017 and 2018, and the remaining 20% will be paid uponJanuary 2020. With the delivery of the vessel, which at our option can be deferred until December31, 2019. We are also contractually committed to reimburse the shipyard for its costs incurred in connection with the deferment of the Q7000’s delivery beyond 2017. At December 31, 2018, our total investment in the Q7000 was $403.8 million, including $276.8 million of installment payments to the shipyard. Currently equipment is being manufactured and/or installed for the completion of the vessel.
Lease Commitments
We lease facilities and equipment as well as charter vessels under non-cancelable operating leases and vessel charters expiring at various dates through 2031. Future minimum rental payments at December 31, 2018 are as follows (in thousands):
|
| | | | | | | | | | | |
| | Vessels | | Facilities and Other | | 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 commitments | $ | 444,273 |
| | $ | 36,451 |
| | $ | 480,724 |
|
For the years ended December 31, 2018, 2017 and 2016, total rental expense was approximately $147.8 million, $114.5 million and $87.8 million, respectively.
We sublease some, all of our facilities under non-cancelable sublease agreements. For the years ended December 31, 2018, 2017 and 2016, total rental income was $1.4 million, $1.3 million and $1.6 million, respectively. As of December 31, 2018, the minimum rentals to be received in the future totaled $3.5 million.
In January 2016, we entered into an agreement to lease back our former office and warehouse property located in Aberdeen, Scotland for 15 years with two five-year options to extend the lease. The annual minimum lease payment is approximately $0.8 million.planned major capital commitments have been completed.
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 other legal proceedings, some involving claims for personal injury under the General Maritime Laws of the United States and the Jones Act based on alleged negligence.Act. In addition, from time to time we incurreceive other claims, such as contract and employment-related disputes, in the normal course of business.
Note 1518 — Statement of Cash Flow Information
The following table provides supplemental cash flow information (in thousands):
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Interest paid, net of interest capitalized | $ | 7,369 |
| | $ | 10,367 |
| | $ | 18,749 |
| Interest paid, net of interest capitalized | $ | 15,943 | | | $ | 1,909 | | | $ | 7,369 | |
| Income taxes paid | 5,705 |
| | 6,015 |
| | 5,635 |
| Income taxes paid | 7,434 | | | 8,856 | | | 5,705 | |
Our non-cash investing activitiescapital additions include the acquisition of property and equipment for which payment has not been made. As of December 31, 20182020 and 2017,2019, these non-cash capital additions totaled $9.9$1.6 million and $16.9$10.2 million, respectively.
Note 1619 — 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, 20182020 (in thousands):
| | | | | | | | | | | |
| Allowance
for
Credit
Losses | | Deferred
Tax Asset
Valuation
Allowance |
| | | |
| Balance at December 31, 2017 | $ | 2,752 | | | $ | 12,337 | |
| | | |
Deductions (1) | (2,752) | | | 0 | |
Adjustments (2) | 0 | | | 5,603 | |
| Balance at December 31, 2018 | 0 | | | 17,940 | |
| | | |
| | | |
Adjustments (2) | 0 | | | 691 | |
| Balance at December 31, 2019 | 0 | | | 18,631 | |
Additions (3) | 2,684 | | | 0 | |
| | | |
Adjustments (2) (4) | 785 | | | 1,091 | |
| Balance at December 31, 2020 | $ | 3,469 | | | $ | 19,722 | |
|
| | | | | | | |
| | Allowance for Uncollectible Accounts | | Deferred Tax Asset Valuation Allowance |
| | | | |
| Balance at December 31, 2015 | $ | 350 |
| | $ | 1,936 |
|
Additions (1) | 1,778 |
| | — |
|
Deductions (2) | (350 | ) | | — |
|
Adjustments (3) | — |
| | 1,835 |
|
| Balance at December 31, 2016 | 1,778 |
| | 3,771 |
|
Additions (1) (4) | 1,206 |
| | 2,788 |
|
Deductions (2) | (232 | ) | | — |
|
Adjustments (3) | — |
| | 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 |
|
| |
(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 increase in valuation allowance primarily reflects additional net operating losses in Brazil and in our Robotics segment in the U.K. for which insufficient future taxable income exists to offset the losses. |
| |
(4) | 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. |
| |
(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. |
(2)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.
(3)The additions in allowance for credit losses reflect credit loss reserves during 2020.
(4)The adjustment in allowance for credit losses reflects provision for current expected credit losses upon the adoption of ASU No.2016-13 on January 1, 2020.
See Note 2 for a detailed discussion regarding our accounting policy on accounts and notes receivable and allowance for uncollectible accounts andcredit losses as well as the adoption of ASU No.2016-13. See Note 79 for a detailed discussion of the valuation allowance related to our deferred tax assets.
Note 1720 — 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). |
(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 18) and of our note receivable that is accounted for as an investment in available-for-sale debt securities (Note 3)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. Our actual results may differ from our estimates, and these differences could be positive or negative.As of December 31, 2020, there were no financial instruments measured at fair value on a recurring basis. The following tables providetable provides additional information relating to those financial instruments measured at fair value on a recurring basis as of December 31, 2019 (in thousands):
|
| | | | | | | | | | | | | | | | | |
| | Fair Value Measurements at
December 31, 2018 Using | | | | 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 |
| | |
| | | | Fair Value Measurements at
December 31, 2017 Using | | | | Valuation Approach | | Fair Value at December 31, 2019 | | Valuation
Approach |
| | Level 1 | | Level 2 | | Level 3 | | Total | | | Level 1 | | Level 2 | | Level 3 | | Total | |
| Assets: | | | | | | | | | Assets: | | | | | | | | | |
| Note receivable | $ | — |
| | $ | 3,758 |
| | $ | — |
| | $ | 3,758 |
| | (c) | |
| Interest rate swaps | — |
| | 966 |
| | — |
| | 966 |
| | (c) | Interest rate swaps | $ | 0 | | | $ | 44 | | | $ | 0 | | | $ | 44 | | | (c) |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | Liabilities: | |
| Foreign exchange contracts — hedging instruments | — |
| | 12,467 |
| | — |
| | 12,467 |
| | (c) | Foreign exchange contracts — hedging instruments | 0 | | | 401 | | | 0 | | | 401 | | | (c) |
| Foreign exchange contracts — non-hedging instruments | — |
| | 6,308 |
| | — |
| | 6,308 |
| | (c) | Foreign exchange contracts — non-hedging instruments | 0 | | | 601 | | | 0 | | | 601 | | | (c) |
| Total net liability | $ | — |
| | $ | 14,051 |
| | $ | — |
| | $ | 14,051 |
| | Total net liability | $ | 0 | | | $ | 958 | | | $ | 0 | | | $ | 958 | | |
The principal amount and estimated fair value of our long-term debt are as follows (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | |
| December 31, |
| 2020 | | 2019 |
| Principal Amount (1) | | Fair Value (2) (3) | | Principal Amount (1) | | Fair Value (2) (3) |
| | | | | | | |
| | | | | | | |
| Term Loan (matures December 2021) | $ | 29,750 | | | $ | 28,969 | | | $ | 33,250 | | | $ | 32,959 | |
Nordea Q5000 Loan (matures January 2021) (4) | 53,572 | | | 53,598 | | | 89,286 | | | 89,398 | |
| MARAD Debt (matures February 2027) | 56,410 | | | 62,318 | | | 63,610 | | | 68,643 | |
| 2022 Notes (mature May 2022) | 35,000 | | | 33,513 | | | 125,000 | | | 134,225 | |
| 2023 Notes (mature September 2023) | 30,000 | | | 28,650 | | | 125,000 | | | 162,188 | |
| 2026 Notes (mature February 2026) | 200,000 | | | 211,383 | | | 0 | | | 0 | |
| Total debt | $ | 404,732 | | | $ | 418,431 | | | $ | 436,146 | | | $ | 487,413 | |
(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, the 2023 Notes and the 2026 Notes was determined using Level 1 fair value inputs under the market approach. The fair value of the term loans, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level2 fair value inputs under the market approach, which was determined using a third-party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms.
(3)The principal amount and estimated fair value of the 2022 Notes, the 2023 Notes and the 2026 Notes are for the entire instrument inclusive of the conversion feature reported in shareholders’ equity.
(4)The maturity date of the Nordea Q5000 Loan was extended from April 2020 to January 2021 as a result of an amendment to the Nordea Credit Agreement in March2020. We repaid the Nordea Q5000 Loan in January 2021. (Note 8).
|
| | | | | | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | Principal Amount (1) | | Fair Value (2) | | Principal Amount (1) | | Fair Value (2) |
| | | | | | | | |
| Term Loan (matures April 2020) | $ | 33,693 |
| | $ | 33,314 |
| | $ | 97,500 |
| | $ | 98,231 |
|
| Nordea Q5000 Loan (matures April 2020) | 125,000 |
| | 122,500 |
| | 160,714 |
| | 160,111 |
|
| MARAD Debt (matures February 2027) | 70,468 |
| | 74,406 |
| | 77,000 |
| | 82,058 |
|
| 2022 Notes (mature May 2022) | 125,000 |
| | 114,298 |
| | 125,000 |
| | 124,219 |
|
| 2023 Notes (mature September 2023) | 125,000 |
| | 114,688 |
| | — |
| | — |
|
| 2032 Notes (redeemed May 2018) | — |
| | — |
| | 60,115 |
| | 60,040 |
|
| Total debt | $ | 479,161 |
| | $ | 459,206 |
| | $ | 520,329 |
| | $ | 524,659 |
|
| |
(1) | Principal amount includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 6 for additional disclosures on our long-term debt. |
| |
(2) | The estimated fair value of the 2022 Notes, the 2023 Notes and the 2032 Notes was determined using Level 1 inputs under the market approach. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach, which was determined using a third party evaluation of the remaining average life and outstanding principal balance of the indebtedness as compared to other obligations in the marketplace with similar terms. |
| |
(3) | The principal amount and fair value of the 2022 Notes, the 2023 Notes and the 2032 Notes are for the entire instrument inclusive of the conversion feature reported in shareholder’s equity. |
Note 1821 — 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 ourthe Nordea Q5000 Loan borrowings (Note 6)8). These swap contracts which are settled monthly, beganexpired in June 2015 and extend through April 2020. Our interest rate swap contracts qualifyqualified for cash flow hedge accounting treatment. The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.
In February 2013, we entered into foreign currency exchange contracts to hedge our foreign currency exposure associated with the Grand CanyonII and Grand CanyonIII charter payments denominated in the Norwegian kroner through July 2019 and February 2020, respectively. Unrealized losses associated with the effectiveA portion of our foreign currency exchange contracts that qualifyqualified for hedge accounting treatment are reflected in “Accumulated other comprehensive loss” in the shareholders’ equity section of the accompanying consolidated balance sheets (net of tax). Changes in unrealized losses associated with the foreign currency exchange contractstreatment.
We had no derivative instruments that are notwere designated as cash flow hedges are reflected in “Other income (expense), net” in the accompanying consolidated statementshedging instruments as of operations. Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying consolidated statements of operations. The amount of ineffectiveness associated with our foreign currency exchange contracts was immaterial for all periods presented.
December 31, 2020. The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments as of December 31, 2019 (in thousands):
|
| | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
| Asset Derivative Instruments: | | | | | | | |
| Interest rate swaps | Other current assets | | $ | 863 |
| | Other current assets | | $ | 311 |
|
| Interest rate swaps | Other assets, net | | 201 |
| | Other assets, net | | 655 |
|
| | | | $ | 1,064 |
| | | | $ | 966 |
|
| | | | | | | | |
| Liability Derivative Instruments: | | | | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 5,857 |
| | Accrued liabilities | | $ | 7,492 |
|
| Foreign exchange contracts | Other non-current liabilities | | 354 |
| | Other non-current liabilities | | 4,975 |
|
| | | | $ | 6,211 |
| | | | $ | 12,467 |
|
| | | | | | | | | | | |
| December 31, |
| 2019 |
| Balance Sheet
Location | | Fair
Value |
| Asset Derivative Instruments: | | | |
| Interest rate swaps | Other current assets | | $ | 44 | |
| | | |
| | | $ | 44 | |
| | | |
| Liability Derivative Instruments: | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 401 | |
| | | |
| | | |
| | | |
| | | $ | 401 | |
We had no derivative instruments that were not designated as hedging instruments as of December 31, 2020. The following table presents the balance sheet location and fair value of our derivative instruments that were not designated as hedging instruments as of December 31, 2019 (in thousands):
|
| | | | | | | | | | | |
| | December 31, |
| | 2018 | | 2017 |
| | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
| Liability Derivative Instruments: | | | | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 3,454 |
| | Accrued liabilities | | $ | 3,133 |
|
| Foreign exchange contracts | Other non-current liabilities | | 530 |
| | Other non-current liabilities | | 3,175 |
|
| | | | $ | 3,984 |
| | | | $ | 6,308 |
|
| | | | | | | | | | | |
| December 31, |
| 2019 |
| Balance Sheet
Location | | Fair
Value |
| Liability Derivative Instruments: | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 601 | |
| | | |
| | | $ | 601 | |
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, 2018, $4.0 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 | | Unrealized Gain (Loss) Recognized in OCI |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Foreign exchange contracts | $ | (1,453 | ) | | $ | 2,672 |
| | $ | 3,630 |
| Foreign exchange contracts | $ | (54) | | | $ | (315) | | | $ | (1,453) | |
| Interest rate swaps | 606 |
| | 651 |
| | (1,264 | ) | Interest rate swaps | (41) | | | (365) | | | 606 | |
| | $ | (847 | ) | | $ | 3,323 |
| | $ | 2,366 |
| | $ | (95) | | | $ | (680) | | | $ | (847) | |
| | | | Location of Gain (Loss) Reclassified from Accumulated OCI into Earnings | | Gain (Loss) Reclassified from Accumulated OCI into Earnings | | Location of Gain (Loss)
Reclassified from
Accumulated OCI
into Earnings | | Gain (Loss) Reclassified from
Accumulated OCI into Earnings |
| | | Year Ended December 31, | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | | | | |
| Foreign exchange contracts | Cost of sales | | $ | (7,709 | ) | | $ | (12,300 | ) | | $ | (10,827 | ) | Foreign exchange contracts | Cost of sales | | $ | (455) | | | $ | (6,125) | | | $ | (7,709) | |
| Interest rate swaps | Net interest expense | | 508 |
| | (615 | ) | | (2,024 | ) | Interest rate swaps | Net interest expense | | 3 | | | 655 | | | 508 | |
| | | $ | (7,201 | ) | | $ | (12,915 | ) | | $ | (12,851 | ) | | $ | (452) | | | $ | (5,470) | | | $ | (7,201) | |
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 Loss
Recognized in Earnings | | Loss Recognized in Earnings |
| | Year Ended December 31, |
| | 2020 | | 2019 | | 2018 |
| | | | | | | |
| Foreign exchange contracts | Other income (expense), net | | $ | (81) | | | $ | (378) | | | $ | (901) | |
| | | $ | (81) | | | $ | (378) | | | $ | (901) | |
|
| | | | | | | | | | | | | |
| | Location of Gain (Loss) Recognized in Earnings | | Gain (Loss) Recognized in Earnings |
| | | Year Ended December 31, |
| | | 2018 | | 2017 | | 2016 |
| | | | | | | | |
| Foreign exchange contracts | Other income (expense), net | | $ | (901 | ) | | $ | 818 |
| | $ | 1,198 |
|
| | | | $ | (901 | ) | | $ | 818 |
| | $ | 1,198 |
|
Note 1922 — 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 period.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, |
| 2020 | | | | | | | |
| Net revenues | $ | 181,021 | | | $ | 199,147 | | | $ | 193,490 | | | $ | 159,897 | |
| Gross profit | 2,010 | | | 29,576 | | | 34,628 | | | 13,695 | |
| Net income (loss) | (13,928) | | | 5,450 | | | 24,445 | | | 4,117 | |
| Net income (loss) attributable to common shareholders | (11,938) | | | 5,450 | | | 24,499 | | | 4,163 | |
| Basic earnings (loss) per common share | $ | (0.09) | | | $ | 0.04 | | | $ | 0.16 | | | $ | 0.03 | |
| Diluted earnings (loss) per common share | $ | (0.09) | | | $ | 0.04 | | | $ | 0.16 | | | $ | 0.03 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| |
| | | | | | | |
| | | | | | | |
| 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 | |
|
| | | | | | | | | | | | | | | |
| | Quarter Ended |
| | March 31, | | June 30, | | September 30, | | December 31, |
| 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 | ) |
| 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 | ) |
|
| | | | | | | | | | | | | | | |
| | Quarter Ended |
| | March 31, | | June 30, | | September 30, | | December 31, |
| 2017 | | | | | | | |
| Net revenues | $ | 104,528 |
| | $ | 150,329 |
| | $ | 163,260 |
| | $ | 163,266 |
|
| Gross profit (loss) | (825 | ) | | 18,367 |
| | 21,141 |
| | 23,483 |
|
Net income (loss) (1) | (16,415 | ) | | (6,403 | ) | | 2,290 |
| | 50,580 |
|
| Basic earnings (loss) per common share | $ | (0.11 | ) | | $ | (0.04 | ) | | $ | 0.02 |
| | $ | 0.34 |
|
| Diluted earnings (loss) per common share | $ | (0.11 | ) | | $ | (0.04 | ) | | $ | 0.02 |
| | $ | 0.34 |
|
| |
(1) | Amount in the fourth quarter of 2017 included a $51.6 million income tax benefit as a result of the U.S. tax law changes enacted in December 2017. |
Item 9. Changes in and Disagreements with Accountants on Accounting andFinancial Disclosure
None.
Item 9A. Controls and Procedures
(a) Disclosure Controls and Procedures. We carried out an evaluation, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as such term is defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended (the “Exchange Act”).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, 20182020 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 Securities and Exchange Commission’sSEC’s rules and forms;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 Securities Exchange Act of 1934, as amended.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 U.S. generally accepted accounting principles.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;company, (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles,GAAP, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company;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 riskrisks 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, 2018.2020. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in InternalControl-Integrated Framework (2013). Based on this assessment,those criteria, management concluded that, as of December 31, 2018,2020, our internal control over financial reporting was effective based on those criteria.effective.
The effectiveness of our internal control over financial reporting as of December 31, 20182020 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in its report which appears in Item 88. Financial Statements and Supplemental Data of this Annual Report on Form 10-K.
(c) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 20182020 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 Securities Exchange Act of 1934 in connection with our 20192021 Annual Meeting of Shareholders to be held on May 15, 2019.19, 2021. See also “Executive Officers of the Company” appearing in Part I of this Annual Report.
Code of Ethics
We have a Code of Business Conduct and Ethics for all of our directors, officers and employees as well as a Code of Ethics for Chief Executive Officer and SeniorFinancial Officers specific to those officers. Copies of these documents are available at our Website www.helixesg.comwebsite www.HelixESG.com under Corporate Governance(which can be accessed by clicking the “Investors” tab and then the “Governance” tab). Interested parties may also request a free copy of these documents from:
Helix Energy Solutions Group, Inc.
ATTN: Corporate Secretary
3505 W. Sam Houston Parkway N., Suite 400
Houston, Texas 77043
Item 11. Executive Compensation
The information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 in connection with our 20192021 Annual Meeting of Shareholders to be held on May 15, 2019.19, 2021.
Item 12. Security Ownership of Certain Beneficial Owners and Managementand 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 Securities Exchange Act of 1934 in connection with our 20192021 Annual Meeting of Shareholders to be held on May 15, 2019.19, 2021.
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 Securities Exchange Act of 1934 in connection with our 20192021 Annual Meeting of Shareholders to be held on May 15, 2019.19, 2021.
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 Securities Exchange Act of 1934 in connection with our 20192021 Annual Meeting of Shareholders to be held on May 15, 2019.19, 2021.
PART IV
Item 15. Exhibits Exhibit and Financial Statement Schedules
(1) Financial Statements
The following financial statements included on pages 4546 through 8486 in this Annual Report are for the fiscal year ended December 31, 2018.2020.
•Report of Independent Registered Public Accounting Firm — KPMG
•Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — KPMG
•Consolidated Balance Sheets as of December 31, 20182020 and 20172019
•Consolidated Statements of Operations for the Years Ended December 31, 2018, 20172020, 2019 and 20162018
•Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2018, 20172020, 2019 and 20162018
•Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2018, 20172020, 2019 and 20162018
•Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 20172020, 2019 and 20162018
•Notes to Consolidated Financial Statements
All financial statement schedules are omitted because the information is not required or because the information required is in the financial statements or notes thereto.
(2) Exhibits
The documents set forth below are filed or furnished herewith or incorporated by reference to the location indicated. Pursuant to Item 601(b)(4)(iii), the Registrant agrees to forward to the commission, upon request, a copy of any instrument with respect to long-term debt not exceeding 10% of the total assets of the Registrant and its consolidated subsidiaries.
|
| | | | | | | | | | | | | |
ExhibitsExhibit Number | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 3.1 | | | | |
| 3.2 | | | | |
| 4.1 | | | | |
| 4.2 | | | | |
4.24.3 | | | | |
4.34.4 | | | | |
4.44.5 | | | | |
4.54.6 | | | | |
4.64.7 | | | | |
4.74.8 | | | | |
4.84.9 | | | | |
4.94.10 | | | | |
4.104.11 | | | | |
4.114.12 | | | | |
4.124.13 | | | | |
4.134.14 | | | | |
| | | | | | | | | | | | | | |
4.14Exhibit Number | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 4.15 | | | | |
|
| 4.16 | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
4.15 | | | | |
4.164.17 | | | | |
4.174.18 | | | | |
4.184.19 | | | | |
4.194.20 | | | | |
4.204.21 | | | | |
4.214.22 | | 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. | | |
| 4.23 | | | | |
| 4.24 | | | | |
4.224.25 | | | | |
| | | | | | | | | | | | | | |
| Exhibit Number | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 4.26 | | | | |
4.234.27 | | | | |
4.244.28 | | | | |
| 4.29 | | | | |
| 4.30 | | | | |
| 10.1 * | | | | |
| 10.2 * | | | | |
| 10.3 * | | | | |
|
| | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
10.4 * | | | | |
10.5 * | | | | |
10.6 * | | | | |
10.710.4 * | | | | |
10.8 * | | | | |
10.910.5 * | | | | |
| 10.6 * | | | | |
| 10.7 * | | | | |
10.1010.8 * | | | | |
10.11 * | | | | |
10.1210.9 * | | | | |
10.1310.10 * | | | | |
| 10.11 * | | | | |
10.1410.12 * | | | | |
10.1510.13 * | | | | |
10.16 * | | | | |
| | | | | | | | | | | | | | |
10.17Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 10.14 * | | | | |
10.1810.15 * | | | | |
| 10.16 * | | | | |
10.1910.17 * | | | | |
10.2010.18 * | | | | |
| 10.19 * | | | | |
10.2110.20 | | | | |
10.22 | | | | |
|
| 10.21 | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
10.23 | | | | |
10.2410.22 | | | | |
10.2510.23 | | | | |
10.2610.24 | | | | |
10.2710.25 | | | | |
10.2810.26 | | | | |
10.2910.27 | | | | |
| 14.1 | | | | |
| 21.1 | | | | |
| 23.1 | | | | |
| 31.1 | | | | |
| 31.2 | | | | |
| | | | | | | | | | | | | | |
32.1Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 32.1 | | | | |
| | | | |
| 101.INS | | XBRL Instance Document. | | Furnished herewithThe instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document |
| 101.SCH | | Inline XBRL Taxonomy Extension Schema Document. | | FurnishedFiled herewith |
| 101.CAL | | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | | FurnishedFiled herewith |
| 101.DEF | | Inline XBRL Taxonomy Extension Definition Linkbase Document. | | Filed herewith |
| 101.LAB | | Inline XBRL Taxonomy Extension Label Linkbase Document. | | Filed herewith |
| 101.PRE | | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | | FurnishedFiled herewith |
101.DEF104 | | Cover Page Interactive Data File (formatted as inline XBRL Definition Linkbase Document.and contained in Exhibit 101). | | FurnishedFiled herewith |
101.LAB | | XBRL Label Linkbase Document. | | Furnished herewith |
| |
* Management contracts or compensatory plans or arrangements *
| Management contracts or compensatory plans or arrangements |
Item 16. Form 10-K Summary
None.
SIGNATURES
Pursuant to the requirements of sectionSection 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. | |
| | | |
| HELIX ENERGY SOLUTIONS GROUP, INC.By: | |
| | | |
| By: | /s/ ERIK STAFFELDT | |
| | Erik Staffeldt | |
| | Executive Vice President and | |
| | Chief Financial Officer | |
February 22, 201925, 2021
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 25, 2021 |
| Owen Kratz | | | |
| | | | |
| /s/ ERIK STAFFELDT | | Executive Vice President and Chief Financial Officer
(principal financial officer and
principal accounting officer) | | February 25, 2021 |
| Erik Staffeldt | | | |
| | | | |
| /s/ AMERINO GATTI | | Director | | February 25, 2021 |
| Amerino Gatti | | | |
| | | | |
Signature | | Title | | Date |
| | | | |
/s/ OWEN KRATZ | | President, Chief Executive Officer and Director
(principal executive officer)
| | February 22, 2019 |
Owen Kratz | | | |
| | | | |
/s/ ERIK STAFFELDT | | Executive Vice President and Chief Financial Officer
(principal financial officer and
principal accounting officer)
| | February 22, 2019 |
Erik Staffeldt | | | |
| | | | |
/s/ AMERINO GATTI | | Director | | February 22, 2019 |
Amerino Gatti | | | |
| | | | |
| /s/ JOHN V. LOVOI | | Director | | February 22, 201925, 2021 |
| John V. Lovoi | | | |
| | | | |
/s/ NANCY K. QUINNAMY H. NELSON | | Director | | February 22, 201925, 2021 |
Nancy K. QuinnAmy H. Nelson | | | |
| | | | |
| /s/ JAN A. RASK | | Director | | February 22, 201925, 2021 |
| Jan A. Rask | | | |
| | | | |
| /s/ WILLIAM L. TRANSIER | | Director | | February 22, 201925, 2021 |
| William L. Transier | | | |
| | | | |
| /s/ JAMES A. WATT | | Director | | February 22, 201925, 2021 |
| James A. Watt | | | |
