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, 20172020
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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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files). þ☑ Yes ¨☐ No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) 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. (Check one):
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Large accelerated filerþ | ☐ | Accelerated filer | ☑ | Accelerated filer ¨
| Non-accelerated filer ¨☐ | Smaller reporting company¨ | ☐ | Emerging growth company¨ |
| | (Do not check if a smaller reporting 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 voting and non-voting common equity held by non-affiliates of the registrant based on the last reported sales priceas of the Registrant’s Common Stock on June 30, 20172020 was approximately $785.8$490.8 million.
The number of shares of the registrant’s Common Stockcommon stock outstanding as of February 20, 201819, 2021 was 148,079,552.150,714,706.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 10, 201819, 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 oil and gasoffshore energy industry and 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, or 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 recently enacted U.S. Tax Cuts and Jobs 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 16 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, and in 2017 expanded our operations into Brazil with the commencement of operations of the Siem Helix1 and Siem Helix2 vessels for Petróleo Brasileiro S.A. (“Petrobras”). Our “life of field” services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities.regions. 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 2017.2020. 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“Certain Definitions” on page 15 for definitions of additional terms commonly used in this Annual Report. Unless otherwise indicated, any reference to Notes herein refers to Notes to Consolidated Financial Statements in Item 8. 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 make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions. Our well intervention fleet expanded following the delivery of the Siem Helix2 chartered vessel in February 2017 and is expected to further expand following the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018 or 2019. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel that went into service for us in May 2017, 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 is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. In April 2015, we and OneSubsea agreed to jointly develop and ordered a 15,000 working p.s.i. intervention riser system (“15K IRS”) for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At December 31, 2017, our total investment in the 15K IRS was $14.9 million inclusive of capitalized interest. The 15K IRS was completed and placed in service in January 2018. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest). At December 31, 2017, our total investment in the ROAM was $3.6 million. The ROAM is expected to be available to customers in the first half of 2018.
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, and expanded our operations into Brazil with the commencement of operations for Petrobras of the Siem Helix1 in April 2017 and the Siem Helix2 in December 2017.regions. Our Well Intervention segment includes our vessels andand/or equipment used to performaccess offshore wells for the purpose of performing well enhancement or decommissioning operations. Our well intervention services primarily invessels include the Gulf of Mexico, North SeaQ4000, the Q5000, the Q7000, the Seawell, the Well Enhancer, and Brazil.two chartered monohull vessels, the Siem Helix1 and the Siem Helix2. Our Well Intervention segment alsowell intervention equipment includes intervention riser systems (“IRSs”), some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”). Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and the Siem Helix1 and Siem Helix2 chartered vessels. We also haveRiserless Open-water Abandonment Module (“ROAM”), some of which we provide on a semi-submersible well intervention vessel under construction, the Q7000. stand-alone basis. Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrillsa ROVDrill, which are designed to complement offshore construction and well intervention services and currently operates 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, including the Grand Canyon II andthe Grand Canyon III that went into service for us in May 2017., 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 1215 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.
Reclamation. 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 ofHP I as an oil and natural gas processing facilities and services to oil and gas companies operating in the deepwater of the Gulf of Mexico, using our HP I vessel.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 in the event ofto 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.trees to increase, which can improve long-term demand for well intervention 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. Over time,We believe we expect long-term demand for well intervention services to increase due to the growing number of subsea tree installations and theoffer efficiency gains from our specialized intervention assets and equipment.assets.
Our well intervention business currently operates seven vessels and various equipment such as IRSs, SILs and the ROAM, providing services primarily in the Gulf of Mexico, Brazil, the North Sea and West Africa.
In the Gulf of Mexico, our multi-servicethe Q4000, a riser-based semi-submersible vessel, the Q4000, has set a series of well intervention “firsts”vessel, has been serving customers in increasingly deeper water without the use of a traditional drilling rig.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 during the fourth quarter of 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 the Siem Helix1 and Siem Helix2 vessels that we charter from Siem Offshore AS (“Siem”). The initial term of the agreements with Petrobras is for four years, with options to extend by agreement of both parties for an additional period of up to four years. The Siem Helix1 commenced operations for Petrobras in April 2017 and the Siem Helix2 commenced operations for Petrobras in December 2017. The initial term of the charter agreements with Siem is for seven years with options to extend.
In the North Sea, the Well Enhancer has performed well intervention, abandonment and coil tubing services since it joined our fleet in the North Sea region in 2009. The Seawell has provided well intervention and abandonment services since 1987. The1987, and the vessel underwent major capital upgrades in 2015 to extend its estimated useful economic life by approximately 15 years. The chartered Skandi Constructor performed well intervention services for us in the North Sea beginning in September 2013 and was returned to its owner in March 2017 upon the expiration of the vessel charter.
In September 2013, we executedThe Q7000, a contract with the same shipyard in Singapore that constructed the Q5000 for the construction of a newbuild semi-submersible well intervention vessel the Q7000, to be built to U.K. North Sea standards. Pursuant to the contractstandards and subsequent amendments, including the third amendment that was entered intocapable of working globally, commenced operations in November2017, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% was paid in December2017, 20%January 2020 and is to be paid on December31, 2018, and 20% is to be paid upon the delivery of the vessel, which at our option can be deferred until December31, 2019.currently performing integrated well intervention operations offshore Nigeria.
In February 2014, we entered into agreementsOur alliance with PetrobrasSchlumberger leverages the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well intervention services offshore Brazil,access and in connection with the Petrobras agreements,control technologies. Through our alliance, we entered into charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohull vessels, the Siem Helix1and Schlumberger jointly developed a 15K IRS and the Siem Helix2. The initial term of the charter agreements with Siem is for seven years from the respective vessel delivery dates with optionsROAM, which are currently available to extend. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. The Siem Helix1 was delivered to us and the charter term began on June 14, 2016. The vessel was accepted by Petrobras and commenced operations on April 14, 2017, at which time we agreed with Petrobras to commence operations at reduced day rates. Our day rates have improved as we addressed most of the items identified in the vessel acceptance process. The Siem Helix2 was delivered to us and the charter term began on February 10, 2017. The vessel was accepted by Petrobras and commenced operations on December 15, 2017 at contracted rates.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. As global marine constructionservices for the oil and gas market and to support operates in deeper waters,offshore renewable energy projects for the use and scope of ROVrenewable energy market. We often integrate our services has expanded. Ourwith 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 48 ROVs, five trenching systems and two ROVDrills.vessels. 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 currently charter vessels on a long-term or a spot basis to support deployment of our robotics operations and we have historically engaged 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. Our vessel charter for the Deep Cygnus was terminated on February 9, 2018, at which time we returned the vessel to its owner.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 services required 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, that can occur offshore, especially in northernNorthern 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 2017,2020, revenues derived from offshore renewablesrenewable energy contracts accounted for 15%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 business. 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 two of our vessels,combines the HP I, the Q4000 and the Q4000, both of which played a key role in the MacondoQ5000 with certain well control and containment efforts and are currently operating in the Gulf of Mexico. Pursuant to an agreement with certain industry participants in exchange for a retainer fee, the HFRS provides these participants with a response resourceequipment that can be named in permit applicationsdeployed to federal and state agencies. The HFRS agreements with individual participants also specify the day ratesrespond to be charged should the HFRS be deployed in connection with a well control incident. TheWe are under agreement providingthrough September 30, 2021 with various operators to provide access to the HFRS was amended effective February 1, 2017 to extendfor well control purposes.
Our Production Facilities segment includes two remaining wells acquired from Marathon Oil Corporation (“Marathon Oil”) in January 2019. These oil and gas properties are associated with the termDroshky Prospect located in offshore Gulf of Mexico Green Canyon Block 244. As part of the agreement by one yeartransaction, Marathon Oil agreed to March 31, 2019 and to reducepay us certain amounts as we complete the retainer fee.P&A work.
GEOGRAPHIC AREAS
We primarily operate in the U.S. Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regionsregions. Our North Sea operations are subject to seasonal changes in demand, which generally peaks in the summer months and declines in 2017 expanded our operations into Brazil with the commencement of operations of the Siem Helix1 and Siem Helix2 vessels for Petrobras.winter months. See Note 1215 for revenues as well as property and equipment net of accumulated depreciation, by geographic areas.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 capital expenditure 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 percentpercentages of consolidated revenues from major customers those whose total represented(those representing 10% or more of our consolidated revenues isrevenues) are as follows: 20172020 — BP (19%), Petrobras (13%(28%) and Talos (10%BP (17%); 2019 — Petrobras (29%), 2016 — BP (17%(15%) and Shell (11%(13%),; and 20152018 — Shell (16%Petrobras (28%) and Talos (11%BP (15%). We provided services to over 4050 customers in 2017.2020.
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 also important.operate safely are important factors to competing in these markets. Our principal competitors in the well intervention business include Island Offshore, Wild Well ControlBaker Hughes, C-Innovation, Expro, Oceaneering, TIOS and international drilling contractors. Our principal competitors in the robotics business include C-Innovation, LLC, DeepOcean, Group, DOF Subsea, Group, Fugro, N.V.Oceaneering 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-incident workplace is based on the belief that all incidents should be preventable. Helix strivesare preventable and that we manage our working conditions 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 well intervention and robotics 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
Many aspectsWe provide services primarily in deepwater in the Gulf of the offshore marine construction industryMexico, Brazil, North Sea, Asia Pacific and West Africa regions, and as such we are subject to extensive governmental regulations. Wenumerous laws and regulations, including international treaties, flag state requirements, environmental laws and regulations, requirements for obtaining operating and navigation licenses, local content requirements, and other national, state and local laws and regulations in force in the jurisdictions in which our vessels and other assets operate or are registered, all of which can significantly affect the ownership and operation of our vessels and other assets. Beginning in 2019 we operate end of life offshore oil and gas wells, some of which are producing and which we plan to ultimately decommission. Being an operator of wells subjects us to additional regulatory oversight from the Bureau of Ocean Energy Management (“BOEM”) and the Bureau of Safety and Environmental Enforcement (“BSEE”).
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 the Bureau of Ocean Energy Management (the “BOEM”), the Bureau of Safety(BOEM, BSEE and Environmental Enforcement (the “BSEE”), the Office of Natural Resource Revenue (the “ONRR”)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 (“OSHA”) and comparable state laws that regulate the protection of employee health and safety for our land-based operations.
International Overview
We provide services globally and generally can be subject to local laws and regulations wherever we operate. Those laws and regulations generally govern environmental, labor, health and safety and other matters. The regulatory regimes of the U.K. and Brazil are of particular importance given the locations of our current operations. The U.K. Continental Shelf in the North Sea is regulated by the Oil and Gas Authority (the “OGA”) in accordance with the Petroleum Act 1998. The OGA controls 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 a specifiedthe working environment, as well as standards for diving procedures, equipment and diver health. These North Sea standards are some of the most stringent worldwide. In the absence of any specific regulation, our North Sea operations adhere to standards set by the International Marine Contractors Association and the International Maritime Organization. In addition, we operate in other foreign jurisdictions each with their own laws and regulations to which we are subject.
With respect to North Sea operations, weWe 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.
Coast GuardOur operations in Brazil are predominantly regulated by the Brazilian National Agency of Petroleum, Natural Gas and Biofuels, the federal government agency responsible for the regulation of the oil sector. Additional regulatory oversight is provided, among others, by the Brazilian Institute of the Environment and Renewable Natural Resources, which oversees Brazilian environmental legislation, implements the National Environmental Policy and exercises control and supervision of the use of natural resources, the Brazilian Health Regulatory Agency, which regulates products and services subject to health regulations, and the Ministry of Labor, which regulates a variety of subjects including work-related accident prevention and use of machinery and equipment.
Operating Certification
Each of our vessels is subject to regulatory requirements of the country in which the vessel is registered, also known as the flag state. In addition, the country in which a vessel is operating may have its own requirements with respect to safety and environmental protections. These requirements must be satisfied in order for the vessel to operate. Flag state requirements are largely established by international treaties such as MARPOL, SOLAS, the ISM Code and the MODU Code, and in some instances, specific requirements of the flag state. These include engineering, safety, safe manning and other requirements related to the maritime industry. Each of our vessels must also maintain its “in-class” status with a classification society, evidencing that the vessel has been built and maintained in accordance with the rules of the classification society and complies with applicable flag state rules and international conventions. Our vessels generally must undergo a class survey once every five years. In the U.S., the Coast Guard sets safety standards and is authorized to investigate vesselmarine incidents, recommend safety standards, and diving accidents as well as other marine casualty incidents and to recommend improved safety standards. The Coast Guard is also authorized to inspect vessels at will. We also adhere to manning requirements which are implemented by the Coast Guard for operations on the U.S. Outer Continental Shelf (“OCS”). We are required by various governmental and quasi-governmental agencies to obtain various permits, licenses and certificates with respect to our operations.
BOEMLocal Content Requirements and BSEE
The development and operation of oil and gas properties located on the OCS of the United States is regulated primarily by the BOEM and BSEE. Among other requirements, the BOEM requires lessees of OCS properties to post bonds or provide other adequate financial assurance in connection with the plugging and abandonment of wells located offshore and the removal of all production facilities. As a service company, we are not subject to these regulations, but do depend on the demand for our services from the oil and gas industry, and, therefore our business is affected by laws and regulations as well as changing tax laws and policies relating to the oil and gas industry in general.
The Deepwater Horizon incident in April 2010 resulted in enhanced standards being implemented for companies engaged in the development of offshore oil and gas wells. These standards are determined and implemented by BSEE. The applicable standards now include Notice to Lessees (NTL), NTL 2010-N06 (Environmental NTL), NTL 2010-N10 (Compliance and Evaluation NTL), NTL 2013-N02 (Significant Change to Oil Spill Response Plan Worst Case Scenario), the Final Drilling Safety Rule, and a rule regarding Production Measurement Documents.
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 (WCR), which updated requirements for equipment and operations for well control activities associated with drilling, completion, workover and decommissioning operations. Specifically, the “Well Control Rule” resulted in reforms that establish the following items: (1) incorporation of the latest industry standards that establish minimum baseline requirements for the design, manufacture, repair, and maintenance of blowout preventers (“BOPs”); (2) additional controls over the maintenance and repair of BOPs; (3) use of dual shear rams in deepwater BOPs; (4) requirement that BOP systems include technology that allows the drill pipe to be centered during shearing operations; (5) more rigorous third-party certification of the shearing capability of BOPs; (6) expanded accumulator capacity and operational capabilities for increased functionality; (7) real-time monitoring capability for deep-water and high-temperature/high-pressure drilling activities; (8) establishment of criteria for the testing and inspection of subsea well containment equipment; (9) increased reporting of BOP failure data to the BSEE and the Original Equipment Manufacturers; (10) expectations of what constitutes a safe drilling margin and allowance for alternative safe drilling margins when justified; (11) requirements for the use of accepted engineering principles and establishment of general performance criteria for drilling and completion equipment; (12) establishment of additional requirements for using ROVs to function certain components on the BOP stack; (13) requirements for adequate centralization of casing during cementing; and (14) making the testing frequency of BOPs used on workover and decommissioning operations the same as drilling operations.
The Well Control Rule further provides guidance for the design and operation of remotely operated tools including the requirement that ROV tooling used on offshore subsea systems be held to the industry standards incorporated in API 17H, First Edition. On December 29, 2017, BSEE proposed to amend the WCR to reduce certain unnecessary regulatory burdens imposed under the existing regulations, while correcting errors and clarifying current requirements. Comments were due on January 29, 2018. WC rule requirements can significantly affect our operations.
The Jones Act (Coastwise Trade Rules)Cabotage Rules
We are alsosubject 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 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 Jonesthe “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. This statuteThe Jones Act has been applied to offshore oil and gas work in the U.S. The Jones Act is interpreted in large partthrough interpretations by letter rulings of the CBP. The cumulative effect of these letter rulings has been to establish a framework for offshore operators to understand when an operation can be carried out by a foreign flag vessel and when it must be carried out by a coastwise qualified U.S. flag vessel.
In January 2017, CBP proposed a modification or revocationBOEM 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 numerous prior letter rulings regarding the interpretation of the Jones Act, which would have significantly changed how foreign flag vessels could operateoil and gas properties located on the OCS underis 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 Jones Act. While CBP withdrew this proposalP&A of wells located offshore and the removal of production facilities. Following the Deepwater Horizon incident in May 2017, CBP, its parent agency, the Department of Homeland Security, or the U.S. Congress could revisit the issue through a rulemaking, the Customs Bulletin, or legislation. If a policy change occurred along the lines proposed by CBP in January 2017, such a new interpretation of the Jones Act could adversely impact the operations of non-coastwise qualified vessels workingApril 2010, BSEE implemented enhanced standards for companies engaged in the U.S. Gulfdevelopment of Mexico,offshore oil and could potentially make it more difficult and/or costlygas wells. As an operator of wells, we are also required to perform our offshore serviceshave a BSEE-approved Oil Spill Response Plan. In April 2016 BSEE issued the final Oil and Gas and Sulfur Operations in the area. Industry would undoubtedly challenge any such actionOuter Continental Shelf-Blowout Preventer Systems and Well Control Rule, which updated requirements for equipment and operations for well control activities associated with drilling, completion, workover and decommissioning operations, and provided further guidance for the design and operation of remotely operated tools. In May 2019, BSEE released revised regulations for well control and blowout preventer systems designed to improve operations on the extent that it seeks to limit the ability of non-coastwise qualified vessels from performing the operations they are currently permitted to perform, but such regulatory or legislative action could create the same uncertainty in the industry as the January 2017 CBP proposal did.OCS. The regulations address offshore oil and gas drilling, completions, workovers, and decommissioning activities, and we have incorporated them into our operations.
Other Federal and State Regulatory AgenciesImpact
Additional proposals and proceedings before various international, federal and state regulatory agencies and the courts could affect the oilenergy industry, including curtailing production and gas industry.demand for fossil fuels. We cannot predict when or whether any such proposals may become effective.effective, or how they will be interpreted or enforced.
These regulatory developments and legislative initiatives may curtail production and demand for fossil fuels such as oil and natural gas in areas
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 both state and federal, 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 suchthose 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 U.S. is one of approximately 170 member countries party to the International Maritime Organization (“IMO”), an agency of the United Nations responsible for developing measures to improve the safety and security of international shipping and to prevent marine pollution from ships. The IMO has negotiated MARPOL, which imposes on the shipping industry environmental standards relating to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage, and air emissions.
OPA 90
The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on offshore facility owners or operators 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 or bareboat charterers of vessels. Any of these entities or persons can be “responsible parties” and are jointly, severally and strictly liable for removal costs and damages arising from facility and vessel oil spills or threatened spills up to their limits of liability (except if the limits are broken as discussed below). There are few exceptions and defenses to OPA, including if the spill results solely from the act or omission of certain third parties under specified circumstances, an act of God or an act of war.spills. Failure to comply with OPA may result in the assessment of civil, administrative and criminal penalties. In a final rule published on November 19, 2015, the Coast Guard increased liability limits under OPA 90 equal to the greater of $939,800 or $1,100 per gross ton for vessels other than tankers. Liability limits are higher for certain types of facilities and could apply if our operations resulted in Responsible Party status for a spill from such a facility. The liability limits are not applicable, however, (i) if the spill is caused by gross negligence or willful misconduct, (ii) if the spill results from violation of a federal safety, construction or operating regulation, or (iii) if a party fails to report a spill or fails to cooperate fully in the cleanup. Few defenses exist to the liability imposed under OPA.
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 suchthose vessels. We currently own and operate five vessels over 300 gross tons. We have providedA number of foreign jurisdictions also require us to present satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels.responsibility. We satisfy these requirements through appropriate insurance coverage.
Clean Water ActPollution
TheFor 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. The controls and restrictions imposed under the Clean Water Act have become more stringent over time, and it is possible that additional restrictions will be imposed in the future. Permits must be obtained to discharge pollutants into state and federal waters.
The Clean Water Act also establishes the National Pollutant Discharge Elimination System (“NPDES”) permitting program, which governs discharges of pollutants into navigable waters of the United States. Pursuant to the NPDES program, EPA has issuedissues Vessel General Permits (“VGPs”) covering discharges incidental to normal vessel operations. The current Vessel General Permit (the “2013 VGP”), which became effective on December 19, 2013, applies to commercial vessels that are at least 79 feet in length. The 2013 VGP requires vessel owners and operators to adhere to “best management practices” to manage the covered discharges that occur normally in the operation of a 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. The 2013 VGP has also implemented more stringent requirements than the prior Vessel General Permit, including numeric technology-based effluent limitations for ballast water discharges. The 2013 VGP expires on December 18, 2018. We expect a new VGP to be proposed this year. Additionally, certain state regulations and the VGPVGPs 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.
The Clean Water Act provides for civil, criminal and administrative penalties for any unauthorized discharge of oil and other hazardous substances and imposes liability on Responsible Parties for the costs of cleaning up any environmental contamination caused by the release of a hazardous substance and for natural resource damages resulting from the release. 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. Our vessels carry diesel fuel for their own use. Offshore facilities and vessels operated by us have facility and vessel response plans to deal with potential spills. We believe that our operations comply in all material respects withInternationally, the requirements of the Clean Water Act and state statutes enacted to controlBWM Convention covers mandatory ballast water pollution.exchange requirements.
Air Act
The U.S. Supreme Court has held that greenhouse gasses are an air pollutant under the federal Clean Air ActPollution and thus subject to regulation by the EPA. In October 2009, the EPA published a final rule requiring the reporting of greenhouse gas emissions from specified large greenhouse gas sources in the United States on an annual basis, beginning in 2011 for emissions occurring in 2010. In November 2010, the EPA expanded its greenhouse reporting rule to include onshore petroleum and natural gas production, offshore petroleum and natural gas production, onshore natural gas processing, natural gas transmission, underground natural gas storage, liquefied natural gas storage, liquefied natural gas import and export, and natural gas distribution facilities. As of 2011, reporting of greenhouse gas emissions from such facilities is required on an annual basis under this expanded rule.Emissions
A variety of regulatory developments, proposals orand requirements and legislative initiatives that are focused on restricting the emissions of carbon dioxide, methane and other greenhouse gases have been introduced inapply to the domestic and international regionsjurisdictions in which we operate. For example, Congress has from time to time considered legislationAnnex VI of MARPOL addresses air emissions, including emissions of sulfur and nitrous oxide, and requires the use of low sulfur fuels worldwide in both auxiliary and main propulsion diesel engines on vessels. The IMO designates the waters off North America as an Emission Control Area, meaning that vessels operating in the U.S. must use fuel with a sulfur content no greater than 0.1%. Directives have been issued designed to reduce greenhouse gas emissions,the emission of nitrogen oxides and almost one-half ofsulfur oxides. These can impact both the states already have taken legal measures to reduce greenhouse gas emissions, primarily throughfuel and the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap and trade programs. More stringent regulations under the Clean Air Act or other similar federal or state law could materially impact our business.engines that may be used onboard vessels.
CERCLA
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) contains provisions requiringrequires 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. Under CERCLA, those persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. Third parties may also file claims for personal injury and property damage allegedly caused by the release of hazardous substances.
We operate in foreign jurisdictions that have various types of governmental laws and regulations relating to the discharge of oil or hazardous substances and the protection of the environment. Pursuant to these laws and regulations, we could be held liable for remediation of some types of pollution, including the release of oil, hazardous substances and debris from production, refining or industrial facilities, and other assets we own or operate or that are owned or operated by our customers or our subcontractors.
OCSLA
The Outer Continental Shelf Lands Act, as amended (“OCSLA”), provides the federalU.S. government with broad discretion in regulating the production of offshore resources of oil and natural gas, including authority to impose safety and 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 of lease conditions or regulations issued pursuant to OCSLA can result in substantial civil and criminal penalties, as well as potential court injunctions that could curtail operations and cancellation ofcancel leases. Because our operations rely on offshore oil and gas exploration and production, if the government were to exercise its authority under OCSLA to restrict the availability of offshore oil and gas leases, such action could have a material adverse effect on our financial condition and results of operations. In addition, since August 2012, the agency has implemented policy guidelines (IPD No. 12-07) under which BSEE will issue incidents of non-compliance directly to contractors for serious violations of BSEE regulations. However, on December 18, 2017, the U.S. Court of Appeals for the Fifth Circuit dismissed the U.S. government’s appeal regarding a BSEE Notification of an INC civil penalty issued against an oilfield contractor. This development brings closure to the long-standing question of whether BSEE has authority to enforce civil and criminal penalties against offshore contractors.
MARPOL
The United States is one of approximately 170 member countries Party to the International Maritime Organization (“IMO”), an agency of the United Nations which is responsible for developing measures to improve the safety and security of international shipping and to prevent marine pollution from ships. The IMO has negotiated the International Convention for the Prevention of Pollution from Ships (“MARPOL”). MARPOL imposes environmental standards on the shipping industry, to which we are subject. These standards relate to oil spills, management of garbage, the handling and disposal of noxious liquids, harmful substances in packaged forms, sewage and air emissions.
Greenhouse Gases and Vessel Engine Emissions
Greenhouse gases and marine engine emissions are an area of increasing regulatory action. We may be subject to a variety of regulations from multiple regulatory bodies that are designed to reduce greenhouse gases or other particulate emissions, including restrictions on the types of fuels used on our vessels, restrictions on the types of engines, carbon neutralization or offset measures and/or requirements to collect and report data on emissions and the costs attendant to each of these efforts.
Annex VI of MARPOL, which addresses air emissions, including emissions of sulfur and nitrous oxide requires the use of low sulfur fuels worldwide in both auxiliary and main propulsion diesel engines on vessels. Vessels worldwide are currently required to use fuel with a sulfur content no greater than 3.5%, which the IMO decided in October 2016 to reduce to 0.5% beginning in January 2020.
In the U.S., the EPA regulates the standards for emissions from vessel engines, both on its own and as a participant in the IMO. Beginning in 2010, the IMO designated the waters off North American as an Emission Control Area, meaning that vessels operating in the United States 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. In addition, U.S. states can (and in the case of California, have) issue rules regulating emissions from vessels operating off their coasts. In 2016, the California Air Resources Board notified the industry that their vessel fuel regulations would not sunset due to the implementation by the IMO of the emissions regulations in the North American Emission Control Area, but would continue in effect (Marine Notice 2016-1).
In addition, foreign nations and state actors may also impose emissions restrictions. The EU has issued regulations (EU Regulation 2015/757) that 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. At present the regulation is for monitoring and reporting only, but it is anticipated that in the future the EU may move from requiring reporting of emissions to regulations aimed at reducing them.
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 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. SuchCosts or liabilities related to environmental liabilitycompliance could substantially reducehave a material adverse effect on our net incomefinancial 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 condition,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 (limited coverage considering the underlying cost).economics.
Our current insurance program is valid until June 30, 2019.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.limits as well as OPA insurance for our offshore oil and gas properties with $35 million of coverage as required by BOEM. Our self-insured retention on our medical and health benefits program for employees is $300,000 per participant.
We 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, which we believe are covered by insurance.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, 2017, we had approximately 1,600 employees. Of our total employees, we had approximately 380 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, 2017, and2020, 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 general public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. We are an electronic filer, and 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:
BOEM: The Bureau of Ocean Energy Management (“BOEM”)(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.
BSEE: The Bureau of Safety and Environmental Enforcement (“BSEE”)(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. 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 generallylargely depend on the prevailing view of future oil and gas prices, which areis influenced by numerous factors, including:
•worldwide economic activity;activity and general economic and business 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, Chinagas;
•political and India;
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 in the market 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 for existingduring and at the expiration of the term of our contracts, and when existing contracts expire, 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 the currentan 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, 2017,2020, the BP contract, the Petrobras contracts and the contract for the HP I represented approximately 87%69% of our total backlog. Any cancellation, termination or breach of thesethose contracts would have a larger impact on our operating results and our financial condition than of our shorter term contracts. In addition, the BP contract and the Petrobras contracts dueexpire in 2021 and the contract for the HP I expires in 2023. Our ability to the value at risk. The cancellationextend, renew or termination of, or unwillingness to perform,replace these contracts when they expire or obtain new contracts as alternatives, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers. Given the historically cyclical nature of the oil and gas market, we may not be able to extend, renew or replace the contracts or we may be required to extend, renew or replace expiring contracts or obtain new contracts at rates that are below our existing contract rates, or that have other terms that are less favorable to us than our existing contracts. Failure to extend, renew or replace expiring contracts or secure new contracts at comparable rates and with favorable terms could have a material adverse effect on our financial position, results of operations and cash flows.
Our current backlog for our services may not be ultimately realized for various reasons, and our contracts may be terminated early.
As of December 31, 2017,2020, backlog for our services supported by written agreements or contracts totaled $1.6 billion,$407 million, of which $503$301 million is expected to be performed in 2018.2021. 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.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 could leadcase a customer tomay repudiate or seek to repudiate, cancel or renegotiate the contract. Our inability or the inability of our customers to perform under our or their contractual obligations, and/or theThe repudiation, 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 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 (which fines may be deducted by Petrobras from our monthly payments), and that ultimately Petrobras has the right to terminate should assessed penalties reach a certain amount. 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.
TimeOur customers and other counterparties may be unable to perform their obligations.
Continued industry uncertainty and domestic and global economic conditions, including the financial condition of our customers, lenders, insurers and other financial institutions generally, could jeopardize the ability of such parties to perform their obligations to us, including obligations to pay amounts owed to us. In the event one or more of our customers is adversely affected by the ongoing COVID-19 pandemic or otherwise 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 variety of conditions and factors could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts. In particular, our robotics business unit tends to do business with smaller customers that may not be capitalized to the same extent as larger operators and/or that may be more exposed to financial loss in an uncertain economic environment. In addition, we may offer favorable payment or other contractual terms to customers in order to secure contracts. These circumstances may lead to more frequent collection issues. Our financial results and liquidity could be adversely affected and we could incur losses.
Our forward-looking statements assume that our customers, lenders, insurers and other financial institutions will be able to fulfill their obligations under our various contracts, credit agreements and insurance policies. The inability of our customers and other counterparties to perform under these agreements may materially adversely affect our business, financial position, results of operations and cash flows.
We may own assets with ongoing costs that cannot be recouped if the assets are not under contract, and time chartering 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 the Petrobras contracts.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, depending on available opportunities and market conditions, vessels and other assets may be constructed 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 shipyard scope for the Q7000, our newbuild semi-submersible well intervention vessel, is complete and currently equipment is being manufactured and/or installed for the completion of the vessel. From time to time, we construct or make capital improvements to other pieces of equipment (such as the 15K IRS that we jointly constructed with OneSubsea). In addition, weWe 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 resulting from numerous factors, including:project.
shortages of equipment, materials or skilled labor;
unscheduled delays in the delivery of ordered materials and equipment;
unanticipated increases in the cost of equipment, labor and raw materials, particularly steel;
weather interferences;
difficulties in obtaining necessary permits or in meeting permit conditions;
design and engineering problems;
political, social and economic instability, war and civil disturbances;
delays in customs clearance of critical parts or equipment;
financial or other difficulties or failures at shipyards and suppliers;
disputes with shipyards and suppliers; and
work stoppages and other labor disputes.
The estimatedActual capital expenditures for vessel and equipment construction, upgrade, modification, refurbishment and dry dock projects 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.
A sustained period of unfavorable industry conditionsall, which could jeopardize our customers’ and other counterparties’ ability to perform their obligations.
Continued uncertain industry conditions could jeopardize the ability of certain of our counterparties, including our customers, insurers and financial institutions, to perform their obligations. Although we assess the creditworthiness of our counterparties, a prolonged period of difficult industry conditions could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts. In particular, our robotics business unit tends to do business with smaller customers that may not be capitalized to the same extent as larger operators. In addition, we may offer extended payment 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.
Because we 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.
Although we continue to seek to reduce the levelbusiness, financial position, results of our capitaloperations and other expenses and have raised capital by means of several equity 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.cash flows.
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, 2017, we had $495.6 million of consolidated indebtedness outstanding. The level of indebtedness may claims. Any such failure could have ana material 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 because a portion of our current and potential future borrowings are 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; and
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 limit 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 any refinancing of our maturing debt. Also, we may incur increased costs and less favorable terms associated with any additional financing 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. In addition, 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.
Our forward-looking statements assume that our lenders, insurers and other financial institutions will be able to fulfill their obligations under our various credit agreements, insurance policies and contracts. If any of our significant financial institutions were unable to perform under these agreements, and if we were unable to find suitable replacements at a reasonable cost, ourcompetitive position, financial position, results of operations liquidity and cash flows could be adversely impacted.flows.
A further decline in the offshore energy services market could result in additional impairment charges.
In December 2016, we recorded a goodwill impairment charge of $45.1 million related to our robotics reporting unit. In December 2015, we recorded asset impairment charges of $205.2 million related to our previously owned Helix 534 vessel, $133.4 million related to our HP I vessel and $6.3 million related to certain capitalized vessel project costs. We also recognized a goodwill impairment charge of $16.4 million related to our U.K. well intervention reporting unit as well as losses totaling $124.3 million primarily reflecting our share of impairment charges that Deepwater Gateway and Independence Hub recorded in December 2015. Prolonged periods of low utilization and day rates could result in the recognition of additional 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. We may also record additional impairment losses in the future.
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 condition.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 are now requiringrequire broad exclusions for losses due to war risk and terrorist acts, and limitations for wind storm damages.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 oil and gas operations involve a high degree of operational, contractual and financial risk, particularly risk of personal injury, damage, loss of equipment and environmental incidents.
In January 2019 we began owning oil and gas properties as part of our strategy to secure utilization for our vessels 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 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 thesetheir indemnification obligations.
Enhanced regulations for deepwater offshore drilling may reduceOur operations outside of the need for our services.U.S. subject us to additional risks.
Exploration and development activities andOur operations outside of the production and sale of oil and natural gasU.S. are subject to extensive federal, state, localrisks 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 regulations. To conduct deepwater drillingoperations.
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. Gulfaffecting foreign trade, taxation and other commercial activity may adversely affect our international operations.
Financial and Liquidity Risks
Our indebtedness and the terms of Mexico,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 operator isadverse 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 existingour covenants 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. Operators also are requiredother 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 Safetypossible acceleration of our repayment of outstanding debt and Environmental Management System regulations (SEMS) within the deadlines specifiedexercise of certain remedies by our lenders, including foreclosure against our collateral. These conditions and events may limit our access to the regulations,credit markets if we need to replace our existing debt, which could lead to increased costs and ensureless 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 contractors have SEMS compliant safetycapital and environmental policiesoperating expenditure programs, which could result in a decrease in demand for our assets and procedures. Additionally, each operator must demonstrate that it has containment resources that are available promptlya 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 a deepwater blowout, regardless of the company operations, fulfill their commitments and/or operator involved. It is expected that the BOEMfund future operations and the BSEE will continue to issue further regulations regarding deepwater offshore drilling. Our business, a significant portionobligations, each of which iscould adversely affect our operations. Continued lower levels of economic activity and weakness in the Gulffinancial 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 Mexico, provides development services to newly drilled wells,low utilization and therefore relies heavily on the industry’s drilling of new oil and gas wells. If the issuance of permits is significantly delayed, or if other oil and gas operations are delayed or reduced due to increased costs of complying with regulations, demandlow rates for our services could result in the Gulfrecognition of Mexico may also decline. Moreover, ifimpairment charges for our assets areif future cash flow estimates, based on information available to us at the time, indicate that their carrying value may not redeployed to other locations where we can provide our services at a profitable rate, our business, financial condition, results of operations and cash flows would be materially adversely affected.recoverable.
We cannot predict with any certainty
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 substance or effectrevenue and local expenses is incurred in local currencies and we are at risk of any new or additional regulationschanges in the United States orexchange 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 areas aroundcountries’ currencies. Those assets, liabilities, revenues and expenses are translated into U.S. dollars at the world. Ifapplicable exchange rates to prepare our consolidated financial statements. Therefore, changes in exchange rates between the United States orU.S. dollar and those other countries wherecurrencies affect the value of those items as reflected in our customers operate enact stricter restrictions on offshore drilling or further regulate offshore drillingconsolidated financial statements, even if their value remains unchanged in their original currency.
Legal 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 condition, results of operations and cash flows could be materially adversely affected.Regulatory Compliance Risks
Government regulations may affect our business operations.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 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 underand (ii) establish rules regarding incidental vessel movements related to offshore lifting operations. The 2019 CBP Rulings constitute a significant step towards establishing a predictable regime of regulation for offshore operations. We are aware, however, that certain organizations are seeking to overturn the Jones Act. While2019 CBP withdrew this proposal in May 2017,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. The United States recentlyIn 2017 the U.S. enacted significant tax reform, and certain provisions of the new law may ultimately adversely affect us. Certain members of the EU are undergoing significant changes to their tax systems, which may have an adverse effect on us. In addition, risks of substantial costs and liabilities related to environmental compliance issues are inherent in our operations. Our operations are subject to extensive federal, state, local and 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 Gulf of Mexico, an operator is required to comply with existing and newly developed regulations and enhanced safety standards. Before drilling may commence, BSEE conducts many inspections of deepwater drilling operations for compliance with its regulations. Operators also are required to comply with Safety and Environmental Management System (“SEMS”) regulations within the deadlines specified by the regulations, and confirm that their contractors have SEMS-compliant safety and environmental policies and procedures in place. Additionally, each operator must demonstrate that it has containment resources that are available promptly in the event of a loss of well control. It is expected that government authorities, including BOEM and BSEE, will continue to issue further regulations regarding deepwater offshore drilling. Our business, a significant portion of which is in the Gulf of Mexico, provides development services to newly drilled wells, and therefore relies heavily on the industry’s drilling of new oil and gas wells. If the issuance of drilling or other permits is significantly delayed, or if other oil and gas operations are delayed or reduced due to increased costs of complying with regulations, demand for our services may also decline. Moreover, if our assets are not redeployed such that we can provide our services at profitable rates, our business, financial condition, results of operations and cash flows would be materially adversely affected.
We cannot predict with any certainty the substance or effect of any new or additional regulations in the U.S. or in other areas around the world. If the U.S. or other countries where our customers operate enact stricter restrictions on offshore drilling or further regulate offshore drilling, and this results in decreased demand for or profitability of our services, our business, financial position, results of operations and cash flows could be materially adversely affected.
Failure to comply with anti-bribery laws could have a material adverse impact on our business.
The U.S. Foreign Corrupt Practices Act (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 governmental 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, in the relevant foreign jurisdictions, including prohibition of our participating in or curtailment of business operations in thosecertain 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 also 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, unplanned capital expenditures, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, theft or misappropriation of funds, violation of privacy or other laws, and exposure to litigation. Any such breach could have a material adverse effect on our business, reputation, financial position, results of operations and cash flows and financial results.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, 48the ROAM, 44 ROVs, fivefour trenchers and two ROVDrills.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(6)
| Bahamas | | 4/2015 | | 358 | | — | | DP3 |
Siem Helix1(5)
| Bahamas | | 6/2016 | | 521 | | — | | DP3 |
Siem Helix2(5)
| Bahamas | | 2/2017 | | 521 | | — | | DP3 |
6 IRSs and 3 SILs | — | | Various | | — | | — | | — |
Robotics — | | | | | | | | | |
48 ROVs, 5 Trenchers and 2 ROVDrills (3), (7)
| — | | Various | | — | | — | | — |
Grand Canyon(5)
| Panama | | 10/2012 | | 419 | | — | | DP3 |
Grand Canyon II(5)
| Panama | | 4/2015 | | 419 | | — | | DP3 |
Grand Canyon III(5)
| Panama | | 5/2017 | | 419 | | — | | DP3 |
| |
(1)Helix Producer I(3) | 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 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.Bahamas | | 4/2009 | | 528 | | DP2 |
| Well Intervention — | | | | | | | |
(2)Q4000(4) | RepresentsU.S. | | 4/2002 | | 312 | | DP3 |
Seawell (3) | U.K. | | 7/2002 | | 368 | | DP2 |
Well Enhancer (3) | U.K. | | 10/2009 | | 432 | | DP2 |
Q5000(5) | Bahamas | | 4/2015 | | 358 | | DP3 |
Siem Helix1(6) | Bahamas | | 6/2016 | | 521 | | DP3 |
Siem Helix2(6) | Bahamas | | 2/2017 | | 521 | | DP3 |
| Q7000 | Bahamas | | 1/2020 | | 320 | | DP3 |
6 IRSs, 3 SILs and 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.ROAM (7) | — | | Various | | — | | — |
| Robotics — | | | | | | | |
44 ROVs, 4 Trenchers and 1 ROVDrill (3), (8) | Serves as security for our Credit Agreement described in Note 6.— |
| Various | | — | | — |
(4)Grand Canyon II(6) | Subject to a vessel mortgage securing our MARAD Debt described in Note 6.Norway |
| 4/2015 | | 419 | | DP3 |
(5)Grand Canyon III(6) | Chartered vessel.Norway | | 5/2017 | | 419 | | DP3 |
| |
(6) | Serves as security for our Nordea Q5000 Loan described in Note 6. |
| |
(7) | Average age of our fleet of ROVs, trenchers and ROVDrills is approximately 8.1 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 underin accordance with the rules of the applicable class society. In addition to complying with these requirements, we have our own vesselasset maintenance programprograms that we believe permitspermit 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 that serves as a regional hub 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, 2017 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 two 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)
|
Houston, Texas | | Canyon Offshore, Inc.
Warehouse and Storage Facility
| | 3.7 acres
(Building: 22,000 square feet) (subject to one year remaining under a sub-lease agreement)
|
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, including 7,000 square feet subject to one year remaining under a sub-lease agreement)
|
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
| | 3,632 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 | | 6366 | | President, Chief Executive Officer and Director |
| Erik Staffeldt | | 4649 | | SeniorExecutive Vice President and Chief Financial Officer |
| Scott A. Sparks | | 4347 | | Executive Vice President and Chief Operating Officer |
Alisa B. JohnsonKenneth E. Neikirk | | 6045 | | ExecutiveSenior Vice President, General Counsel and Corporate Secretary |
Geoffrey C. Wagner | | 39 | | Executive Vice President and Chief Commercial Officer |
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 was appointed Senior is Executive Vice President and Chief Financial Officer of Helix in June 2017.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, and Vice President — Finance and Accounting from July 2015 to June 2017.2017, and Senior Vice President and Chief Financial Officer from June 2017 until February 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 2225 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 2730 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 27 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.
Geoffrey C. Wagner is Executive Vice President and Chief Commercial Officer. Mr. Wagner joined Helix in January 2018. Prior to joining Helix, he worked in a consulting capacity with Blackhill Partners from September to December 2017. Prior to that time, he served in various capacities for Atwood Oceanics, Inc., an offshore drilling contractor, as Vice President, Strategic Planning from August 2016 until August 2017, Vice President, Technical Services and Supply Chain from August 2015 until August 2016, Vice President, Marketing and Business Development from October 2012 until August 2015, and Director, Marketing and Business Development from March 2010 until October 2012. He served from January 2005 to March 2010 in management positions of increasing responsibility with Transocean, prior to which he was employed by SeaRiver Maritime, Inc., an ExxonMobil company, that owns and operates vessels providing maritime transportation of petroleum and chemical products. Mr. Wagner holds an MBA from the Jones Graduate School of Business at Rice University and an undergraduate degree in Marine Engineering and Nautical Science from the United States Merchant Marine Academy at Kings Point, New York.
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.” The following table sets forth, for the periods indicated, the high and low sale prices per share of our common stock:
|
| | | | | | | |
| | Common Stock Prices |
| | High | | Low |
| 2016 | | | |
| First Quarter | $ | 6.09 |
| | $ | 2.60 |
|
| Second Quarter | $ | 9.07 |
| | $ | 4.87 |
|
| Third Quarter | $ | 8.69 |
| | $ | 6.48 |
|
| Fourth Quarter | $ | 11.87 |
| | $ | 8.05 |
|
| | | | |
| 2017 | | | |
| First Quarter | $ | 9.82 |
| | $ | 6.87 |
|
| Second Quarter | $ | 8.11 |
| | $ | 4.82 |
|
| Third Quarter | $ | 7.78 |
| | $ | 5.07 |
|
| Fourth Quarter | $ | 8.09 |
| | $ | 6.20 |
|
| | | | |
| 2018 | | | |
First Quarter (1) | $ | 8.70 |
| | $ | 6.27 |
|
| |
(1) | Through February 20, 2018
|
On February 20, 2018,19, 2021, the closing sale price of our common stock on the NYSE was $6.45$4.95 per share. As of February 20, 2018,19, 2021, there were 302287 registered shareholders and approximately 13,70093,300 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, 20122015 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: Diamond Offshore Drilling,ChampionX Corporation (formerly known as Apergy Corporation), Archrock, Inc., ForumBaker Hughes Company, Core Laboratories N.V., DMC Global Inc., Dril-Quip, Inc., Bristow Group Inc. (formerly known as Era Group Inc.), Exterran Corporation, Geospace Technologies Corporation, Halliburton Company, KLX Energy Technologies,Services Holdings, Inc., Frank’s International N.V., GulfMark Offshore, Inc., Hornbeck Offshore Services, Inc.,Matrix Service Company, McDermott International, Inc., Noble EnergyNOV Inc. (formerly known as National Oilwell Varco, Inc.), Newpark Resources, Inc., Oceaneering International, Inc., Oil States International, Inc., Rowan CompaniesProPetro Holding Corp., RPC, Inc., Schlumberger Limited, SEACOR Holdings Inc., TechnipFMC plc, 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, 20172020 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, 20122015 in our common stock at the closing price on that date price and on December 31, 20122015 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 — (63.5)(20.2)%; the Peer Group — (79.2)(50.3)%; the OSX — (32.1)(68.9)%; and S&P 500 — 108.1%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, |
| | 2012 | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 |
| Helix | $ | 100.0 |
| | $ | 112.3 |
| | $ | 105.1 |
| | $ | 25.5 |
| | $ | 42.7 |
| | $ | 36.5 |
| Helix | $ | 100.0 | | | $ | 167.7 | | | $ | 143.3 | | | $ | 102.9 | | | $ | 183.1 | | | $ | 79.8 | |
| Peer Group Index | $ | 100.0 |
| | $ | 121.2 |
| | $ | 68.7 |
| | $ | 33.3 |
| | $ | 28.9 |
| | $ | 20.8 |
| Peer Group Index | $ | 100.0 | | | $ | 132.5 | | | $ | 111.4 | | | $ | 66.8 | | | $ | 75.1 | | | $ | 49.7 | |
| Oil Service Index | $ | 100.0 |
| | $ | 127.7 |
| | $ | 95.8 |
| | $ | 71.6 |
| | $ | 83.5 |
| | $ | 67.9 |
| Oil Service Index | $ | 100.0 | | | $ | 101.0 | | | $ | 98.5 | | | $ | 54.0 | | | $ | 53.7 | | | $ | 31.1 | |
| S&P 500 | $ | 100.0 |
| | $ | 132.4 |
| | $ | 150.5 |
| | $ | 152.6 |
| | $ | 170.8 |
| | $ | 208.1 |
| 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, 2017 | | — |
| | $ | — |
| | — |
| | 3,116,351 |
|
| November 1 to November 30, 2017 | | — |
| | — |
| | — |
| | 3,116,351 |
|
| December 1 to December 31, 2017 | | 98,452 |
| | 7.40 |
| | — |
| | 3,234,091 |
|
| | | 98,452 |
| | $ | 7.40 |
| | — |
| | |
| |
(1) | Includes shares forfeited by certain members of our Board of Directors in satisfaction of withholding taxes 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 11), increases the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 9. |
| |
(3) | In January 2018, we issued approximately 0.5 million shares of restricted stock to our executive officers 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, 20172020 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. In February 2013, we sold
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 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 former domestic oil and gas subsidiary, Energy Resource Technology GOM, Inc. (“ERT”)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.
(2)Amount in 2020 included a $9.2 million gain on extinguishment of long-term debt (Note 8), anda $7.6 million net tax benefit as a result of the assetsU.S. Coronavirus Aid, Relief, and liabilitiesEconomic 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”).
(3)This is a non-GAAP financial measure. See “Non-GAAP Financial Measures” below for an explanation of the definition and use of such measure as well as a reconciliation of these amounts to each year’s respective reported net income or loss.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| December 31, |
| 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 the salenet working capital and excluded from long-term debt. Long-term debt is also net of ERTunamortized debt discounts and the historical operating results of our former Oil and Gas segment are presented as discontinued operations in this Annual Report.
|
| | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (in thousands, except per share amounts) |
| Statement of Operations Data: | | | | | | | | | |
| Net revenues | $ | 581,383 |
| | $ | 487,582 |
| | $ | 695,802 |
| | $ | 1,107,156 |
| | $ | 876,561 |
|
Gross profit (loss) (1) | 62,166 |
| | 46,516 |
| | (233,774 | ) | | 344,036 |
| | 260,685 |
|
Income (loss) from operations (2) | (1,130 | ) | | (63,235 | ) | | (307,360 | ) | | 261,756 |
| | 179,034 |
|
Net income (loss) from continuing operations (3) | 30,052 |
| | (81,445 | ) | | (376,980 | ) | | 195,550 |
| | 111,976 |
|
| Income from discontinued operations, net of tax | — |
| | — |
| | — |
| | — |
| | 1,073 |
|
| Net income (loss), including noncontrolling interests | 30,052 |
| | (81,445 | ) | | (376,980 | ) | | 195,550 |
| | 113,049 |
|
| Net income applicable to noncontrolling interests | — |
| | — |
| | — |
| | (503 | ) | | (3,127 | ) |
| Net income (loss) applicable to common shareholders | 30,052 |
| | (81,445 | ) | | (376,980 | ) | | 195,047 |
| | 109,922 |
|
Adjusted EBITDA from continuing operations (4) | 107,216 |
| | 89,544 |
| | 172,736 |
| | 378,010 |
| | 268,311 |
|
| Basic earnings (loss) per share of common stock: | | | | | | | | | |
| Continuing operations | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
| | $ | 1.03 |
|
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | 0.01 |
|
| Net income (loss) per common share | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
| | $ | 1.04 |
|
| Diluted earnings (loss) per share of common stock: | | | | | | | | | |
| Continuing operations | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
| | $ | 1.03 |
|
| Discontinued operations | — |
| | — |
| | — |
| | — |
| | 0.01 |
|
| Net income (loss) per common share | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) | | $ | 1.85 |
| | $ | 1.04 |
|
| Weighted average common shares outstanding: | | | | | | | | | |
| Basic | 145,295 |
| | 111,612 |
| | 105,416 |
| | 105,029 |
| | 105,032 |
|
| Diluted | 145,300 |
| | 111,612 |
| | 105,416 |
| | 105,045 |
| | 105,184 |
|
| |
(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 (Note 4).
|
| |
(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 (Note 5). 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 (Note 17).
|
| |
(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) from continuing operations. |
|
| | | | | | | | | | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | (in thousands) |
| Balance Sheet Data: | | | | | | | | | |
| Working capital | $ | 186,004 |
| | $ | 336,387 |
| | $ | 473,123 |
| | $ | 468,660 |
| | $ | 553,427 |
|
| Total assets | 2,362,837 |
| | 2,246,941 |
| | 2,399,959 |
| | 2,690,179 |
| | 2,531,934 |
|
| Total debt | 495,627 |
| | 625,967 |
| | 749,335 |
| | 540,853 |
| | 553,806 |
|
| Total controlling interest shareholders’ equity | 1,567,393 |
| | 1,281,814 |
| | 1,278,963 |
| | 1,653,474 |
| | 1,499,051 |
|
| Noncontrolling interests | — |
| | — |
| | — |
| | — |
| | 25,059 |
|
| Total shareholders’ equity | 1,567,393 |
| | 1,281,814 |
| | 1,278,963 |
| | 1,653,474 |
| | 1,524,110 |
|
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 U.S. GAAP. Users of this financial information should consider the types of events and transactions that are excluded from these non-GAAP measures.
We measure our operating performance based on EBITDA aand free cash flow. EBITDA and free cash flow are non-GAAP financial measuremeasures that isare commonly used but isare not a recognized accounting termterms under U.S. GAAP. We use EBITDA and free cash flow to monitor and facilitate the 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 measuremeasures of EBITDA providesand 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 from continuing operations as net income (loss) from continuing operations 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 early extinguishment of long-term debt is considered equivalent to additional interest expense and thus is added back to net income (loss) from continuing operations.
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 from continuing operations, when applicable, we exclude the noncontrolling interests related to the adjustment components of EBITDA. Our measure of Adjusted EBITDA also excludes the gain or loss on disposition of assets from continuing operations. In addition, we include realized losses from foreign currency exchange contracts not designated as hedging instruments, which are excluded from EBITDA from continuing operations as a component of net other income or expense.
Other companies may calculate their measures of EBITDA, and Adjusted EBITDA and free cash flow differently from the way we do, which may limit their usefulness as comparative measures. BecauseEBITDA, Adjusted EBITDA and Adjusted EBITDA are not financial measures calculated in accordance with U.S. GAAP, theyfree cash flow should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income, cash flows from operating activities, or other income or cash flow data prepared in accordance with U.S. 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) from continuing operations to EBITDA from continuing operations and Adjusted EBITDA from continuing operations is as follows: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 | |
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, |
| | 2017 | | 2016 | | 2015 | | 2014 | | 2013 |
| | | | | | | | | | |
| Net income (loss) from continuing operations | $ | 30,052 |
| | $ | (81,445 | ) | | $ | (376,980 | ) | | $ | 195,550 |
| | $ | 111,976 |
|
| Adjustments: | | | | | | | | | |
| Income tax provision (benefit) | (50,424 | ) | | (12,470 | ) | | (101,190 | ) | | 66,971 |
| | 31,612 |
|
| Net interest expense | 18,778 |
| | 31,239 |
| | 26,914 |
| | 17,859 |
| | 32,898 |
|
| Loss on early extinguishment of long-term debt | 397 |
| | 3,540 |
| | — |
| | — |
| | 12,100 |
|
Other (income) expense, net (1) | 1,434 |
| | (3,510 | ) | | 24,310 |
| | (814 | ) | | (6 | ) |
| Depreciation and amortization | 108,745 |
| | 114,187 |
| | 120,401 |
| | 109,345 |
| | 98,535 |
|
Asset impairments (2) | — |
| | — |
| | 345,010 |
| | — |
| | — |
|
Goodwill impairments (3) | — |
| | 45,107 |
| | 16,399 |
| | — |
| | — |
|
Losses on equity investments (4) | 1,800 |
| | 1,674 |
| | 122,765 |
| | — |
| | — |
|
| EBITDA from continuing operations | 110,782 |
| | 98,322 |
| | 177,629 |
| | 388,911 |
| | 287,115 |
|
| Adjustments: | | | | | | | | | |
| Noncontrolling interests | — |
| | — |
| | — |
| | (661 | ) | | (4,077 | ) |
| (Gain) loss on disposition of assets, net | 39 |
| | (1,290 | ) | | (92 | ) | | (10,240 | ) | | (14,727 | ) |
| Realized losses from foreign currency exchange contracts not designated as hedging instruments | (3,605 | ) | | (7,488 | ) | | (4,801 | ) | | — |
| | — |
|
| Adjusted EBITDA from continuing operations | $ | 107,216 |
| | $ | 89,544 |
| | $ | 172,736 |
| | $ | 378,010 |
| | $ | 268,311 |
|
| |
(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 (Note 17).
|
| |
(2) | Amount in 2015 reflects asset impairment charges for the Helix 534, the HP I and certain capitalized vessel project costs (Note 4).
|
| |
(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 (Note 5).
|
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 make strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions.offshore wind farm projects and cable burial operations. Our well intervention fleet expanded followingincludes seven purpose-built well intervention vessels, six IRSs, three SILs and the deliveryROAM. 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 facilitate our ROV and trenching operations. Our well intervention and robotics operations are geographically dispersed throughout the world. Our Production Facilities segment includes the HP I, the HFRS and our ownership of the Siem Helix2 chartered vessel in February 2017oil and is expected to further expand following the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018 or 2019. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel that went into service for us in May 2017, 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. 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 is expected to leverage the parties’ capabilities to provide a unique, fully integrated offering to clients, combining marine support with well access and control technologies. In April 2015, we and OneSubsea agreed to jointly develop and ordered a 15K IRS for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At December 31, 2017, our total investment in the 15K IRS was $14.9 million inclusive of capitalized interest. The 15K IRS was completed and placed in service in January 2018. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest). At December 31, 2017, our total investment in the ROAM was $3.6 million. The ROAM is expected to be available to customers in the first half of 2018.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, Chinagas;
•political and India;
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.
OilCrude oil prices declined significantly in 2014 and have been volatile since then, most recently experiencing a precipitous decline through April 2020 due to the ongoing COVID-19 pandemic as well as the price war among OPEC+ nations during the 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 2020 and their recovery remains uncertain. The decline in oil prices and the volatility and uncertainty in prices have gradually risen above $60 per barrel, fueled by OPEC-led production cuts and increased demand for commodities as global economic conditions continue to improve. We have started to see an uptick incaused oil and gas explorationoperators to drastically reduce spending (on both operational activities and production activities as evidencedcapital projects), which has decreased the demand and rates for services provided by an increase in the global rig count. However, prolonged oversupply, partially attributable to increased shale oil production, is expected to constrain oil prices at least in the near term. The resulting weak industry environment may continue to curtail investments in offshore exploration and production as well as other offshore operational activities. Increased competition for limited 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. In addition, 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.
The recently enacted U.S. Tax Cutsongoing 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 Jobs Act (the “2017 Tax Act”)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 introduce uncertainty in termsimpacted, 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 spending byacross 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 companies.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.
ManyDespite this current period of market weakness and volatility, over the longer term we expect 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 over the longer term,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 coping with 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.
Demand for our services in the renewable energy market is affected by various factors, including the pace of consumer shift towards renewable energy sources, global electricity demand, technological advancements that increase the production and/or reduce the cost of renewable energy, expansion of offshore renewable energy projects to deeper water, and government subsidies for renewable energy projects.
Business Activity Summary
We have enhancedbeen focused on enhancing our financial position and strengthenedstrengthening our balance sheet with proceeds from the salethrough various means including securities offerings (the last of certain non-core business assets, which together with net proceeds from our equity offeringsoccurred in 2016 and early 2017 as well as liquidity under our Revolving Credit Facility,August 2020), which has allowed us to strategically focus on our core well intervention and robotics businesses. Our non-core business asset dispositions since 2009 primarily included
In January 2020, the sale of individualQ7000, a newbuild semi-submersible well intervention vessel built to U.K. North Sea standards, commenced operations.
During 2020, the COVID-19 pandemic and related governmental shut-downs significantly affected oil and gas propertiesprices, which negatively affected customer demand for our services. Consequently, we warm-stacked the Seawell and former reservoir consulting businessthe 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 the pandemic, including significant measures to protect personnel working in 2009, the saleoffshore environment. The vast majority of our stockholdingsonshore personnel are working remotely during the pandemic.
We have continued to expand our services and offerings into the offshore renewable energy sector. During 2020, we completed a site clearance project in Cal Dive International, Inc.the North Sea as well as performed services for renewable energy customers in 2009, the sale of ERT in 2013,Asia and the dispositionU.S., including the first wind farm installed in U.S. federal waters.
Backlog
We provide services and methodologies that we believe are critical to maximizing production economics. Our services cover the lifecycle of an offshore oil or gas field. 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 provide services primarily in deepwater in the Gulf of Mexico, Brazil, North Sea, Asia Pacific and West Africa regions. As of December 31, 2020, our consolidated backlog that is supported by written agreements or contracts totaled $407 million, of which $301 million is expected to be performed in 2021. The substantial majority of our subsea construction business, includingbacklog is associated with our Well Intervention segment. As of December 31, 2020, our well intervention backlog was $226 million, all of which is expected to be performed in 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 sale in 2013 of the CaesarSiem Helix1 and Express pipelaySiem Helix2 chartered vessels, and our fixed fee agreement for the sale in 2014HP I represent approximately 69% of the spoolbase facility located in Ingleside, Texas.
Our business activities in 2017 included the following:
The agreement providing access to the HFRS was amended effective February 1, 2017 to extend the termour total backlog. As of the agreement by one year to MarchDecember 31, 2019, the total backlog associated with our operations was $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 to reducein 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 retainer fee;amount of those fees can be substantially less than the rates we would have generated had we performed the contract.
We returned the Skandi Constructor to its owner in March 2017 upon the expiration36
The Siem Helix2 vessel was delivered to us and the charter term began in February 2017;
In April 2017, the Siem Helix1 vessel commenced operations for Petrobras offshore Brazil;
In May 2017, we took delivery of the Grand Canyon III chartered vessel; and
The Siem Helix2 vessel commenced operations for Petrobras in December 2017.
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.
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. We operate primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and in 2017 expanded our operations into Brazil with the commencement of operations of the Siem Helix1 and Siem Helix2 vessels for Petrobras. In addition to servicing the oil and gas market, our Robotics operations are contracted for the development of renewable energy projects (wind farms). As of December 31, 2017, our consolidated backlog that is supported by written agreements or contracts totaled $1.6 billion, of which $503 million is expected to be performed in 2018. The substantial majority of our backlog is associated with our Well Intervention business segment. As of December 31, 2017, our well intervention backlog was $1.2 billion, including $388 million expected to be performed in 2018. 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 87% of our total backlog. At December 31, 2016, the total backlog associated with our operations was $1.9 billion. Backlog contracts are cancelable sometimes without penalty. In addition, 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. Accordingly, backlog is not necessarily a reliable indicator of total annual revenues for our services as contracts may be added, renegotiated, deferred, canceled and in many cases modified while in progress, and reduced rates, fines and penalties may be imposed by our customers.
Comparison of Years Ended December 31, 20172020 and 20162019
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% | | | | |
(1)Represents the number of vessels or robotics assets as of the end of the period, including spot vessels and those under long-term charter, and excluding acquired vessels prior to their in-service dates and vessels or assets disposed of and/or taken out of service.
(2)Represents the average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of 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, | | Increase/ |
| | 2017 | | 2016 | | (Decrease) |
| Net revenues — | | | | | |
| Well Intervention | $ | 406,341 |
| | $ | 294,000 |
| | $ | 112,341 |
|
| Robotics | 152,755 |
| | 160,580 |
| | (7,825 | ) |
| Production Facilities | 64,352 |
| | 72,358 |
| | (8,006 | ) |
| Intercompany elimination | (42,065 | ) | | (39,356 | ) | | (2,709 | ) |
| | $ | 581,383 |
| | $ | 487,582 |
| | $ | 93,801 |
|
| | | | | | |
| Gross profit — | | | | | |
| Well Intervention | $ | 66,515 |
| | $ | 26,879 |
| | $ | 39,636 |
|
| Robotics | (31,986 | ) | | (12,466 | ) | | (19,520 | ) |
| Production Facilities | 28,568 |
| | 34,335 |
| | (5,767 | ) |
| Corporate and other | (1,815 | ) | | (1,860 | ) | | 45 |
|
| Intercompany elimination | 884 |
| | (372 | ) | | 1,256 |
|
| | $ | 62,166 |
| | $ | 46,516 |
| | $ | 15,650 |
|
| | | | | | |
| 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 number of vessels or robotics assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. |
| |
(2) | Represents average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period. |
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/ |
| | 2017 | | 2016 | | (Decrease) | | 2020 | | 2019 | | (Decrease) |
| | | | | | | | | | | | |
| Well Intervention | $ | 11,489 |
| | $ | 8,442 |
| | $ | 3,047 |
| Well Intervention | $ | 15,039 | | | $ | 43,484 | | | $ | (28,445) | |
| Robotics | 30,576 |
| | 30,914 |
| | (338 | ) | Robotics | 26,976 | | | 30,789 | | | (3,813) | |
| | $ | 42,065 |
| | $ | 39,356 |
| | $ | 2,709 |
| |
| | | $ | 42,015 | | | $ | 74,273 | | | $ | (32,258) | |
Net Revenues. Our totalconsolidated net revenues increaseddecreased by 19%2% in 20172020 as compared to 2016. Increased2019, reflecting lower revenues for 2017 reflectedfrom our Well Intervention and Production Facilities segments, offset in part by higher revenues in our Robotics segment and lower intercompany eliminations.
Our Well Intervention segment,revenues decreased by 9% in 2020 as compared to 2019, primarily reflecting lower vessel utilization in the North Sea and Gulf of Mexico, lower IRS rental utilization and lower foreign currency rates in Brazil. The decrease in revenues was offset in part by revenue decreasesrevenues on the Q7000, which commenced operations offshore West Africa in January 2020. Vessel utilization in 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 Roboticswarm-stacking the Seawell and the Q7000 during the year, as well as scheduled regulatory certification inspections in the Gulf of Mexico during the first quarter 2020. Additionally, our Well Intervention revenues in the Gulf of Mexico in 2019 included $27.5 million associated with intercompany P&A work for our Production Facilities segments.
segment and no such P&A work was performed in 2020. Our Well Intervention revenues increased by 38% in 2017 as compared2019 also included approximately $3.9 million of contractual adjustments related to 2016 primarily reflecting higher revenues generated from all of the well intervention vessels except for the Q4000. In Brazil, the Siem Helix1 achieved 96% utilization since it commenced operations for Petrobrasincreases in mid-April 2017. The Siem Helix2 commenced operations for Petrobraswithholding taxes in mid-December 2017 with 53% utilization. In the North Sea, the Well Enhancer was 74% utilized during 2017 while the vessel was 64% utilized during 2016. The Seawell was 78% utilized during 2017 whereas it was 42% utilized during 2016. In the Gulf of Mexico, the Q5000 was 91% utilized during 2017 as compared to being 65% utilized during 2016. The Q4000 was 75% utilized during 2017 as compared to being 98% utilized during 2016. The vessel was out of service for 49 days during the first half of 2017 undergoing its scheduled regulatory dry dock. Additionally in 2016, we recognized $15.6 million associated with cancellation of work originally scheduled to be performed by the Q4000 in late 2016.Brazil.
Our Robotics revenues decreasedincreased by 5%4% in 20172020 as compared to 2016. The decrease2019, primarily reflectedreflecting improvements in chartered vessel utilization, offset in part by lower utilization of our robotics assetsROV, trencher and performing work at reduced rates. Some of our ROV units have been affected by other industry participants laying up vessels or canceling workROVDrill 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 a result of the oilcompared to 1,086 vessel days and gas industry downturn.729 trenching days (including 245 days on third-party vessels) in 2019.
Our Production Facilities revenues decreased by 11%5% in 20172020 as compared to 2016, which reflected2019, primarily reflecting reduced retainer fees from the amended HFRS agreement which was effective February 1, 2017, no revenue fromrevenues associated with 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 Ia reduction in oil and gas production revenues.
The decrease in intercompany eliminations was primarily attributable to a fixed fee agreement$27.5 million elimination of revenues that commenced June 1, 2016.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.Profit (Loss). Our 2017consolidated 2020 gross profit increaseddecreased by 34%$57.9 million, or 42%, as compared to 2016. 2019, primarily reflecting lower gross profit in our Well Intervention and Production Facilities segments, offset in part by higher gross profit in our Robotics segment.
The gross profit related to our Well Intervention segment increaseddecreased by 147%$63.3 million, or 61%, in 20172020 as compared to 2016,2019, 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 cost reductions relating to certain vessels, including the termination of the Grand Canyon charter in our North Sea region.November2019 and 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 associated with our Robotics segment decreased 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%7% in 20172020 as compared to 20162019, primarily reflecting revenue decreases for the HFRS and the HP I.in revenues.
Goodwill Impairment. The $45.1$6.7 million impairment charge in 20162020 reflects the write-offimpairment of the entire goodwill balance associated with our robotics reporting unit.acquisition of a controlling interest in Subsea Technologies Group Limited (“STL”) (Note 7).
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 in 2020 included a $2.7 million provision for credit losses (Note 19). Excluding this charge, our selling, general and administrative expenses decreased by $2.7$11.4 million in 20172020 as compared to 2016. The decrease was2019, primarily attributable toreflecting a $4.7 million decrease associated with the provision for uncertain collection of a portion of our then existing tradereduction in employee compensation costs 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 11).other cost-saving measures during 2020.
Equity in LossesEarnings of Investments.Investment. Equity in lossesearnings of investmentsinvestment was $2.4$0.2 million in 2017 as compared to $2.22020 and $1.4 million in 20162019, 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 $18.8$28.5 million in 20172020 as compared to $31.2$8.3 million in 20162019, primarily reflecting increases in interest income andlower capitalized interest in 2020 and a decreasehigher yields associated with the 2026 Notes issued in August 2020. Capitalized interest expense. Interest income totaled $2.6decreased to $1.2 million for 2017in 2020 with the completion of the Q7000 in January 2020 as compared to $2.1$20.2 million for 2016. Interestin 2019 (Note 8).
Gain on Extinguishment of Long-term Debt. The $9.2 million gain on extinguishment of long-term debt used to finance capital projects is capitalizedin 2020 was associated with our repurchase of a portion of the 2022 and thus reduces overall interest expense. Capitalized interest totaled $16.92023 Notes (Note 8).
Other Income, Net. Net other income increased by $3.6 million for 2017in 2020 as compared to $11.8 million for 2016. The decrease in interest expense was2019, 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 Early 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 reflectreflecting 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 17). 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).
Comparison of Years Ended December 31, 2016 and 2015
The following table details various financial and operational highlights for the periods presented (dollars in thousands):
|
| | | | | | | | | | | |
| | Year Ended December 31, | | Increase/ |
| | 2016 | | 2015 | | (Decrease) |
| Net revenues — | | | | | |
| Well Intervention | $ | 294,000 |
| | $ | 373,301 |
| | $ | (79,301 | ) |
| Robotics | 160,580 |
| | 301,026 |
| | (140,446 | ) |
| Production Facilities | 72,358 |
| | 75,948 |
| | (3,590 | ) |
| Intercompany elimination | (39,356 | ) | | (54,473 | ) | | 15,117 |
|
| | $ | 487,582 |
| | $ | 695,802 |
| | $ | (208,220 | ) |
| | | | | | |
| Gross profit — | | | | | |
Well Intervention (1) | $ | 26,879 |
| | $ | (165,049 | ) | | $ | 191,928 |
|
| Robotics | (12,466 | ) | | 41,446 |
| | (53,912 | ) |
Production Facilities (1) | 34,335 |
| | (106,112 | ) | | 140,447 |
|
| Corporate and other | (1,860 | ) | | (3,961 | ) | | 2,101 |
|
| Intercompany elimination | (372 | ) | | (98 | ) | | (274 | ) |
| | $ | 46,516 |
| | $ | (233,774 | ) | | $ | 280,290 |
|
| | | | | | |
| Gross margin — | | | | | |
| Well Intervention | 9 | % | | (44 | )% | | |
| Robotics | (8 | )% | | 14 | % | | |
| Production Facilities | 47 | % | | (140 | )% | | |
| Total company | 10 | % | | (34 | )% | | |
| | | | | | |
Number of vessels or robotics assets (2) / Utilization (3) | | | | | |
| Well Intervention vessels | 5/54% |
| | 6/58% |
| | |
| Robotics assets | 59/48% |
| | 59/57% |
| | |
| Chartered robotics vessels | 3/64% |
| | 4/78% |
| | |
| |
(1) | 2015 amounts included asset impairment charges (see discussions below). |
| |
(2) | Represents number of vessels or robotics assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. The Helix 534 was excluded from the numbers for the entire year of 2016 as it had been stacked and out of service prior to its sale in December 2016. The Seawell was excluded from the numbers for the first eight months of 2015 as it was out of service undergoing major capital upgrades.
|
| |
(3) | Represents average utilization rate, which is calculated by dividing the total number of days the vessels or robotics assets generated revenues by the total number of calendar days in the applicable period. |
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/ |
| | 2016 | | 2015 | | (Decrease) |
| | | | | | |
| Well Intervention | $ | 8,442 |
| | $ | 22,855 |
| | $ | (14,413 | ) |
| Robotics | 30,914 |
| | 31,618 |
| | (704 | ) |
| | $ | 39,356 |
| | $ | 54,473 |
| | $ | (15,117 | ) |
Net Revenues. Our total net revenues decreased by 30% in 2016 as compared to 2015. In general, decreased revenues for 2016 reflect both reduced opportunities for work and the acceptance of work at reduced rates for some of our assets in light of the continuation of the industry-wide downturn as a result of the substantial decline in oil prices since late 2014.
Our Well Intervention revenues decreased by 21% in 2016 as compared to 2015 primarily reflecting significantly lower revenues in our North Sea region due to lack of work and our acceptance of work at reduced rates, offset in part by revenue increases in our U.S. Gulf of Mexico region. In the North Sea, the Well Enhancer was 64% utilized during 2016 while the vessel was 89% utilized during 2015. The Skandi Constructor was 4% utilized during 2016 as compared to being 56% utilized during 2015. The Seawell was re-activated in June 2016 and was 42% utilized during 2016 as compared to being out of service undergoing its life extension capital upgrades during the first eight months of 2015 and being stacked after those life extension activities were completed in September 2015. In the Gulf of Mexico, the Q4000 was 98% utilized during 2016 as compared to 71% utilized during 2015. Idle time for the Q4000 included 64 days in the second quarter of 2015 for its scheduled dry dock, and some downtime attributable to IRS mechanical issues in January 2015. In addition, we recognized $15.6 million associated with a work scope cancellation under a “take or pay” contract for 42 days of work originally scheduled to be performed by the Q4000 in late 2016. The Q5000, which was delivered to us in April 2015 and went on contracted rates under our five-year contract with BP in May 2016, was 65% utilized in 2016 due to operational downtime. The Helix 534 had been stacked and out of service prior to its sale in December 2016 while the vessel was 31% utilized during 2015.
Our Robotics revenues decreased by 47% in 2016 as compared to 2015. The decrease primarily reflects the reduction and lower utilization of our available Robotics assets, including our chartered vessels, 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. Utilization of our chartered ROV support vessels decreased primarily reflecting reduction in work opportunities as a result of further market deterioration in the offshore energy industry.
Our Production Facilities revenues decreased by 5% in 2016 as compared to 2015, which reflects lower revenues from the new fixed fee agreement with the field operator for production from the Phoenix field starting June 1, 2016 (Note 1) as well as a slight decrease in our variable throughput fee for the first five months of 2016 as compared to the same period in 2015.
Gross Profit (Loss). Excluding the impact of impairment charges in 2015 related to the Helix 534 and HP I vessels and certain capitalized vessel project costs (Note 4), our 2016 gross profit decreased by 58% as compared to 2015. Excluding the $211.6 million impairment charges in 2015 related to the Helix 534 and certain capitalized vessel project costs, the gross profit related to our Well Intervention segment decreased by 42% in 2016 as compared to 2015 primarily reflecting significantly lower revenues from most of our well intervention vessels in our North Sea region during 2016 due to lack of available projects and acceptance of work at reduced rates as a result of the ongoing industry downturn. The decrease in our Well Intervention gross profit was partially offset by higher gross profit achieved in our Gulf of Mexico region as a result of the Q5000 being on hire under the BP contract since May 2016 as well as the $15.6 million in revenues associated with a take-or-pay contract.
The gross profit associated with our Robotics segment decreased by 130% in 2016 as compared to 2015 primarily reflecting decreased utilization for our Robotics assets, including our chartered vessels, and performing work with lower profit margins.
Excluding the $133.4 million impairment charge in 2015 for the HP I, the gross profit related to our Production Facilities segment increased by 26% in 2016 as compared to 2015. The increase primarily reflects lower repair and maintenance costs and a decrease in depreciation expense related to the HP I as a result of the vessel’s impairment charge recorded in December 2015.
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 (Note 2). The $16.4 million impairment charge in 2015 reflects the write-off of the entire goodwill balance associated with our U.K. well intervention 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 (Note 4).
Selling, General and Administrative Expenses. Our selling, general and administrative expenses increased by $8.7 million in 2016 as compared to 2015. The increase was primarily attributable to payroll related costs associated with our variable performance-based incentive compensation programs (Note 11), increased overhead costs associated with the Petrobras contract and a $2.5 million increase associated with the provision for uncertain collection of a portion of our then existing trade and note receivables, and was partially offset by overhead cost saving measures including headcount reductions.
Equity in Losses of Investments. Equity in losses of investments was $2.2 million in 2016 as compared to $124.3 million in 2015. The losses in 2015 primarily reflect our share of impairment charges that Deepwater Gateway and Independence Hub recorded in December 2015 (Note 5).
Net Interest Expense. Our net interest expense totaled $31.2 million in 2016 as compared to $26.9 million in 2015 primarily reflecting an increase in interest expense, which was partially offset by a slight increase in capitalized interest. The increase in interest expense was primarily attributable to nearly four months of additional interest on the Nordea Q5000 Loan, which was funded in April 2015, as well as increases in interest rates on the Term Loan and the Nordea Q5000 Loan. Interest expense for 2016 also included a $2.5 million charge to accelerate the amortization of debt issuance costs in proportion to the reduced commitment under our Revolving Credit Facility in February 2016 (Note 6). Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $11.8 million for 2016 as compared to $11.0 million for 2015.
Loss on Early Extinguishment of Long-term Debt. 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 (Note 6).
Other Income (Expense), Net. We reported other income, net, of $3.5 million for 2016 as compared to other expense, net, of $24.3 million in 2015. Net other income for 2016in 2020 and 2019 included net gains totaling $1.3 million associated with our foreign currency exchange contracts, which primarily related to the portions of the contracts that were not designated as cash flow hedges (Note 17). Net other expense for 2015 primarily reflects losses associated with our foreign currency exchange contracts, including $18.0 million upon de-designation of our Grand Canyon II and Grand Canyon III hedges and $5.1 million related to our hedge ineffectiveness. Also included in other income (expense), net, were foreign currency transaction gains (losses) of $0.2$4.6 million and $(1.2)$1.5 million, respectively, in the comparable year-over-year periods. These amounts primarily reflect foreign exchange fluctuations in our non-U.S. dollar currencies. 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.respectively.
OtherRoyalty Income – Oil and Gas. OurOther. Royalty income and other income - oil and gas decreased by $2.0$0.6 million in 20162020 as compared to 2015.2019. The decrease was primarily attributable to the reduction in our overriding royalty income, which was significantly affected by the decline inlower average oil prices and lower volumes.
Income Tax Benefit. Income taxes reflected a benefit of $12.5 millionproduction volumes in 20162020 as compared to $101.22019.
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 2019. Our income tax benefit in 2015. This variance is primarily due2020 included discrete benefits related to the decreaserestructuring of certain of our foreign subsidiaries and our carrying back certain net operating losses to prior periods with higher income tax rates under tax law changes associated with the CARES Act (Note 9). Excluding these discrete items, we had an income tax benefit of $2.8 million and an effective tax rate of (200.5)% in pre-tax loss for 2016.2020 as compared to an income tax provision of $7.9 million and an effective tax rate of 12.0% in 2019. The negative effective tax rate was 13.3% for 2016 as compared to 21.2% for 2015. The decrease was primarily attributable to the non-deductible goodwill impairment charge, partially offset byour near break-even pre-tax income for 2020 as well as the earnings mix between our higher and lower tax rate jurisdictions.
Comparison of Years Ended December 31, 2019 and 2018
Various financial and operational highlights for the years ended December 31, 2019 and 2018 were previously presented in our 2019 Annual Report on Form 10-K.
LIQUIDITY AND CAPITAL RESOURCES
Overview
The following table presents certain information useful in the analysis of our financial condition and liquidity (in thousands):
| | | | | | | | | | | |
| December 31, |
| 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, |
| | 2017 | | 2016 |
| | | | |
| Net working capital | $ | 186,004 |
| | $ | 336,387 |
|
Long-term debt (1) | 385,766 |
| | 558,396 |
|
Liquidity (2) | 348,207 |
| | 375,504 |
|
| |
(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. It 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, 2017 included cash and cash equivalents of $266.6 million (including $100 million of minimum cash balance required by our Credit Agreement) and $81.6 million of available borrowing capacity under our Revolving Credit Facility (Note 6). Our liquidity at December 31, 2016 included cash and cash equivalents of $356.6 million and $18.9 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, |
| | 2017 | | 2016 |
| | | | |
| Former term loan (was scheduled to mature June 2018) | $ | — |
| | $ | 190,867 |
|
| Nordea Q5000 Loan (matures April 2020) | 158,930 |
| | 193,879 |
|
| Term Loan (matures June 2020) | 95,842 |
| | — |
|
| MARAD Debt (matures February 2027) | 72,487 |
| | 78,221 |
|
2022 Notes (mature May 2022) (1) | 108,829 |
| | 105,697 |
|
2032 Notes (mature March 2032) (2) | 59,539 |
| | 57,303 |
|
| Total debt | $ | 495,627 |
| | $ | 625,967 |
|
| |
(1) | The 2022 Notes will increase to their face amount through accretion of the debt discount through May 1, 2022. |
| |
(2) | The 2032 Notes will increase to their face amount through accretion of the debt discount through March 15, 2018, which is the first date on which the holders may require us to repurchase the notes. |
The following table provides summary data from our consolidated statements of cash flows (in thousands):
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| Cash provided by (used in): | | | | | | Cash provided by (used in): | | | | | |
| Operating activities | $ | 51,638 |
| | $ | 38,714 |
| | $ | 110,805 |
| Operating activities | $ | 98,800 | | | $ | 169,669 | | | $ | 196,744 | |
| Investing activities | (221,127 | ) | | (147,110 | ) | | (295,719 | ) | Investing activities | (19,281) | | | (142,385) | | | (136,014) | |
| Financing activities | 77,482 |
| | (25,524 | ) | | 204,625 |
| 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 cannot reduce costs or replace those revenues. Despite these challenges, we remain even more 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 the 2032 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 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, 2017 and 2016, we were in compliance with all of the covenants in our long-term debt agreements.2023 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, 2017,2020, our available borrowing capacity under ourthe Revolving Credit Facility, based on the applicable leverage ratio covenant, was restricted to $81.6$160.2 million, net of $3.0$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. If we failcontrol, and our failure to comply with these covenants and other restrictions that failure 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, including covenants and collateral.
The 2022 Notes and the 2032 Notes can be converted prior to their stated maturity upon certain triggering events specified in the applicable Indenture governing the notes. We can settle any conversion in cash or shares of our common stock. In March 2018, the holders of the remaining 2032 Notes may require us to repurchase those notes. Accordingly, the 2032 Notes are classified as current liabilities on our consolidated balance sheet at December 31, 2017. No conversion triggers were met during the years ended December 31, 2017 and 2016.default.
Operating Cash Flows
Total cash flows from operating activities increaseddecreased by $12.9$70.9 million in 20172020 as compared to 20162019, primarily reflecting changeslower operating income and larger increases in our working capital.capital as compared to 2019.
Total cash flows from operating activities decreased by $72.1$27.1 million in 20162019 as compared to 20152018, primarily reflecting decreases in income from operations and changes in our working capital. Our operating cash flowscapital during 2019 as well as higher regulatory certification costs for 2016our vessels and systems, which included the receiptcosts related to planned dry docks for three of $28.4 million in U.S. and foreign income tax refunds.our vessels.
Investing Activities
Capital expenditures consistrepresent cash paid principally offor 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 for the years ended December 31, 2017, 2016 and 2015 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, |
| | 2017 | | 2016 | | 2015 |
| Capital expenditures: | | | | | |
| Well Intervention | $ | (230,354 | ) | | $ | (185,892 | ) | | $ | (307,879 | ) |
| Robotics | (648 | ) | | (720 | ) | | (10,700 | ) |
| Production Facilities | — |
| | (74 | ) | | (1,867 | ) |
| Other | (125 | ) | | 199 |
| | 135 |
|
| Distributions from equity investments (Note 5) | — |
| | 1,200 |
| | 7,000 |
|
Proceeds from sale of equity investment (1) | — |
| | 25,000 |
| | — |
|
Proceeds from sale of assets (2) | 10,000 |
| | 13,177 |
| | 17,592 |
|
| Net cash used in investing activities | $ | (221,127 | ) | | $ | (147,110 | ) | | $ | (295,719 | ) |
| |
(1) | Amount in 2016 reflected cash received from the sale of our former ownership interest in Deepwater Gateway (Note 5) |
| |
(2) | Amounts in 2015 and 2017 primarily reflected cash received related to the sale in 2014 of our Ingleside spoolbase. Amount in 2016 primarily reflected cash received from the sale of our office and warehouse property located in Aberdeen, Scotland and the sale of the Helix 534 (Note 4).
|
CapitalOur capital expenditures associated with our business primarily have included payments associated with the construction and completion of our Q5000 and the Q7000 vessels (see below), paymentswhich commenced operations in connection with the Seawell life extension activities in 2015, the investment in the topsideJanuary 2020, as well intervention equipment for the Siem Helix1 and Siem Helix2 vessels chartered to perform our agreements with Petrobras (see below),as the investment in the 15K IRS and the ROAM, as well as capital spending on ROVs and trenchers for our robotics business.ROAM.
In March 2012, we entered into a contract with a shipyard in Singapore for the construction of the Q5000. Pursuant to the terms of this contract, payments were made as a fixed percentage of the contract price, together with any variations, on contractually scheduled dates. The Q5000 was delivered to us in the second quarter of 2015. The vessel commenced operations in the Gulf of Mexico under our five-year contract with BP and went on contracted rates in May 2016.
In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000 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, including the third amendment that was entered into in November2017, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% was paid in December2017, 20% is to be paid on December31, 2018, and 20% is to 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, 2017, our total investment in the Q7000 was $295.8 million, including $207.6 million of installment payments to the shipyard. Currently equipment is being manufactured and/or installed for the completion of the vessel. We plan to incur approximately $105 million related to the Q7000 in 2018.
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years with Petrobras’s options to extend. In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild 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. At December 31, 2017, our investment in the topside equipment for the two chartered vessels was $309.8 million.
Financing Activities
Cash flows from financing activities consist primarily of proceeds from debt and equity financing activitiestransactions and repayments of our long-term debt. TotalNet cash flowsoutflows from financing activities increased by $103.0of $52.6 million in 2017 as compared to 2016. We received approximately $2202020 primarily reflect the repayment of $46.4 million of scheduled maturities related to our indebtedness (Note 8) as well as the net proceedscash flow from our underwritten public equity offeringissuance 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 January 2017 (Note 8) and $100 million from our Term Loan borrowings in June 2017, while making early repayments2019 primarily reflect the repayment of approximately $180$42.6 million of term loan then outstanding underour indebtedness and $2.0 million in net cash outflows related to repayments and net refinancing, including fees, of the credit agreement prior to its June 2017 amendmentTerm Loan. Net cash outflows from financing activities of $46.2 million in 2018 primarily reflect the repayment of $166.4 million of our indebtedness using cash and restatement (Note 6). In 2016, we received $96.5 million ofthe net proceeds from the saleissuance in March 2018 of $125 million of the 2023 Notes.
In August 2020, we issued the 2026 Notes, which have a principal amount of $200 million and a conversion price of approximately $6.97 per share. We used the proceeds from the issuance 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 issuanceeffective conversion price of the 20222026 Notes while making early repaymentsto approximately $8.42 per share, and to fund the related debt issuance costs.
Free Cash Flow
Free cash flow increased to $79.5 million in aggregate principal amount2020 from $31.4 million in 2019. The increase was due to the decrease in capital expenditures with the completion of the 2032 Notes including approximately $122 million with proceeds fromQ7000, offset in part by the issuance of the 2022 Notes.reduction in operating cash flows.
TotalFree cash flows from financing activitiesflow decreased by $230.1to $31.4 million in 2016 as compared to 2015. In 2016, we received approximately $222 million2019 from debt and equity financing activities. Our $250 million Nordea Q5000 Loan was funded in April 2015 at the time the Q5000 vessel was delivered to us. Repayments of our long-term debt increased by $196.8$59.7 million in 2016 as compared2018. The decrease was primarily attributable to 2015 primarily reflecting an additional $17.9 millionthe decrease in repayment of the Nordea Q5000 Loan, an additional $40.2 million in repayment of term loan then outstanding, and the payments to repurchase the 2032 Notes.
Outlook
We anticipate that our capital expenditures and deferred dry dock costs for 2018 will approximate $135 million. We believe that our cash on hand, internally generatedoperating cash flows and availability under our Revolving Credit Facility will provide the capital necessary to continue funding our 2018 capital spending and to meet our debt obligations due in 2018. Our estimate of futurehigher capital expenditures may change based on various factors. We may seek to reducein 2019.
Free cash flow is a non-GAAP financial measure. See Item 6. Selected Financial Data of this Annual Report for the leveldefinition and calculation of our planned capital expenditures given a prolonged industry downturn.free cash flow.
Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 20172020 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 | $ | 97,500 |
| | $ | 7,500 |
| | $ | 90,000 |
| | $ | — |
| | $ | — |
|
| Nordea Q5000 Loan | 160,714 |
| | 35,714 |
| | 125,000 |
| | — |
| | — |
|
| MARAD debt | 77,000 |
| | 6,532 |
| | 14,058 |
| | 15,497 |
| | 40,913 |
|
2022 Notes (2) | 125,000 |
| | — |
| | — |
| | 125,000 |
| | — |
|
2032 Notes (3) | 60,115 |
| | 60,115 |
| | — |
| | — |
| | — |
|
Interest related to debt (4) | 71,858 |
| | 22,802 |
| | 32,922 |
| | 11,765 |
| | 4,369 |
|
Property and equipment (5) | 157,513 |
| | 88,313 |
| | 69,200 |
| | — |
| | — |
|
Operating leases (6) | 599,088 |
| | 128,018 |
| | 228,265 |
| | 181,526 |
| | 61,279 |
|
| Total cash obligations | $ | 1,348,788 |
| | $ | 348,994 |
| | $ | 559,445 |
| | $ | 333,788 |
| | $ | 106,561 |
|
| |
(1) | Excludes unsecured letters of credit outstanding at December 31, 2017 totaling $3.0 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 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 130% of the conversion price on that 30th trading day (i.e., $18.06 per share). At December 31, 2017, the conversion trigger was not met. See Note 6 for additional information. |
| |
(3) | Notes mature in 2032. The 2032 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 130% of the conversion price on that 30th trading day (i.e., $32.53 per share). At December 31, 2017, the conversion trigger was not met. The first date that the holders of these notes may require us to repurchase the notes is March 15, 2018. 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, 2017 for variable rate debt. |
| |
(5) | Primarily reflects costs associated with our Q7000 semi-submersible vessel currently under construction (Note 13).
|
| |
(6) | Operating leases include vessel charters and facility leases. At December 31, 2017, our vessel charter commitments totaled approximately $558 million, including the Grand Canyon III that went into service for us in May 2017, the Siem Helix1 that commenced operations for Petrobras in mid-April 2017, and the Siem Helix2 that commenced operations for Petrobras in mid-December 2017.
|
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.
Revenue Recognition
Revenues from our services are derived from contracts, which are both short-term and long-term in duration. Our services contracts generally contain either lump-sum provisions or provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts. We recognize revenue as it is earned at estimated collectible amounts. Further, we record revenues net of taxes collected from customers and remitted to governmental authorities.
The majority of our contracts contain provisions for specific time, material and equipment charges. Revenues generated from these contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month. Certain dayrate contracts with built-in rate changes require us to record revenues on a straight-line basis. We may receive revenues for mobilization of equipment and personnel under dayrate contracts. Revenues related to mobilization are deferred and recognized over the period in which contracted services are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, also are deferred and recognized using the same straight-line method. Our policy to amortize the revenues and costs related to mobilization on a straight-line basis over the estimated contract service period is consistent with the general pace of activity, level of services being provided and dayrates being earned over the contract period. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.
Revenues on significant lump sum contracts are generally recognized under the percentage-of-completion method. Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs. Changes in the expected cost of materials and labor,
productivity, scheduling and other factors affect the total estimated costs. Additionally, weather and other external factors outside of our control may affect the progress and estimated cost of a project’s completion, and therefore the timing of revenue recognition. We routinely review estimates related to our contracts and reflect revisions to profitability in earnings on a current basis. If a current estimate of total contract cost indicates an ultimate loss on a contract, we recognize the projected loss in full when it is first determined. We recognize additional contract revenue related to claims when the claim is probable and legally enforceable.
Property and Equipment
PropertyWe review our property and equipment is recorded at cost. Depreciation expense is derived primarily using the straight-line method over the estimated useful life of an asset.
Assets used in operations are evaluated for impairment indicators at least quarterly or whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable. We evaluate impairment indicators considering the nature of the asset or asset group, the future economic benefits of the asset or asset group, historical and estimated future profitability measures, and other external market conditions or factors that may be present. We often estimate future earnings and cash flows of our assets to corroborate our determination of whether impairment indicators exist. If impairment indicators suggest that the carrying amount of an asset may not be recoverable, we determine whether an impairment has occurred by estimating undiscounted cash flows of the asset and may exceedcomparing those cash flows to the asset’s carrying value. If the undiscounted cash flows are less than the asset’s carrying value (i.e., the asset is unrecoverable), impairment, if any, is recognized for the difference between the asset’s carrying value and its estimated fair value. Our marine vessels are assessed on a vessel by vessel basis, while our robotics assets are grouped and assessed by asset class. 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. If an
The determination of the appropriate asset groups at which to evaluate impairment, has occurred, we recognize a lossthe review of property and equipment for impairment indicators, the difference between the carrying amountprojection of future cash flows of property and equipment, and the estimated fair value of any property and equipment that may be deemed unrecoverable involve significant judgment and estimation by our management. Changes to those judgments and estimations could require us to recognize impairment charges in the asset.future.
Income Taxes
DeferredWe conduct business in numerous countries and earn income taxes are based on the differences between the 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.various jurisdictions. Income taxes have been provided based upon the tax laws and rates in those jurisdictions. The provision of our income taxes involves the countriesinterpretation of various laws and regulations, and changes in whichthose laws, our operations are conducted andand/or legal structure could impact our 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 deferredliabilities. Furthermore, our tax asset will not be realized.
As of December 31, 2017, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $48 million, all of which wasfilings are subject to the one-time transition tax on foreign earnings requiredregular audits and examination by the 2017 Tax Act enacted in December 2017 or has otherwise been previously taxed.local taxing authorities. 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. In addition, we expect future U.S. cash generation will be sufficient to meet future U.S. cash needs.
It is our policy to 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 Hedging Activitiesthe tax basis of assets and liabilities. The carrying value of deferred tax assets are based on our estimates, judgments and assumptions regarding future operating results and taxable income. Loss carryforwards and tax credits are assessed for realization, and a valuation allowance for deferred tax assets is recorded when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. If we subsequently determine that we will be able to realize deferred tax assets in the future in excess of our net recorded amount, the resulting adjustment would increase earnings for the period in which such determination was made. We will continue to assess the adequacy of a valuation allowance on a quarterly basis. Any changes to our estimated valuation allowance could be material to our consolidated financial position and results of operations.
Our risk management activities involveThe 2017 Tax Act requires the usetaxable repatriation of derivative financial instrumentsforeign earnings that had been reinvested in previous years. Subsequently, repatriation of foreign earnings will generally be free of U.S. federal tax but may be subject to hedgechanges in future tax legislation that may result in taxation. As of December 31, 2020, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the impactU.S. of market risk exposure relatedapproximately $62.2 million. We intend to variable interest rates and foreign currency exchange rates. To reduceindefinitely reinvest these earnings, as well as future earnings from our non-U.S. subsidiaries without operations in the impact of these risksU.S., to fund our international operations. We have not provided deferred income taxes on the accumulated earnings and increase the predictability of our cash flows, from time to timeprofits as we have entered into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative contracts are reflected on our balance sheet at fair value.consider them permanently reinvested. The fair value of our interest rate swaps is calculated as the discounted cash flowscomputation of the difference betweenpotential deferred tax liability associated with the rate fixed by the hedging instrumentamount of reinvested earnings and the LIBOR forward curve over the remaining term of the hedging instrument. The fair value of our foreign currency exchange contractsother basis differences 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 assumptions used could impact whether the fair value change in the hedged instrument is charged to earnings or accumulated other comprehensive income (loss) (a component of shareholders’ equity).not practicable.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2017,2020, 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, 2017, $258.22020, $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 $187.5 million of our Nordea Q5000 Loan. These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. 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 $1.8$0.9 million in interest expense for the year ended December 31, 2017.2020.
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 (i) currencies other than the U.S. dollar, which is our functional currency of the relevant Helix entity or (ii) the functional currency of our subsidiaries which mayis not be 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” (“Accumulated OCI”) in the shareholders’ equity section of our consolidated balance sheets. At December 31, 2017,2020, approximately 13%40% of our net assets were impacted by changes in foreign currencies in relation to the U.S. dollar. We recorded foreign currency translation unrealized gains (losses) of $16.3 million, $(35.9) million and $(12.8) million to Accumulated OCI forFor the years ended December 31, 2017, 20162020, 2019 and 2015, respectively.2018, we recorded foreign currency translation gains (losses) of $12.8 million, $5.4 million and $(7.2) million, respectively, to accumulated other comprehensive loss. Deferred taxes have not been provided on foreign currency translation adjustments since we consider our undistributed earnings (when applicable) of our non-U.S. subsidiaries without operations in the U.S. to be permanently reinvested.
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, 2017, 20162020, 2019 and 2015, these amounts resulted in2018, we recorded foreign currency transaction gains (losses) of $(2.2)$4.6 million, $0.2$1.5 million and $(1.2)$(4.3) 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 similar foreign currency exchange contracts to hedge our foreign currency exposure with respect to the Grand Canyon II and the Grand Canyon III charter payments denominated in Norwegian kroner through July 2019 and February 2020, respectively. In December 2015, we re-designated the hedging relationship between 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 ConsolidatedFinancial Statements
We have audited the accompanying consolidated balance sheets of Helix Energy Solutions Group, Inc. and subsidiaries (the “Company”)Company) as of December 31, 20172020 and 2016,2019, the related consolidated statements of operations, comprehensive income, (loss), shareholders’ equity, and cash flows for each of the years in the two-yearthree-year period ended December 31, 2017,2020, and the related notes (collectively, the “consolidatedconsolidated financial statements”)statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172020 and 2016,2019, and the results of its operations and its cash flows for each of the years in the two-yearthree-year period ended December 31, 2017,2020, 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”)(PCAOB), the Company’s internal control over financial reporting as of December 31, 2017,2020, 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 23, 201825, 2021 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
Emphasis of MatterChange in Accounting Principle
As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting method for deferred income taxes effectiveleases as of January 1, 20172019 due to the adoption of FASB ASU 2015-17, Balance Sheet Classification of Deferred Taxes.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 23, 201825, 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”)Company) internal control over financial reporting as of December31, 2017,2020, 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, 2017,2020, 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”)(PCAOB), the consolidated balance sheets of the Company as of December 31, 20172020 and 2016,2019, the related consolidated statements of operations, comprehensive income, (loss), shareholders’ equity, and cash flows for each of the years in the two-yearthree-year period ended December 31, 2017,2020, and the related notes (collectively, “thethe consolidated financial statements”)statements), and our report dated February 23, 201825, 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 23, 201825, 2021
Report
The Board of Directors and Shareholders of
Helix Energy Solutions Group, Inc. and subsidiaries
We have audited the consolidated statements of operations, comprehensive income (loss), shareholders' equity, and cash flows of Helix Energy Solutions Group, Inc. (the Company) for the year ended December 31, 2015 (collectively referred to as the “financial statements”). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audit. We did not audit the financial statements of Deepwater Gateway, L.L.C. (a limited liability company in which the Company has a 50% interest) and Independence Hub, LLC (a limited liability company in which the Company has a 20% interest) for the year ended December 31, 2015. In the consolidated financial statements, the Company’s equity in the net losses of Deepwater Gateway, L.L.C. and Independence Hub, LLC is stated at approximately $124 million for the year ended December 31, 2015. Those statements were audited by other auditors whose reports have been furnished to us, and our opinion, insofar as it relates to the amounts included for Deepwater Gateway, L.L.C. and Independence Hub, LLC, for the year ended December 31, 2015, is based solely on the reports of the other auditors.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audit and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated results of operations and cash flows of the Company for the year ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Houston, Texas
February 29, 2016
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Management Committee of
Deepwater Gateway, L.L.C.
Houston, Texas
We have audited the statements of operations, cash flows, and members’ equity of Deepwater Gateway, L.L.C. (the “Company”) for the year ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the results of operations and cash flows of Deepwater Gateway, L.L.C. for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 12, 2016
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Management Committee of
Independence Hub, LLC
Houston, Texas
We have audited the statements of operations, cash flows, and members’ equity of Independence Hub, LLC (the “Company”) for the year ended December 31, 2015. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.
The financial statements include considerations of the Members’ having guaranteed their commitment to the Company to provide the necessary level of financial support to enable the Company to pay its obligations as they become due.
In our opinion, such financial statements present fairly, in all material respects, the results of operations and cash flows of Independence Hub, LLC for the year ended December 31, 2015, in conformity with accounting principles generally accepted in the United States of America.
/s/ Deloitte & Touche LLP
Houston, Texas
February 12, 2016
HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)
| | | | December 31, | | December 31, |
| | 2017 | | 2016 | | 2020 | | 2019 |
| ASSETS | ASSETS | ASSETS |
| Current assets: | | | | Current assets: | |
| Cash and cash equivalents | $ | 266,592 |
| | $ | 356,647 |
| Cash and cash equivalents | $ | 291,320 | | | $ | 208,431 | |
| Accounts receivable: | | | | |
| Trade, net of allowance for uncollectible accounts of $2,752 and $1,778, respectively | 113,336 |
| | 101,825 |
| |
| Unbilled revenue and other | 29,947 |
| | 10,328 |
| |
| Current deferred tax assets | — |
| | 16,594 |
| |
| 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 | 41,768 |
| | 37,388 |
| Other current assets | 102,092 | | | 50,450 | |
| Total current assets | 451,643 |
| | 522,782 |
| Total current assets | 525,645 | | | 438,468 | |
| Property and equipment | 2,695,772 |
| | 2,450,890 |
| Property and equipment | 2,948,907 | | | 2,922,274 | |
| Less accumulated depreciation | (889,783 | ) | | (799,280 | ) | Less accumulated depreciation | (1,165,943) | | | (1,049,637) | |
| Property and equipment, net | 1,805,989 |
| | 1,651,610 |
| 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 | 105,205 |
| | 72,549 |
| Other assets, net | 40,013 | | | 84,508 | |
| Total assets | $ | 2,362,837 |
| | $ | 2,246,941 |
| 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 | $ | 81,299 |
| | $ | 60,210 |
| Accounts payable | $ | 50,022 | | | $ | 69,055 | |
| Accrued liabilities | 71,680 |
| | 58,614 |
| Accrued liabilities | 87,035 | | | 62,389 | |
| Income tax payable | 2,799 |
| | — |
| |
| | Current maturities of long-term debt | 109,861 |
| | 67,571 |
| 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 | 265,639 |
| | 186,395 |
| Total current liabilities | 279,307 | | | 284,960 | |
| Long-term debt | 385,766 |
| | 558,396 |
| Long-term debt | 258,912 | | | 306,122 | |
| Operating lease liabilities | | Operating lease liabilities | 101,009 | | | 151,827 | |
| Deferred tax liabilities | 103,349 |
| | 167,351 |
| Deferred tax liabilities | 110,821 | | | 112,132 | |
| Other non-current liabilities | 40,690 |
| | 52,985 |
| Other non-current liabilities | 3,878 | | | 38,644 | |
| Total liabilities | 795,444 |
| | 965,127 |
| 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, 147,740 and 120,630 shares issued, respectively | 1,284,274 |
| | 1,055,934 |
| |
| 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 | 352,906 |
| | 322,854 |
| Retained earnings | 464,524 | | | 445,370 | |
| Accumulated other comprehensive loss | (69,787 | ) | | (96,974 | ) | Accumulated other comprehensive loss | (51,620) | | | (64,740) | |
| Total shareholders’ equity | 1,567,393 |
| | 1,281,814 |
| Total shareholders’ equity | 1,740,496 | | | 1,699,591 | |
| Total liabilities and shareholders’ equity | $ | 2,362,837 |
| | $ | 2,246,941 |
| |
| 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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Net revenues | $ | 581,383 |
| | $ | 487,582 |
| | $ | 695,802 |
|
| | | | | | |
| Cost of sales: | | | | | |
| Cost of sales | 519,217 |
| | 441,066 |
| | 584,566 |
|
| Asset impairments | — |
| | — |
| | 345,010 |
|
| Total cost of sales | 519,217 |
| | 441,066 |
| | 929,576 |
|
| | | | | | |
| Gross profit (loss) | 62,166 |
| | 46,516 |
| | (233,774 | ) |
| | | | | | |
| Goodwill impairments | — |
| | (45,107 | ) | | (16,399 | ) |
| Gain (loss) on disposition of assets, net | (39 | ) | | 1,290 |
| | 92 |
|
| Selling, general and administrative expenses | (63,257 | ) | | (65,934 | ) | | (57,279 | ) |
| Loss from operations | (1,130 | ) | | (63,235 | ) | | (307,360 | ) |
| Equity in losses of investments | (2,368 | ) | | (2,166 | ) | | (124,345 | ) |
| Net interest expense | (18,778 | ) | | (31,239 | ) | | (26,914 | ) |
| Loss on early extinguishment of long-term debt | (397 | ) | | (3,540 | ) | | — |
|
| Other income (expense), net | (1,434 | ) | | 3,510 |
| | (24,310 | ) |
| Other income – oil and gas | 3,735 |
| | 2,755 |
| | 4,759 |
|
| Loss before income taxes | (20,372 | ) | | (93,915 | ) | | (478,170 | ) |
| Income tax benefit | (50,424 | ) | | (12,470 | ) | | (101,190 | ) |
| Net income (loss) | $ | 30,052 |
| | $ | (81,445 | ) | | $ | (376,980 | ) |
| | | | | | |
| Earnings (loss) per share of common stock: | | | | | |
| Basic | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) |
| Diluted | $ | 0.20 |
| | $ | (0.73 | ) | | $ | (3.58 | ) |
| | | | | | |
| Weighted average common shares outstanding: | | | | | |
| Basic | 145,295 |
| | 111,612 |
| | 105,416 |
|
| Diluted | 145,300 |
| | 111,612 |
| | 105,416 |
|
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Net revenues | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | |
| | | | | |
| | | | | |
| | | | | |
| | | | | |
| Cost of sales | 653,646 | | | 614,071 | | | 618,134 | |
| | | | | |
| Gross profit | 79,909 | | | 137,838 | | | 121,684 | |
| Gain on disposition of assets, net | 889 | | | 0 | | | 146 | |
| Goodwill impairment | (6,689) | | | 0 | | | 0 | |
| Selling, general and administrative expenses | (61,084) | | | (69,841) | | | (70,287) | |
| Income from operations | 13,025 | | | 67,997 | | | 51,543 | |
| Equity in earnings (losses) of investment | 216 | | | 1,439 | | | (3,918) | |
| Net interest expense | (28,531) | | | (8,333) | | | (13,751) | |
| Gain (loss) on extinguishment of long-term debt | 9,239 | | | (18) | | | (1,183) | |
| Other income (expense), net | 4,724 | | | 1,165 | | | (6,324) | |
| Royalty income and other | 2,710 | | | 3,306 | | | 4,631 | |
| Income before income taxes | 1,383 | | | 65,556 | | | 30,998 | |
| Income tax provision (benefit) | (18,701) | | | 7,859 | | | 2,400 | |
| Net income | 20,084 | | | 57,697 | | | 28,598 | |
| Net loss attributable to redeemable noncontrolling interests | (2,090) | | | (222) | | | 0 | |
| Net income attributable to common shareholders | $ | 22,174 | | | $ | 57,919 | | | $ | 28,598 | |
| | | | | |
| Earnings per share of common stock: | | | | | |
| Basic | $ | 0.13 | | | $ | 0.39 | | | $ | 0.19 | |
| Diluted | $ | 0.13 | | | $ | 0.38 | | | $ | 0.19 | |
| | | | | |
| Weighted average common shares outstanding: | | | | | |
| Basic | 148,993 | | | 147,536 | | | 146,702 | |
| 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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Net income (loss) | $ | 30,052 |
| | $ | (81,445 | ) | | $ | (376,980 | ) |
| Other comprehensive income (loss), net of tax: | | | | | |
| Unrealized gain (loss) on hedges arising during the period | 3,323 |
| | 2,366 |
| | (25,259 | ) |
| Reclassification adjustments for loss on hedges included in net income (loss) | 12,915 |
| | 12,851 |
| | 13,659 |
|
| Reclassification adjustments for loss from derivative instruments de-designated as cash flow hedges included in net loss | — |
| | — |
| | 18,014 |
|
| Income taxes on unrealized (gain) loss on hedges | (5,724 | ) | | (5,347 | ) | | (2,214 | ) |
| Unrealized gain on hedges, net of tax | 10,514 |
| | 9,870 |
| | 4,200 |
|
| Unrealized gain on note receivable arising during the period | 629 |
| | — |
| | — |
|
| Income taxes on unrealized gain on note receivable | (220 | ) | | — |
| | — |
|
| Unrealized gain on note receivable, net of tax | 409 |
| | — |
| | — |
|
| Foreign currency translation gain (loss) arising during the period | 16,264 |
| | (33,899 | ) | | (12,849 | ) |
| Reclassification adjustment for net translation gain realized upon liquidation | — |
| | (2,044 | ) | | — |
|
| Foreign currency translation gain (loss) | 16,264 |
| | (35,943 | ) | | (12,849 | ) |
| Other comprehensive income (loss), net of tax | 27,187 |
| | (26,073 | ) | | (8,649 | ) |
| Comprehensive income (loss) | $ | 57,239 |
| | $ | (107,518 | ) | | $ | (385,629 | ) |
| | | | | | | | | | | | | | | | | |
| 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 Income (Loss) | | Total Shareholders’ Equity |
| | Shares | | Amount | | | |
| Balance, December 31, 2014 | 105,586 |
| | $ | 934,447 |
| | $ | 781,279 |
| | $ | (62,252 | ) | | $ | 1,653,474 |
|
| Net loss | — |
| | — |
| | (376,980 | ) | | — |
| | (376,980 | ) |
| Foreign currency translation adjustments | — |
| | — |
| | — |
| | (12,849 | ) | | (12,849 | ) |
| Unrealized gain on hedges, net of tax | — |
| | — |
| | — |
| | 4,200 |
| | 4,200 |
|
| Activity in company stock plans, net and other | 703 |
| | 3,443 |
| | — |
| | — |
| | 3,443 |
|
| Share-based compensation | — |
| | 5,463 |
| | — |
| | — |
| | 5,463 |
|
| Cumulative share-based compensation in excess of fair value of modified liability awards | — |
| | 2,915 |
| | — |
| | — |
| | 2,915 |
|
| Excess tax from share-based compensation | — |
| | (703 | ) | | — |
| | — |
| | (703 | ) |
| 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 due 2022 | — |
| | 10,719 |
| | — |
| | — |
| | 10,719 |
|
| Re-acquisition of equity component of debt discount on Convertible Senior Notes due 2032 | — |
| | (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 due 2022 | — |
| | (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 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Common Stock | | Retained
Earnings | | Accumulated
Other
Comprehensive
Loss | | Total
Shareholders’
Equity | | Redeemable
Noncontrolling
Interests |
| Shares | | Amount | | | | |
| Balance, December 31, 2017 | 147,740 | | | $ | 1,284,274 | | | $ | 352,906 | | | $ | (69,787) | | | $ | 1,567,393 | | | $ | — | |
| Net income | — | | | — | | | 28,598 | | | — | | | 28,598 | | | — | |
| Reclassification of stranded tax effect to retained earnings | — | | | — | | | 1,530 | | | (1,530) | | | — | | | — | |
| Foreign currency translation adjustments | — | | | — | | | — | | | (7,166) | | | (7,166) | | | — | |
| Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 5,016 | | | 5,016 | | | — | |
| Unrealized loss on note receivable, net of tax | — | | | — | | | — | | | (497) | | | (497) | | | — | |
| Equity component of debt discount on convertible senior notes | — | | | 15,411 | | | — | | | — | | | 15,411 | | | — | |
| | | | | | | | | | | |
| Activity in company stock plans, net and other | 463 | | | (746) | | | — | | | — | | | (746) | | | — | |
| Share-based compensation | — | | | 9,770 | | | — | | | — | | | 9,770 | | | — | |
| Balance, December 31, 2018 | 148,203 | | | $ | 1,308,709 | | | $ | 383,034 | | | $ | (73,964) | | | $ | 1,617,779 | | | $ | — | |
| Net income | — | | | — | | | 57,919 | | | — | | | 57,919 | | | (222) | |
| Reclassification of deferred gain from sale leaseback transaction to retained earnings | — | | | — | | | 4,560 | | | — | | | 4,560 | | | — | |
| Foreign currency translation adjustments | — | | | — | | | — | | | 5,400 | | | 5,400 | | | 138 | |
| Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 3,824 | | | 3,824 | | | — | |
| Issuance of redeemable noncontrolling interests | — | | | — | | | — | | | — | | | — | | | 3,396 | |
| Accretion of redeemable noncontrolling interests | — | | | — | | | (143) | | | — | | | (143) | | | 143 | |
| Activity in company stock plans, net and other | 685 | | | (1,032) | | | — | | | — | | | (1,032) | | | — | |
| Share-based compensation | — | | | 11,284 | | | — | | | — | | | 11,284 | | | — | |
| Balance, December 31, 2019 | 148,888 | | | $ | 1,318,961 | | | $ | 445,370 | | | $ | (64,740) | | | $ | 1,699,591 | | | $ | 3,455 | |
| Net income | — | | | — | | | 22,174 | | | — | | | 22,174 | | | (2,090) | |
| Credit losses recognized in retained earnings upon adoption of ASU No. 2016-13 | — | | | — | | | (620) | | | — | | | (620) | | | — | |
| Foreign currency translation adjustments | — | | | — | | | — | | | 12,835 | | | 12,835 | | | 90 | |
| Unrealized gain on hedges, net of tax | — | | | — | | | — | | | 285 | | | 285 | | | — | |
| Accretion of redeemable noncontrolling interests | — | | | — | | | (2,400) | | | — | | | (2,400) | | | 2,400 | |
| Equity component of convertible senior notes | — | | | 33,336 | | | — | | | — | | | 33,336 | | | — | |
| Re-acquisition of equity component of convertible senior notes | — | | | (18,006) | | | — | | | — | | | (18,006) | | | — | |
| Capped call transactions | — | | | (10,625) | | | — | | | — | | | (10,625) | | | — | |
| Activity in company stock plans, net and other | 1,453 | | | (4,345) | | | — | | | — | | | (4,345) | | | — | |
| Share-based compensation | — | | | 8,271 | | | — | | | — | | | 8,271 | | | — | |
| Balance, December 31, 2020 | 150,341 | | | $ | 1,327,592 | | | $ | 464,524 | | | $ | (51,620) | | | $ | 1,740,496 | | | $ | 3,855 | |
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, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| Cash flows from operating activities: | | | | | | Cash flows from operating activities: | | | | | |
| Net income (loss) | $ | 30,052 |
| | $ | (81,445 | ) | | $ | (376,980 | ) | |
| 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 | 108,745 |
| | 114,187 |
| | 120,401 |
| Depreciation and amortization | 133,709 | | | 112,720 | | | 110,522 | |
| Non-cash impairment charges | — |
| | 45,107 |
| | 361,409 |
| |
| Amortization of debt discount | 4,688 |
| | 5,905 |
| | 5,957 |
| |
| Goodwill impairment | | Goodwill impairment | 6,689 | | | 0 | | | 0 | |
| Amortization of debt discounts | | Amortization of debt discounts | 6,964 | | | 6,261 | | | 5,735 | |
| Amortization of debt issuance costs | 6,154 |
| | 7,733 |
| | 5,664 |
| Amortization of debt issuance costs | 3,177 | | | 3,600 | | | 3,592 | |
| Share-based compensation | 10,877 |
| | 5,862 |
| | 6,543 |
| Share-based compensation | 8,568 | | | 11,469 | | | 9,925 | |
| Deferred income taxes | (54,585 | ) | | 14,849 |
| | (103,022 | ) | Deferred income taxes | (3,883) | | | 3,485 | | | (2,430) | |
| Equity in losses of investments | 2,368 |
| | 2,166 |
| | 124,345 |
| |
| (Gain) loss on disposition of assets, net | 39 |
| | (1,290 | ) | | (92 | ) | |
| Loss on early extinguishment of long-term debt | 397 |
| | 3,540 |
| | — |
| |
| Unrealized (gains) losses and ineffectiveness on derivative contracts, net | (4,423 | ) | | (8,800 | ) | | 18,281 |
| |
| 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 | (28,424 | ) | | (22,437 | ) | | 36,354 |
| 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 | (15,680 | ) | | (2,386 | ) | | 7,956 |
| Other current assets | (28,664) | | | 25,383 | | | (9,904) | |
| Income tax payable | 3,949 |
| | (4,571 | ) | | (7,464 | ) | |
| | Accounts payable and accrued liabilities | 33,381 |
| | (630 | ) | | (63,817 | ) | Accounts payable and accrued liabilities | 10,830 | | | (31,265) | | | (1,818) | |
| Other non-current, net | (45,900 | ) | | (39,076 | ) | | (24,730 | ) | |
| Other, net | | Other, net | (14,521) | | | (6,743) | | | 26,543 | |
| Net cash provided by operating activities | 51,638 |
| | 38,714 |
| | 110,805 |
| Net cash provided by operating activities | 98,800 | | | 169,669 | | | 196,744 | |
| | | | | | | | | | | | |
| Cash flows from investing activities: | |
| | |
| | |
| Cash flows from investing activities: | | | | | |
| Capital expenditures | (231,127 | ) | | (186,487 | ) | | (320,311 | ) | Capital expenditures | (20,244) | | | (140,854) | | | (137,083) | |
| Distributions from equity investments | — |
| | 1,200 |
| | 7,000 |
| |
| Proceeds from sale of equity investment | — |
| | 25,000 |
| | — |
| |
| STL acquisition, net | | STL acquisition, net | 0 | | | (4,081) | | | 0 | |
| Proceeds from sale of assets | 10,000 |
| | 13,177 |
| | 17,592 |
| Proceeds from sale of assets | 963 | | | 2,550 | | | 25 | |
| Other | | Other | 0 | | | 0 | | | 1,044 | |
| Net cash used in investing activities | (221,127 | ) | | (147,110 | ) | | (295,719 | ) | 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 due 2022 | — |
| | 125,000 |
| | — |
| |
| Repurchase of Convertible Senior Notes due 2032 | — |
| | (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 loan | (194,758 | ) | | (62,742 | ) | | (22,500 | ) | |
| Proceeds from Nordea Q5000 Loan | — |
| | — |
| | 250,000 |
| |
| Repayment of term loans | | Repayment of term loans | (3,500) | | | (35,442) | | | (63,807) | |
| Repayment of Nordea Q5000 Loan | (35,715 | ) | | (35,714 | ) | | (17,857 | ) | Repayment of Nordea Q5000 Loan | (35,714) | | | (35,714) | | | (35,714) | |
| Repayment of MARAD Debt | (6,222 | ) | | (5,926 | ) | | (5,644 | ) | Repayment of MARAD Debt | (7,200) | | | (6,858) | | | (6,532) | |
| Capped call transactions | | Capped call transactions | (10,625) | | | 0 | | | 0 | |
| Debt issuance costs | (3,717 | ) | | (4,655 | ) | | (1,737 | ) | 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 | (2,042 | ) | | (341 | ) | | (1,121 | ) | Payments related to tax withholding for share-based compensation | (5,264) | | | (1,680) | | | (1,407) | |
| Proceeds from issuance of ESPP shares | 432 |
| | 708 |
| | 3,484 |
| Proceeds from issuance of ESPP shares | 622 | | | 462 | | | 506 | |
| Net cash provided by (used in) financing activities | 77,482 |
| | (25,524 | ) | | 204,625 |
| |
| 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 | 1,952 |
| | (3,625 | ) | | (2,011 | ) | |
| Net increase (decrease) in cash and cash equivalents | (90,055 | ) | | (137,545 | ) | | 17,700 |
| |
| 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 | 356,647 |
| | 494,192 |
| | 476,492 |
| Balance, beginning of year | 262,561 | | | 279,459 | | | 266,592 | |
| Balance, end of year | $ | 266,592 |
| | $ | 356,647 |
| | $ | 494,192 |
| 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, and in 2017 expanded our operations into Brazil with the commencement of operations of the Siem Helix1 and Siem Helix2 vessels for Petróleo Brasileiro S.A. (“Petrobras”).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 12)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 Brazil.West Africa. Our well intervention vessels include the Q4000, the Q5000, the Q7000, the Seawell, the Well Intervention segment alsoEnhancer, and 2 chartered monohull vessels, the Siem Helix1 and the Siem Helix2. Our well intervention equipment includes intervention riser systems (“IRSs”), some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”). Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and two chartered newbuild monohull vessels, the Siem Helix1 and the Siem Helix2. We also haveRiserless Open-water Abandonment Module (“ROAM”), some of which we provide on a semi-submersible well intervention vessel under construction, the Q7000. 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.stand-alone basis.
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrillsa ROVDrill, which are designed to complement offshore construction and well intervention services and currently operates 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, including the Grand CanyonII and the Grand CanyonIII that went into service for us in May 2017. We also utilize, as well as spot vessels as needed. Our vessel charter for the Deep Cygnus was terminated on February 9, 2018, at which time we returned the vessel to its owner.
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 provides certain operators access toand our Q4000ownership of oil and HP I vessels in the eventgas properties. All of a well control incidentour current Production Facilities activities are located in the Gulf of Mexico. The HP I has been under contract to the Phoenix field operator since February 2013, currently under a fixed fee agreement through at least June 1, 2023. We are party to an agreement providing various operators with access to the HFRS for well control purposes, which agreement was amended effective February 1, 2017 to extend the term of the agreement by one year to March 31, 2019 and to reduce the retainer fee. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”).
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 former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and 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 (“U.S. GAAP”) and reported 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 (which were normal recurring adjustments) that we believe are necessary for a fair presentation of our consolidated financial statements, as applicable.statements.
Use of Estimates
The preparation of financial statements in conformity with U.S. 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 definitively not be collected (Note 15)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 linestraight-line basis over theits estimated useful life of each asset.life. The cost of improvements is capitalized whilewhereas the cost of repairs and maintenance is charged to expenseexpensed as incurred. For the years ended December 31, 2017, 2016 and 2015, repair and maintenance expense totaled $28.1 million, $25.5 million and $32.8 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 fair value.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 lessnot recoverable and is greater than its carrying amount,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 InvestmentsInvestment
We periodically reviewWith respect to our equity investmentsinvestment accounted for impairment. Underusing the equity method of accounting, an impairment loss would be recorded whenever the fair value of an equity investment is determined to be below its carrying amount and the reduction is considered to be other than temporary. In judging “other than temporary,” we consider the length of time and extent to which the fair value of the investment has been less than the carrying amount of the equity investment, the near-term and long-term operating and financial prospects of the entity and our longer-term intent of retaining our investment in the entity.
In the event we incur losses in excess of the carrying amount of anour 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 have the option to assess qualitative factors to determine if it is necessary to perform the first step. If it is more likely than not that a reporting unit’s fair value is less than its carrying amount, we must perform the quantitative goodwill impairment test, which involves estimating the reporting unit’s fair value and comparing it to its carrying amount. If the reporting unit’s carrying amount exceeds its fair value, the second step is performed by comparing the implied fair value of goodwill with the reporting unit’s carrying amount of goodwill. If the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess.excess, but not to exceed the goodwill’s carrying amount.
We previously performedperform an impairment analysis of goodwill at least annually as of November 1 or more frequently whenever events or circumstances occur indicating that itgoodwill might be impaired. As a result of our 2015 goodwill impairment analysis, we recorded an impairment charge of $16.4 million to write off the goodwill associated with our U.K. well intervention reporting unit. As a result of our 2016 goodwill impairment analysis, we recorded an impairment charge of $45.1 million to write off the entireOur goodwill balance attributable to the acquisition of our robotics reporting unit. Wea controlling interest in Subsea Technologies Group Limited (“STL”) was fully impaired during 2020, and we had no goodwill remaining on ourin the accompanying consolidated balance sheetssheet at December 31, 2017 and 2016.2020 (Note 7).
Deferred Recertification Costs and Deferred 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 athe vessel is in dry dock. In addition, routine repairs and maintenance are performed and at times, major replacements and improvements are performed. We expense routine repairs and maintenance costs as they are incurred. We defer and amortize recertification costs, including vessel dry dock and related recertification costs, over the length of time forperiod that the certification applies, which we expectgenerally ranges from 30 to receive benefits from the dry dock and related recertification, which is generally 30 months but can be as long as 60 months if the appropriate permitting is obtained. A recertification process, including vessel dry dock, and related recertification process typically lasts between one to twothree months, a period during which thea vessel or a piece of equipment is idle and generally not available to earn revenue. Major replacements and improvements that extend the vessel’s economic useful life or functional operating capability of a vessel or a piece of equipment are capitalized and depreciated over the vessel’sasset’s remaining economic useful life. We expense routine repairs and maintenance costs as they are incurred.
As of December 31, 20172020 and 2016, capitalized2019, deferred recertification and dry dock costs, which were included within “Other assets, net” in the accompanying consolidated balance sheets (Note 3), totaled $12.4$21.5 million and $14.8$16.1 million (net of accumulated amortization of $7.1$21.8 million and $10.7$15.7 million), respectively. During the years ended December 31, 2017, 20162020, 2019 and 2015,2018, amortization expense related to deferred recertification and dry dock amortization expensecosts was $6.9$14.3 million, $14.0$12.4 million and $10.8$8.3 million, respectively.
Revenue Recognition
RevenuesRevenue 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 a ROVDrill to provide subsea construction, inspection, repair and maintenance services to oil and gas companies as well as subsea trenching and burial of pipelines and cables as well as seabed clearing for the oil and gas and the renewable energy markets. We also provide integrated robotic services by supplying vessels that deploy ROVs and trenchers. Our Production Facilities segment generates revenue by supplying vessels, personnel and equipment for oil and natural gas processing, well control response services, and oil and gas production from owned properties.
Our revenues are derived from contracts, which are both short-term and long-term in duration.service contracts with customers. Our servicesservice contracts generally contain either lump sum provisions or provisions for specific time, material and equipment charges that are billed in accordance with the terms of such contracts.contracts (dayrate contracts) or lump sum payment provisions (lump sum contracts). We recognize revenue as it is earned at estimated collectible amounts. Further, 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.
Unbilled revenue represents revenue attributableWe generally account for our services under contracts with customers as a single performance obligation satisfied over time. The single performance obligation in our dayrate contracts is comprised of a series of distinct time increments in which we provide services. We do not account for activities that are immaterial or not distinct within the context of our contracts as separate performance obligations. Consideration received under a contract is allocated to work completed priorthe single performance obligation on a systematic basis that depicts the pattern of the provision of our services to period end that has not yet been invoiced. All amounts included in unbilled revenue arethe customer.
The total transaction price for a contract is determined by estimating both fixed and variable consideration expected to be billedearned over the term of the contract. We generally do not provide significant financing to our customers and collected withindo not adjust contract consideration for the time value of money if extended payment terms are granted for less than one year. We monitorEstimated variable consideration, if any, is considered to be constrained and therefore is not included in the collectabilitytransaction price until it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur. At the end of each reporting period, we reassess and update our outstanding trade receivables on a continual basis in connection with our evaluationestimates of allowance for doubtful accounts.variable consideration and amounts of that variable consideration that should be constrained.
Dayrate Contracts.Contracts. Revenues generated from specific time, material and equipment contracts are generally earned on a dayrate basis and recognized as amounts are earned in accordance with contract terms. Certain dayrate contracts generally provide for payment according to the rates per day as stipulated in the contract (e.g., operating rate, standby rate, and repair rate). Invoices billed to the customer are typically based on the varying rates applicable to operating status on an hourly basis. Dayrate consideration is allocated to the distinct hourly time increment to which it relates and is therefore recognized in line with built-inthe contractual rate changes require us to record revenues on a straight-line basis.billed for the services provided for any given hour. Similarly, revenues from contracts that stipulate a monthly rate are recognized ratably during the month. We
Dayrate contracts also may receive revenuescontain fees charged to the customer for mobilization ofmobilizing and/or demobilizing equipment and personnel under dayrate contracts. Revenuespersonnel. Mobilization and demobilization are considered contract fulfillment activities, and related fees (subject to mobilizationany constraint on estimates of variable consideration) are deferredallocated to the single performance obligation and recognized ratably over the term of the contract. Mobilization fees are generally billable to the customer in the initial phase of a contract and generate contract liabilities until they are recognized as revenue. Demobilization fees are generally received at the end of the contract and generate contract assets when they are recognized as revenue prior to becoming receivables from the customer.
We receive reimbursements from our customers for the purchase of supplies, equipment, personnel services and other services provided at their request. Reimbursable revenues are variable and subject to uncertainty as the amounts received and timing thereof are dependent on factors outside of our influence. Accordingly, these revenues are constrained and not recognized until the related costs are incurred on behalf of the customer. We are generally considered a principal in these transactions and record the associated revenues at the gross amounts billed to the customer.
A dayrate contract modification involving an extension of the contract by adding days of services is generally accounted for prospectively as a separate contract, but may be accounted for as a termination of the existing contract and creation of a new contract if the consideration for the extended services does not represent their stand-alone selling prices.
Lump Sum Contracts. Revenues generated from lump sum contracts are recognized over time. Revenue is recognized based on the extent of progress towards completion of the performance obligation. We generally use the cost-to-cost measure of progress for our lump sum contracts because it best depicts the progress toward satisfaction of our performance obligation, which occurs as we incur costs under those contracts. Under the cost-to-cost measure of progress, the extent of progress towards completion is measured based on the ratio of cumulative costs incurred to date to the total estimated costs at completion of the performance obligation. Consideration, including lump sum mobilization and demobilization fees billed to the customer, is recorded proportionally as revenue in accordance with the cost-to-cost measure of progress. Consideration for lump sum contracts is generally due from the customer based on the achievement of milestones. As such, contract assets are generated to the extent we recognize revenues in advance of our rights to collect contract consideration and contract liabilities are generated when contract consideration due or received is greater than revenues recognized to date.
We review and update our contract-related estimates regularly and recognize adjustments in estimated profit on contracts under the cumulative catch-up method. Under this method, the impact of the adjustment on profit recorded to date on a contract is recognized in the period in which contracted servicesthe adjustment is identified. Revenue and profit in future periods of contract performance are performed using the straight-line method. Incremental costs incurred directly for mobilization of equipment and personnel to the contracted site, which typically consist of materials, supplies and transit costs, also are deferred and recognized using the same straight-line method. Mobilization costs to move vessels when a contract does not exist are expensed as incurred.
Lump Sum Contracts. Revenues on significant lump sum contracts are generally recognized under the percentage-of-completion method. Under the percentage-of-completion method, we recognize estimated contract revenue based on costs incurred to date as a percentage of total estimated costs.adjusted estimate. If a current estimate of total contract cost indicates an ultimate loss on a contract,costs to be incurred exceeds the estimate of total revenues to be earned, we recognize the projected loss in full when it is first determined. We recognize additionalidentified. A modification to a lump sum contract is generally accounted for as part of the existing contract and recognized as an adjustment to revenue related to claims when the claim is probableon a cumulative catch-up basis.
Income from Oil and legally enforceable.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, 2017,2020, 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. Tax deduction benefits for a share-based award in excess of recognized compensation cost is reported as a financing cash flow rather than as an operating cash flow.
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 respectiveapplicable vesting periodsperiod 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 based on theat 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 cash payout that would occurvalue 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, 2017 and 2016, and the resulting translation adjustments which were unrealized gains (losses) of $16.3 million and $(35.9) million, respectively, are included in Accumulated other comprehensive lossincome (loss) (“Accumulated OCI”), a component of shareholders’ equity..
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, 2017, 20162020, 2019 and 2015,2018, our foreign currency transaction gains (losses) totaled $(2.2)$4.6 million, $0.2$1.5 million and $(1.2)$(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. Hedges of cashCash flow exposurehedges are entered into to hedge a forecasted transaction or 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 Accumulated OCI to the extent that the hedges are effective.OCI. These changes are subsequently reclassified into earnings when the hedged transactions occur. 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 Accumulatedaccumulated OCI into earnings immediately. If the forecasted transaction continues to be probable of occurring, any gains or losses in Accumulated OCI are reclassified into earnings over the remaining period of the original forecasted transaction.
Interest Rate Risk
From time to time, we enter into interest rate swaps to stabilize cash flows related to our long-term variable interest rate debt. Changes in the fair value of interest rate swaps are reported in Accumulated OCI 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 the line titled “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. 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 the line titled “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 the net income applicableor loss attributable to our common shareholders by the weighted average shares of our outstanding common stock.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 income included in the numerator excludes the effects of the impact of dilutive common stock equivalents, if any. We have shares of restricted stock issued and outstanding that are currently unvested. HoldersBecause holders of such shares of unvested restricted stock are entitled to the same liquidation and dividend rights as the holders of our outstanding 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 the 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 amounts 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 contractually 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 percentpercentages of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) isare as follows: 20172020 — BP (19%), Petrobras (13%(28%) and Talos (10%BP (17%); 2019 — Petrobras (29%), 2016 — BP (17%(15%) and Shell (11%(13%),; and 20152018 — Shell (16%Petrobras (28%) and Talos (11%BP (15%). 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 16.20.
New Accounting Standards
New accounting standards adopted
In May 2014,February 2016, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers2016-02, “Leases (Topic 606).842)” This ASU provides(“ASC842”), which was updated by subsequent amendments. ASC842 requires a five-step approach to account for revenue arising from contracts with customers. The ASU requires an entitylessee to recognize revenue in a way that depictslease ROU asset and related lease liability for most leases, including those classified as operating leases. ASC 842 also changes the transferdefinition of promised goods or services to customers in an amount that reflectsa lease and requires expanded quantitative and qualitative disclosures for both lessees and lessors. We adopted ASC842 as of January 1, 2019 using the consideration to whichmodified retrospective method. We also elected the entity expects to be entitled in exchange for those goods or services. This revenue standard was originally effective for annual reporting periods beginning after December 15, 2016, including interim periods, and was subsequently deferred by one year to annual reporting periods beginning after December 15, 2017. The FASB also issued several subsequent updates containing implementation guidance on principal versus agent considerations (gross versus net revenue presentation), identifying performance obligations and accounting for licensespackage of intellectual property. Additionally, these updates provide narrow-scope improvements and practical expedients as well as technical corrections and improvements topermitted under the guidance. The new revenue standard permitstransition guidance that, among other things, allows companies to either apply the requirements retrospectively to all prior periods presented or apply the requirementscarry forward their historical lease classification. Our adoption of ASC842 resulted in the yearrecognition of operating lease liabilities of $259.0 million and corresponding ROU assets of$253.4 million (net of existing prepaid/deferred rent balances) as of January 1, 2019. In addition, we reclassified the remaining deferred gain of $4.6 million (net of deferred taxes of $0.9 million) on a 2016 sale and leaseback transaction to retained earnings. Subsequent to adoption, through a modified retrospective approach with a cumulative adjustment. We have completed our assessment ofleases in foreign currencies will generate foreign currency gains and losses, and we will no longer amortize the differences betweendeferred gain from the new revenue standardaforementioned sale and current accounting practices (gap analysis). We continue to work on expanded disclosure requirementsleaseback transaction. Aside from these changes, ASC842 has not had, and documentation of new policies, procedures and controls. Although not finalized, based on the implementation efforts performed, management’s assessment is that the new revenue standard is not expected to have, a material impact on our consolidated financial statements. We are applying the modified retrospective approach to adopt this guidance effective in the first quarter of 2018.net earnings or cash flows. See Note 6 for additional information regarding our leases.
In November 2015, the FASB issued ASU No. 2015-17, “Balance Sheet Classification of Deferred Taxes.” This ASU requires companies to classify all deferred tax assets and liabilities as non-current on the balance sheet instead of separating deferred taxes into current and non-current amounts. The requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount was not affected by this guidance. We adopted this guidance prospectively in the first quarter of 2017. Prior periods were not retrospectively adjusted.
In February 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU amends the existing accounting standards for leases. The amendments are intended to increase transparency and comparability among organizations by requiring recognition of lease assets and lease liabilities on the balance sheet and disclosure of key information about leasing arrangements. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. The guidance is required to be adopted at the earliest period presented using a modified retrospective approach. Based on our current portfolio of leases and vessel charters, we expect to record right-of-use assets and lease liabilities on our balance sheet upon adoption of this guidance in the first quarter of 2019. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
In March 2016, the FASB issued ASU No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” This ASU simplifies several aspects of the accounting for share-based payment transactions, including income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification in the statement of cash flows. We adopted this guidance in the first quarter of 2017 with no material impact on our consolidated financial statements.
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. The guidance is effectiveUpon 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 annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will havecurrent expected credit losses on our consolidated financial statements.accounts receivable through a cumulative effect offset to retained earnings. The credit loss standard also resulted in the recognition of an additional $0.7 million in credit loss reserves on our accounts receivable for the year ended December 31, 2020. See Note 19 for additional information regarding allowance for credit losses on our accounts receivable.
New accounting standards issued but not yet effective
In August 2017,2020, the FASB issued ASU No. 2017-12, “Targeted Improvements2020-06, “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 Accountingseparate 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 Hedging Activities.” Thisin their entirety as liabilities measured at their amortized cost. We have elected to early adopt ASU improvesNo.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 financial reportingconversion features associated with our various outstanding convertible senior notes from equity to long-term debt. The adoption of hedging relationshipsthis 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 better align risk management activities in financial statementsits adoption, the ASU is also 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 convertible instruments and makes certain targeted improvements to simplifyinstead requires the application of the hedge accounting guidance in current GAAP. The guidance is effective for annual reporting periods beginning after December 15, 2018, including interim periods. Early adoption is permitted. We are currently evaluatingif-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):
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| 2020 | | 2019 |
| | | |
| Contract assets (Note 12) | $ | 2,446 | | | $ | 740 | |
| Prepaids | 15,904 | | | 12,635 | |
| Deferred costs (Note 12) | 23,522 | | | 28,340 | |
| Income tax receivable (Note 9) | 20,787 | | | 1,261 | |
| Other receivable (Note 16) | 29,782 | | | 0 | |
| Other | 9,651 | | | 7,474 | |
| Total other current assets | $ | 102,092 | | | $ | 50,450 | |
|
| | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | | | |
Note receivable (1) | $ | — |
| | $ | 10,000 |
|
| Prepaids | 10,102 |
| | 13,973 |
|
Deferred costs (2) | 27,204 |
| | 7,971 |
|
| Other | 4,462 |
| | 5,444 |
|
| Total other current assets | $ | 41,768 |
| | $ | 37,388 |
|
| |
(1) | Relates to the balance of the promissory note we received in connection with the sale of our former Ingleside spoolbase in January 2014. Interest on the note was payable quarterly at a rate of 6% per annum. In June 2017, we collected the remaining $10 million principal balance of this note receivable as well as accrued interest. |
| |
(2) | Primarily reflects deferred mobilization costs associated with certain long-term contracts, which are to be amortized within 12 months from the balance sheet date (Note 2). |
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, |
| | 2017 | | 2016 |
| | | | |
Note receivable, net (1) | $ | 3,758 |
| | $ | 2,827 |
|
| Prepaids | 7,666 |
| | 6,418 |
|
| Deferred dry dock costs, net (Note 2) | 12,368 |
| | 14,766 |
|
Deferred costs (2) | 63,767 |
| | 30,738 |
|
Charter fee deposit (3) | 12,544 |
| | 12,544 |
|
| Other | 5,102 |
| | 5,256 |
|
| Total other assets, net | $ | 105,205 |
| | $ | 72,549 |
|
| |
(1) | In 2016, we entered into an agreement with one of our customers to defer their payment obligations to June 30, 2018. On March 30, 2017, we entered into a new agreement with this customer in which we agreed to forgive all but $4.3 million of receivables due from the customer in exchange for its redeemable convertible bonds that approximated that amount. The bonds are redeemable by the customer at any time and the maturity date of the bonds is December 14, 2019. Interest at a rate of 5% per annum is payable annually on the bonds. The amount at December 31, 2017 reflected the fair value of the bonds as of that date (Note 16). The amount at December 31, 2016 was net of allowance of $4.2 million. |
| |
(2) | Primarily reflects deferred mobilization costs to be amortized after 12 months from the balance sheet date through the end of the applicable term of certain long-term contracts (Note 2). |
| |
(3) | Represents deposit 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, |
| | 2017 | | 2016 | | 2020 | | 2019 |
| | | | | | | | |
| Accrued payroll and related benefits | $ | 30,685 |
| | $ | 20,705 |
| Accrued payroll and related benefits | $ | 24,768 | | | $ | 31,417 | |
| Deferred revenue | 12,609 |
| | 8,911 |
| |
| Derivative liability (Note 17) | 10,625 |
| | 18,730 |
| |
| 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 | 17,761 |
| | 10,268 |
| Other | 14,617 | | | 11,393 | |
| Total accrued liabilities | $ | 71,680 |
| | $ | 58,614 |
| 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, |
| | 2017 | | 2016 |
| | | | |
| Investee losses in excess of investment (Note 5) | $ | 7,567 |
| | $ | 10,238 |
|
| Deferred gain on sale of property (Note 4) | 5,838 |
| | 5,761 |
|
| Deferred revenue | 8,744 |
| | 8,598 |
|
| Derivative liability (Note 17) | 8,150 |
| | 20,191 |
|
| Other | 10,391 |
| | 8,197 |
|
| Total other non-current liabilities | $ | 40,690 |
| | $ | 52,985 |
|
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 | | 2017 | | 2016 | | Estimated Useful Life | | 2020 | | 2019 |
| | | | | | | | | | | |
| Vessels | 15 to 30 years | | $ | 2,083,267 |
| | $ | 1,860,379 |
| Vessels | 15 to 30 years | | $ | 2,349,752 | | | $ | 2,323,314 | |
| ROVs, trenchers and ROVDrills | 10 years | | 298,227 |
| | 309,603 |
| |
| ROVs, trenchers and ROVDrill | | ROVs, trenchers and ROVDrill | 10 years | | 263,968 | | | 270,004 | |
| Machinery, equipment and leasehold improvements | 5 to 15 years | | 314,278 |
| | 280,908 |
| Machinery, equipment and leasehold improvements | 5 to 15 years | | 335,187 | | | 328,956 | |
| Total property and equipment | | $ | 2,695,772 |
| | $ | 2,450,890 |
| Total property and equipment | | $ | 2,948,907 | | | $ | 2,922,274 | |
Our assessment at December 31, 2015 indicated impairment on the Helix534 and the HP I. We impaired these assets based on the difference between the carrying amount and the estimated fair value. We recorded an impairment charge of $205.2 million to reduce the carrying amount of the Helix 534 to its estimated fair value of $1.0 million and to write off associated deferred dry dock costs of $9.0 million. The fair value of the Helix534 was based on its estimated salvage value according to current market pricing. We recorded an impairment charge of $133.4 million to reduce the carrying amount of the HP I to its estimated fair value of $124.3 million. We estimated the fair value of the HP I based on the present value of its expected future cash flows. In addition, we recorded impairment charges of $6.3 million to write off capitalized costs associated with certain vessel projects that we no longer expected to materialize.
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.
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, which owns the “IndependenceLLC (“Independence Hub” platform located in Mississippi Canyon Block 920 in a water depth of 8,000 feet. We previously had a 50% ownership interest in Deepwater Gateway, which owns and operates a tension leg platform production hub primarily for Anadarko Petroleum Corporation’s Marco Polofield in the Deepwater Gulf of Mexico. Our Production Facilities segment includes our investment in Independence Hub) that is accountedwe account for using the equity method of accounting, and previously included our former ownership interest in Deepwater Gateway.
In December 2015, we were notified that the operator of the facility no longer forecasted utilization ofaccounting. Independence Hub owns the “Independence Hub” platform, which is nearing the completion of its decommissioning. The remaining liability balances for our share of Independence Hub’s estimated obligations, net of remaining working capital, were $1.5 million and planned$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 turn overbe received in the platform for decommissioning. As a resultfuture totaled $2.1 million.
The following table details the components of this determination, Independence Hub recorded an impairment charge of $343.3 million to reduce the carrying amount of the platform assets to their estimated fair value of zero. 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 year ended December 31, 2015, we recorded losses totaling $74.9 million to account for our 20% share of losses from Independence Hub and to write off the remaining capitalized interest of $3.62018, total rental expense was approximately $147.8 million and a $1.0 million participation fee that we paid in 2004. For the years ended December 31, 2017 and 2016, we recorded losses totaling $2.4 million and $2.2 million, respectively, to account for our share of losses from Independence Hub. Since we are committed to providing the necessary level of financial support to enable Independence Hub to pay its obligations as they become due, we recorded liabilities of $9.8 million and $10.2 million at December 31, 2017 and 2016, respectively, for our share of the estimated obligations, net of remaining working capital. These liabilities are reflected in “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets. We did not receive any cash distributions from Independence Hub in 2016 or 2017. For the year ended December 31, 2015, we received a cash distribution of $1.8total sublease rental income was $1.4 million.
AdditionallyMaturities 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 70% controlling interest in December 2015, Deepwater Gateway recorded an impairment chargeSTL, a subsea engineering firm based in Aberdeen, Scotland, for $5.1 million. The holders of $96.7 millionthe remaining 30% noncontrolling interest currently have the right to reduceput 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 its long-lived assetsgoodwill 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 their estimated fair valuegoodwill arising from the acquisition of $70.8 million. For the year ended December 31, 2015, we recorded losses totaling $49.4 million to account for our 50% share of losses from Deepwater Gateway and to write off the remaining capitalized interest of $1.2 million. These losses included our share of an impairment charge that Deepwater Gateway recorded in December 2015. For the year ended December 31, 2015, we received a cash distribution of $5.2 million from Deepwater Gateway. In February 2016, we received a cash distribution of $1.2 million and sold our ownershipcontrolling interest in Deepwater GatewaySTL in May2019.
(2)Relates to a subsidiaryforeign currency adjustments.
(3)Relates to the impairment of Genesis for $25 million.the entire STL goodwill balance in March2020.
Equity method investments were immaterial to our 2016 and 2017 consolidated financial results. For the year ended December 31, 2015, the summarized aggregated revenues, operating loss and net loss related to our equity method investments were $14.8 million, $448.1 million and $448.1 million, respectively.
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, |
| | 2017 | | 2016 |
| | | | |
| Former term loan (was scheduled to mature June 2018) | $ | — |
| | $ | 192,258 |
|
| Term Loan (matures June 2020) | 97,500 |
| | — |
|
| 2022 Notes (mature May 2022) | 125,000 |
| | 125,000 |
|
| 2032 Notes (mature March 2032) | 60,115 |
| | 60,115 |
|
| MARAD Debt (matures February 2027) | 77,000 |
| | 83,222 |
|
| Nordea Q5000 Loan (matures April 2020) | 160,714 |
| | 196,429 |
|
| Unamortized debt discounts | (14,406 | ) | | (19,094 | ) |
| Unamortized debt issuance costs | (10,296 | ) | | (11,963 | ) |
| Total debt | 495,627 |
| | 625,967 |
|
| Less current maturities | (109,861 | ) | | (67,571 | ) |
| Long-term debt | $ | 385,766 |
| | $ | 558,396 |
|
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, 2017,2020, 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 $81.6$160.2 million, net of $3.0$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 interestat either in relation to Bank of America’s base rate, the LIBOR or to a LIBOR rate.comparable successor rate, or a combination thereof. The Term Loan or portions thereof bearing interest at the base rate will bear interest at a per annum rate equal to theBank of America’s base rate plus 3.25%a margin of 2.25%. The Term Loan or portions thereof 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 3.40% as of December 31, 2020. Borrowings under the Revolving Loans or portions thereofCredit Facility bearing interest at the base rate will bear interest at a per annum rate equal to theBank of America’s base rate plus a margin ranging from 1.75%1.50% to 3.25%2.50%. TheBorrowings under the Revolving Loans or portions thereofCredit 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 amountsindebtedness outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We may prepay amountsindebtedness 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 documents entered into in connection with the Credit Agreement include terms and conditions, including covenants, whichthat we consider customary for this type of transaction. The covenants include certain restrictions on our and certain of our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and make capital expenditures. In addition, the Credit Agreement obligates us to meet minimum financial ratio requirements of EBITDA to interest charges (“Consolidated(Consolidated Interest Coverage Ratio”) andRatio), funded debt to EBITDA (“Consolidated(Consolidated Total Leverage Ratio”),Ratio) and provided that if 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 initial 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 are also required to ensure that the ratio of our total secured indebtedness to EBITDA (“Consolidated(Consolidated Secured Leverage Ratio”) does not exceed the maximum permitted ratio. The Credit Agreement also obligates us to maintain certain cash levels depending on the type of indebtedness outstanding. These financial covenant requirements are detailed as follows:Ratio).
| |
(a) | The minimum required Consolidated Interest Coverage Ratio: |
|
| | | |
Four Fiscal Quarters Ending | Minimum Consolidated
Interest Coverage Ratio
|
| | |
December 31, 2017 and each fiscal quarter thereafter | 2.50 |
| to 1.00 |
| |
(b) | The maximum permitted Consolidated Total Leverage Ratio or Consolidated Net Leverage Ratio: |
|
| | | |
Four Fiscal Quarters Ending | Maximum Consolidated
Total or Net Leverage Ratio
|
| | |
December 31, 2017 | 5.75 |
| to 1.00 |
March 31, 2018 | 5.50 |
| to 1.00 |
June 30, 2018 | 5.25 |
| to 1.00 |
September 30, 2018 | 5.00 |
| to 1.00 |
December 31, 2018 through and including March 31, 2019 | 4.50 |
| to 1.00 |
June 30, 2019 through and including September 30, 2019 | 4.25 |
| to 1.00 |
December 31, 2019 | 4.00 |
| to 1.00 |
March 31, 2020 and each fiscal quarter thereafter | 3.50 |
| to 1.00 |
| |
(c) | The maximum permitted Consolidated Secured Leverage Ratio: |
|
| | | |
Four Fiscal Quarters Ending | Maximum Consolidated
Secured Leverage Ratio
|
| | |
December 31, 2017 through and including June 30, 2018 | 3.00 |
| to 1.00 |
September 30, 2018 and each fiscal quarter thereafter | 2.50 |
| to 1.00 |
| |
(d) | The minimum required Unrestricted Cash and Cash Equivalents: |
|
| | |
Consolidated Total Leverage Ratio | Minimum Cash (1)
|
| |
Greater than or equal to 4.00 to 1.00 | $100,000,000.00 |
Greater than or equal to 3.50 to 1.00 but less than 4.00 to 1.00 | $50,000,000.00 |
Less than 3.50 to 1.00 | $0.00 |
| |
(1) | This minimum cash balance is not required to be maintained in any particular bank account or to be segregated from other cash balances in bank accounts that we use in our ordinary course of business. Because the use of this cash is not legally restricted notwithstanding this maintenance covenant, we present it on our balance sheet as cash and cash equivalents. As of December 31, 2017, we were required to, and did, maintain an aggregate cash balance of at least $100 million in compliance with this covenant. |
We may from time to time designate one or more of our new foreign subsidiaries as subsidiaries which are 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 incorporated in Luxembourg (“Q5000 Holdings”). Our obligations under the Credit Agreement are guaranteed by our domestic subsidiaries (except Cal Dive I - Title XI, Inc.) and Canyon Offshore Limited, a wholly owned Scottish subsidiary. Our obligations under the Credit Agreement and of such guarantors under their guarantee are secured by (i) most of the assets of the parent, (ii) the shares of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and Canyon Offshore Limited, and (iii) most of the assets of our domestic subsidiaries (other than Cal Dive I - Title XI, Inc.) and Canyon Offshore Limited. In addition, these obligations are secured by pledges of up to 66% of the shares of certain foreign subsidiaries.Helix.
In June 2017,2019, in connection with an amendment of the Credit Agreement we recognized a $0.4 million loss to writewrote off the remaining unamortized debt issuance costs related to certain lendersassociated with a lender exiting the Credit Agreement. In March 2018, we prepaid $61 million of the then-existing term loan with a portion of the net proceeds from the term loan then outstanding under our credit facility prior to its June 2017 amendment2023 Notes and restatement. The loss iswrote off $0.9 million of unamortized debt issuance costs. These write-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.
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 net proceeds from the issuance of the 2022 Notes were $121.7 million, after deducting the underwriter’s discounts and commissions and offering expenses. We used net proceeds from the issuance of the 2022 Notes as well as cash on hand to repurchase and retire $125 million in principal of the 2032 Notes (see “Convertible Senior Notes Due 2032” below) in separate, privately negotiated transactions.
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, (as described in the Indenture governing the 2022 Notes) 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 as set forth in the Indenture governing the 2022 Notes.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 our option, subject to certain conditions, 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” with a value equal to(as defined in the present value of the remaining scheduled interest payments ofindenture governing the 2022 Notes to be redeemed through May 1, 2022.Notes). Holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change,” aschange” (as defined in the indenture governing the 2022 Notes.Notes).
The Indentureindenture 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 principalsignificant subsidiary, the principal amount of the 2022 Notes together with any accrued and unpaid interest thereon will automatically be and 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. To arrive at the debt value, we estimated the fair value of the liability component of the 2022 Notes as of October 26, 2016 using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of pricingDecember 31, 2020 and an expected life of 5.5 years. 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. The remaining unamortized amountNotes. For the years ended December 31, 2020, 2019 and 2018, interest expense (including amortization of the debt discount ofdiscount) related to the 2022 Notes was $13.9totaled $6.2 million, $8.4 million and $16.5$8.1 million, respectively. With the adoption of ASU No.2020-06 beginning January 1, 2021, the 2022 Notes will no longer be reported at December 31, 2017 and 2016, respectively.a discount. See Note 2 for the effect of ASU No.2020-06.
Convertible Senior Notes Due 20322023 (“2023 Notes”)
In March 2012, we completed a public offering and sale of our Convertible Senior Notes due 2032 (the “2032 Notes”) in the aggregate principal amount of $200 million, $60 million of which are currently outstanding. The 20322023 Notes bear interest at a rate of 3.25%4.125% per annum and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012.2018. The 20322023 Notes mature on MarchSeptember 15, 2032,2023 unless earlier converted, redeemed or repurchased. The 2032During certain periods and subject to certain conditions, the 2023 Notes are convertible in certain circumstances and during certain periodsby the holders into shares of our common stock at an initial conversion rate of 39.9752105.6133 shares of our common stock per $1,000 principal amount (which represents an initial conversion price of approximately $25.02$9.47 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes.circumstances. We have the right and the intention to settle the principal amount of any such future conversions in cash.
Prior to March 20, 2018,15, 2021, the 20322023 Notes are not redeemable. On or after March 20, 2018,15, 2021, if certain conditions are met, we at our option, may redeem someall or allany portion of the 20322023 Notes in cash, at any time upon at least 30 days’ notice, at a redemption price payable in cash equal to 100% of the principal amount to be redeemed plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the redemption date. In addition, the holders of the 2032 Notes may require us to purchase in cash some or all of their 2032 Notes atand a repurchase price equal to 100% of the principal amount of the 2032 Notes, plus accrued and unpaid interest (including contingent interest, if any) up to but excluding the applicable repurchase date, on March 15, 2018, March 15, 2022 and March 15, 2027, or, subject to specified exceptions, at any time prior to the 2032 Notes’ maturity following a “fundamental change,” as“make-whole premium” (as defined in the indenture governing the 2032 Notes. We elected2023 Notes). Holders of the 2023 Notes may require us to repurchase $7.3the 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 were initially separated between the equity component 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.
On August 14, 2020, we repurchased $95 million $7.6 million and $125 million, respectively, in aggregate principal amount of the 20322023 Notes in June, July and Novemberfor $94.1 million. We applied $78.2 million of 2016, respectively. For the year ended December 31, 2016, we recognized a net loss of $3.5 million relatedrepurchase price to the repurchasere-acquisition of the 2032 Notes, which is presented as “Loss on early extinguishment of long-term debt” in the accompanying consolidated statements of operations. On February 14, 2018, pursuant to the termsdebt component of the Indenture governing the 20322023 Notes we notified the holders that they have the option to require us to purchase their outstanding 2032 Notes on March 15, 2018.
and recognized an extinguishment gain of $5.9 million. The 2032 Notes are accounted for by separating the net proceeds between long-term debt and shareholders’ equity. In connection with the issuance of the 2032 Notes, we recorded aremaining unamortized debt discount of $35.4the 2023 Notes was $2.7 million and a separate$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 $22.5 million. To arrivethe 2023 Notes was $4.2 million ($3.6 million net of tax) and $20.1 million ($15.9 million net of tax) at the debt value, we estimated the fair value of the liability component of the 2032 Notes as of March 12, 2012 using an income approach. To determine this estimated fair value, we used borrowing rates of similar market transactions involving comparable liabilities at the time of pricingDecember 31, 2020 and an expected life of 6 years. In selecting the expected life, we selected the earliest date the holders could require us to repurchase all or a portion of the 2032 Notes (March 15, 2018). 2019, respectively.
The effective interest rate for the 20322023 Notes is 6.9%7.8% after considering the effect of the accretion of the related debt discount over the term of the 2023 Notes. For the years ended December 31, 2020, 2019 and 2018, interest expense (including amortization of the debt discount) related to the 2023 Notes totaled $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 representedupon 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 2032debt 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 at their inception.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 20322026 Notes was $0.5 million and $2.6$41.7 million at December 31, 2017 and 2016, respectively.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 amounts 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 17). 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.
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 restrictionsat its maturity 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.January 29, 2021.
Other
We previously issued additional convertible senior notes in March 2012, which were originally scheduled to mature on March 15, 2032 (the “2032 Notes”). In 2018, we fully redeemed the remaining $60.1 million in aggregate principal amount of the 2032 Notes and recognized a corresponding $0.2 million loss. The loss is presented as “Loss on extinguishment of long-term debt” in the accompanying consolidated statement of operations.
In accordance with ourthe Credit Agreement, the 2022 Notes, the 20322023 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, 2017,2020, we were in compliance with these covenants.
Scheduled maturities of our long-term debt outstanding as of December 31, 20172020 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 | | 2032 Notes (2) | | MARAD Debt | | Nordea Q5000 Loan | | Total |
| | | | | | | | | | | | |
| Less than one year | $ | 7,500 |
| | $ | — |
| | $ | 60,115 |
| | $ | 6,532 |
| | $ | 35,714 |
| | $ | 109,861 |
|
| One to two years | 12,500 |
| | — |
| | — |
| | 6,858 |
| | 35,714 |
| | 55,072 |
|
| Two to three years | 77,500 |
| | — |
| | — |
| | 7,200 |
| | 89,286 |
| | 173,986 |
|
| Three to four years | — |
| | — |
| | — |
| | 7,560 |
| | — |
| | 7,560 |
|
| Four to five years | — |
| | 125,000 |
| | — |
| | 7,937 |
| | — |
| | 132,937 |
|
| Over five years | — |
| | — |
| | — |
| | 40,913 |
| | — |
| | 40,913 |
|
| Total debt | 97,500 |
| | 125,000 |
| | 60,115 |
| | 77,000 |
| | 160,714 |
| | 520,329 |
|
| Current maturities | (7,500 | ) | | — |
| | (60,115 | ) | | (6,532 | ) | | (35,714 | ) | | (109,861 | ) |
| Long-term debt, less current maturities | 90,000 |
| | 125,000 |
| | — |
| | 70,468 |
| | 125,000 |
| | 410,468 |
|
Unamortized debt discounts (3) | — |
| | (13,876 | ) | | (530 | ) | | — |
| | — |
| | (14,406 | ) |
Unamortized debt issuance costs (4) | (1,658 | ) | | (2,295 | ) | | (46 | ) | | (4,513 | ) | | (1,784 | ) | | (10,296 | ) |
| Long-term debt | $ | 88,342 |
| | $ | 108,829 |
| | $ | (576 | ) | | $ | 65,955 |
| | $ | 123,216 |
| | $ | 385,766 |
|
| |
(1) | Term Loan borrowing pursuant to the Credit Agreement matures in June 2020. |
| |
(2) | The holders of our remaining 2032 Notes may require us to repurchase the notes in March 2018. Accordingly, these notes are classified as current liabilities. |
| |
(3) | The 2022 Notes will increase to their face amount through accretion of the debt discount through May 2022. The 2032 Notes will increase to their face amount through accretion of the debt discount through March 2018. |
| |
(4) | Debt issuance costs are amortized 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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Interest expense | $ | 38,274 |
| | $ | 45,110 |
| | $ | 40,024 |
|
| Interest income | (2,590 | ) | | (2,086 | ) | | (2,068 | ) |
| Capitalized interest | (16,906 | ) | | (11,785 | ) | | (11,042 | ) |
| Net interest expense | $ | 18,778 |
| | $ | 31,239 |
| | $ | 26,914 |
|
Note 79 — Income Taxes
On December 22, 2017, the U.S. Tax Cuts and Jobs Act (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 of the U.S. taxation of multinational corporations from a tax on worldwide income 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 (“SAB 118”), which provides SEC staff guidance for the application of ASC Topic 740, Income Taxes, to the 2017 Tax Act. SAB 118 allows for a measurement period of up to one year after the enactment date to finalize the recording of the related tax impacts. Our 2017 financial results reflect the provisional income tax effects of the 2017 Tax Act for which the accounting under ASC Topic 740 is incomplete but a reasonable estimate could be determined. We did not identify any items for which the income tax effects of the 2017 Tax Act could not be reasonably estimated as of December 31, 2017.
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 is 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 is 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.
We believe the provisional amounts recorded during the fourth quarter of 2017 represent a reasonable estimate of the accounting implications of this U.S. tax reform. Our ultimate determination of the tax impacts may differ from the provisional amounts recorded during the fourth quarter of 2017 due to regulatory guidance expected to be issued in the future, tax law technical corrections, and possible changes in the our interpretations, assumptions, and actions taken as a result of tax legislation refinement and clarification. In addition, we are still analyzing certain aspects of the 2017 Tax Act and refining our calculations for historical foreign E&P, which could potentially affect the measurement of these provisional balances. We will continue to evaluate the 2017 Tax Act, and any adjustment to these provisional amounts will be reported in the reporting period in which any such adjustments are determined, which will be no later than the fourth quarter of 2018.
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, anduncertain; 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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Current | $ | 4,161 |
| | $ | (27,319 | ) | | $ | 1,832 |
|
| Deferred | (54,585 | ) | | 14,849 |
| | (103,022 | ) |
| | $ | (50,424 | ) | | $ | (12,470 | ) | | $ | (101,190 | ) |
| | | Domestic | $ | (53,044 | ) | | $ | (9,631 | ) | | $ | (102,978 | ) | Domestic | $ | (15,074) | | | $ | 3,715 | | | $ | (3,161) | |
| Foreign | 2,620 |
| | (2,839 | ) | | 1,788 |
| Foreign | (3,627) | | | 4,144 | | | 5,561 | |
| | $ | (50,424 | ) | | $ | (12,470 | ) | | $ | (101,190 | ) | | $ | (18,701) | | | $ | 7,859 | | | $ | 2,400 | |
Components of income (loss) before income taxes are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| Domestic | $ | (3,406) | | | $ | 2,219 | | | $ | (28,838) | |
| Foreign | 4,789 | | | 63,337 | | | 59,836 | |
| $ | 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.
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Domestic | $ | (221 | ) | | $ | (61,484 | ) | | $ | (485,760 | ) |
| Foreign | (20,151 | ) | | (32,431 | ) | | 7,590 |
|
| | $ | (20,372 | ) | | $ | (93,915 | ) | | $ | (478,170 | ) |
Income taxes are provided based on the U.S. statutory rate of 35% 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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Statutory rate | 35.0 | % | | 35.0 | % | | 35.0 | % |
| Foreign provision | (6.2 | ) | | (5.1 | ) | | (13.7 | ) |
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 | (3.6 | ) | | 0.2 |
| | (0.1 | ) |
| Effective rate | 247.5 | % | | 13.3 | % | | 21.2 | % |
| |
(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. This amount consists of two components: (i) a $59.7 million deferred tax benefit resulting from the remeasurement of our net deferred tax liabilities in the U.S. based on the new lower corporate income tax rate, and (ii) an $8.1 million deferred tax charge relating to the one-time mandatory tax on previously deferred earnings of certain non-U.S. subsidiaries that are owned either wholly or partially by one of our U.S. subsidiaries. |
| |
(2) | We consider all available evidence, both positive and negative, when determining whether a valuation allowance is required against deferred tax assets. Due to weaker near term outlook and financial results primarily associated with our Robotics segment, we currently do not anticipate generating sufficient foreign source income to fully utilize our foreign tax credits prior to their expiration. We have concluded that it is more likely than not previously recorded deferred tax assets attributable to foreign tax credits will not be realized. As a result of this change in tax position, we recorded a tax charge of $6.3 million in June 2017, which is comprised of a $2.8 million valuation allowance attributable to a foreign tax credit carryforward from 2015 and a $3.5 million charge attributable to the decision to deduct foreign taxes related to 2016 and 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, |
| | 2017 | | 2016 | | 2020 | | 2019 |
| Deferred tax liabilities: | | | | Deferred tax liabilities: | | | |
| Depreciation | $ | 135,824 |
| | $ | 192,777 |
| Depreciation | $ | 153,226 | | | $ | 166,239 | |
| Original issuance discount on 2022 Notes and 2032 Notes | 7,727 |
| | 11,802 |
| |
| Prepaid and other | 437 |
| | 1,448 |
| |
| 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 | $ | 143,988 |
| | $ | 206,027 |
| Total deferred tax liabilities | $ | 162,524 | | | $ | 170,882 | |
| Deferred tax assets: | | | | Deferred tax assets: | | | |
| Net operating losses | $ | (33,480 | ) | | $ | (20,910 | ) | Net operating losses | $ | (59,794) | | | $ | (64,178) | |
| Reserves, accrued liabilities and other | (19,496 | ) | | (38,131 | ) | Reserves, accrued liabilities and other | (11,631) | | | (13,203) | |
| Total deferred tax assets | (52,976 | ) | | (59,041 | ) | Total deferred tax assets | (71,425) | | | (77,381) | |
| Valuation allowance | 12,337 |
| | 3,771 |
| Valuation allowance | 19,722 | | | 18,631 | |
| Net deferred tax liabilities | $ | 103,349 |
| | $ | 150,757 |
| Net deferred tax liabilities | $ | 110,821 | | | $ | 112,132 | |
| Deferred income tax is presented as: | | | | |
| Current deferred tax assets | $ | — |
| | $ | (16,594 | ) | |
| Non-current deferred tax liabilities | 103,349 |
| | 167,351 |
| |
| Net deferred tax liabilities | $ | 103,349 |
| | $ | 150,757 |
| |
At December 31, 2017,2020, our U.S. net operating losses available for carryforward totaled $115.8$197.4 million, of which $85.1 million occurred after the passage of the 2017 Tax Act and our U.K. net operating losses of our well intervention company available for carryforward totaled $3.9 million.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, 2017,2020, 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, 2017,2020, we had a $9.4$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 benefit.benefits. Additional valuation allowances may be made in the future if in management’s opinion it is more likely than not that thefuture tax benefitbenefits will not be utilized.
At December 31, 2017,2020, we had accumulated undistributed earnings generated by our non-U.S. subsidiaries without operations in the U.S. of approximately $48 million, all$62.2 million. Due to the enactment of which wasthe U.S. Tax Cuts and Jobs Act (the “2017 Tax Act”), repatriations of foreign earnings will generally be free of U.S. federal tax but may be subject to the one-time transitionchanges in future tax on foreign earnings requiredlegislation that may result in taxation. Indefinite reinvestment is determined by the 2017 Tax Act or has otherwise been previously taxed.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. As discussed above, changesWe have not provided deferred income taxes on the accumulated earnings and profits from our non-U.S. subsidiaries without operations in the our interpretations, assumptions,U.S. as we consider them permanently reinvested. Due to complexities in the tax laws and actions may result from further analysis and legislative clarificationsthe manner of repatriation, it is not practicable to estimate the 2017 Tax Act that occur during 2018.unrecognized amount of deferred income 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, 2017 and 2016, which if recognized would affect the annual effective tax rate. We had no uncertain tax positions as of December 31, 2015.
A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2017 and 2016 is as follows (in thousands):
|
| | | | | | | | | | | |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Balance at January 1, | $ | 343 |
| | $ | — |
| | $ | — |
|
| Additions for tax positions of prior years | — |
| | 343 |
| | — |
|
| Reductions for tax positions of prior years | (25 | ) | | — |
| | — |
|
| Balance at December 31, | $ | 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 2013, 2014, and 2018 through 20172020 remain open to review and examination by the Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 20092013 through 2017.2020.
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 estimated 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, netconsolidated balance sheet.
The components of Accumulatedaccumulated 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, |
| | 2017 | | 2016 |
| | | | |
| Cumulative foreign currency translation adjustment | $ | (62,689 | ) | | $ | (78,953 | ) |
Unrealized loss on hedges, net of tax (1) | (7,507 | ) | | (18,021 | ) |
| Unrealized gain on note receivable, net of tax | $ | 409 |
| | $ | — |
|
| Accumulated other comprehensive loss | $ | (69,787 | ) | | $ | (96,974 | ) |
| |
(1) | Relates to foreign currency hedges for the Grand Canyon, Grand Canyon II and Grand Canyon III charters as well as interest rate swap contracts for the Nordea Q5000 Loan, and are net of deferred income taxes totaling $4.0 million and $9.7 million as of December 31, 2017 and 2016, respectively (Note 17).
|
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 11)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, 2017, 3,234,0912020, 6,913,705 shares of our common stock were available for repurchase under the program.
Note 12 —Revenue from Contracts with Customers
Disaggregation of Revenue
The following table provides information about disaggregated revenue by contract duration (in thousands):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Well Intervention | | Robotics | | Production Facilities | | Intercompany Eliminations (1) | | Total Revenue |
| Year ended December 31, 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 | |
(1)Intercompany revenues among our business segments are under agreements that are considered long-term.
Contract Balances
Contract assets are rights to consideration in exchange for services that we have provided to a customer when those rights are conditioned on our future performance. Contract assets generally consist of (i)demobilization fees recognized ratably over the contract term but invoiced upon completion of the demobilization activities and (ii)revenue recognized in excess of the amount billed to the customer for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract assets are reflected in “Other current assets” in the accompanying consolidated balance sheets (Note 3). Contract assets as of December 31, 2020 and 2019 were $2.4 million and $0.7 million, respectively. We had no credit losses on our contract assets for the years 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 a single performance obligation and recognized ratably over the contract term and/or (ii)amounts billed to the customer in excess of revenue recognized for lump sum contracts when the cost-to-cost method of revenue recognition is utilized. Contract liabilities are reflected as “Deferred revenue,” a component of “Accrued liabilities” and “Other non-current liabilities” in the accompanying consolidated balance sheets (Note 3). Contract liabilities as of December 31, 2020 and 2019 totaled $10.0 million and $19.9 million, respectively. Revenue recognized for the years 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 each period.
We report the net contract asset or contract liability position on a contract-by-contract basis at the end of each reporting period.
Performance Obligations
As of December 31, 2020, $406.7 million related to unsatisfied performance obligations was expected to be recognized as revenue in the future, with $301.2 million in 2021, $72.9 million in 2022 and $32.6 million in 2023 and thereafter. These amounts include fixed consideration and estimated variable consideration for both wholly and partially unsatisfied performance obligations, including mobilization and demobilization fees. These amounts are derived from the specific terms of our contracts, and the expected timing for revenue recognition is based on the estimated start date and duration of each contract according to the information known at December 31, 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 Fulfillment Costs
Contract fulfillment costs consist of costs incurred in fulfilling a contract with a customer. Our contract fulfillment costs primarily relate to costs incurred for mobilization of personnel and equipment at the beginning of a contract and costs incurred for demobilization at the end of a contract. Mobilization costs are deferred and amortized ratably over the contract term (including anticipated contract extensions) based on the pattern of the provision of services to which the contract fulfillment costs relate. Demobilization costs are recognized when incurred at the end of the contract. Deferred contract costs are reflected as “Deferred costs,” a component of “Other current assets” and “Other assets, net” in the accompanying consolidated balance sheets (Note 3). Our deferred contract costs as of December 31, 2020 and 2019 totaled $24.4 million and $42.9 million, respectively. For the years 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. There were no associated impairment losses for any period presented.
Note 1013 — 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, |
| | 2017 | | 2016 | | 2015 |
| | Income | | Shares | | Income | | Shares | | Income | | Shares |
| Basic: | | | | | | | | | | | |
| Net income (loss) | $ | 30,052 |
| | | | $ | (81,445 | ) | | | | $ | (376,980 | ) | | |
| Less: Undistributed earnings allocated to participating securities | (356 | ) | | | | — |
| | | | — |
| | |
| Undistributed earnings (loss) allocated to common shares | $ | 29,696 |
| | 145,295 |
| | $ | (81,445 | ) | | 111,612 |
| | $ | (376,980 | ) | | 105,416 |
|
| | | | | | Diluted: | | | | | | | | | | | | Diluted: | |
| Undistributed earnings (loss) allocated to common shares | $ | 29,696 |
| | 145,295 |
| | $ | (81,445 | ) | | 111,612 |
| | $ | (376,980 | ) | | 105,416 |
| |
| 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 | — |
| | 5 |
| | — |
| | — |
| | — |
| | — |
| Share-based awards other than participating securities | 0 | | | 904 | | | 0 | | | 2,041 | | | 0 | | | 128 | |
| Undistributed earnings reallocated to participating securities | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Undistributed earnings reallocated to participating securities | 1 | | | — | | | 6 | | | — | | | 1 | | | — | |
| Net income (loss) | $ | 29,696 |
| | 145,300 |
| | $ | (81,445 | ) | | 111,612 |
| | $ | (376,980 | ) | | 105,416 |
| |
| 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 net losses for the years ended December 31, 2016 and 2015. Accordingly, our diluted EPS calculation for these periods 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 periods. Shares that otherwise would have been included in the diluted per share calculations assuming we had earnings are as follows (in thousands):
|
| | | | | |
| | Year Ended December 31, |
| | 2016 | | 2015 |
| | | | |
| Diluted shares (as reported) | 111,612 |
| | 105,416 |
|
| Share-based awards | 440 |
| | 59 |
|
| Total | 112,052 |
| | 105,475 |
|
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 because we have the right and the intention to settle any such future conversions in cash (Note 6)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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| 2022 Notes | 8,997 |
| | 1,475 |
| | — |
|
| 2032 Notes | 2,403 |
| | 6,891 |
| | 7,995 |
|
Note 1114 — 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, 20162020 and 2015, our costs related2019, we made discretionary employer contributions of $1.6 million and $1.0 million, respectively, to the 401(k) plan totaled $0.5 million and $2.8 million, respectively.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 0.6December 31, 2020, 1.8 million shares were available for issuance as of December 31, 2017.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. For the years ended December 31, 2017, 2016 and 2015, share-based compensation with respect to the ESPP was $0.1 million, $0.1 million and $1.1 million, respectively.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 three-yearthird 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, 2017,2020, there were 2.46.8 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 20172020 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 |
(1)Reflects grants of restricted stock to our executive officers and select management employees.
(2)Reflects grants of PSUs to our executive officers and select management employees. These awards when vested can only be settled in shares of our common stock.
(3)Reflects grants of restricted stock to certain independent members of our Board who have elected to take their quarterly fees in stock in lieu of cash.
(4)Reflects annual equity grants to each independent member of our Board.
|
| | | | | | | | | | | | | |
| Date of Grant | | | Shares | | | | Grant Date Fair Value Per Share | | | Vesting Period |
| | | | | | | | | | | |
January 3, 2017 (1) | | | 671,771 |
| | | | $ | 8.82 |
| | | 33% per year over three years |
January 3, 2017 (2) | | | 671,771 |
| | | | $ | 12.64 |
| | | 100% on January 1, 2020 |
January 3, 2017 (3) | | | 9,956 |
| | | | $ | 8.82 |
| | | 100% on January 1, 2019 |
April 3, 2017 (3) | | | 8,004 |
| | | | $ | 7.77 |
| | | 100% on January 1, 2019 |
July 3, 2017 (3) | | | 14,018 |
| | | | $ | 5.64 |
| | | 100% on January 1, 2019 |
October 2, 2017 (3) | | | 7,654 |
| | | | $ | 7.39 |
| | | 100% on January 1, 2019 |
December 7, 2017 (4) | | | 117,740 |
| | | | $ | 6.37 |
| | | 100% on December 7, 2018 |
| |
(1) | Reflects grants of restricted stock to our executive officers and select management employees. |
| |
(2) | Reflects grants of PSUs to our executive officers and select management employees. |
| |
(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 annual equity grants to each independent member of our Board. |
In January 2018,2021, we granted our executive officers 449,271 shares of restricted stock452,381 RSUs and 449,271452,381 PSUs under the 2005 Incentive Plan. The marketgrant date fair value of the restricted sharesRSUs was $7.54$4.20 per shareunit or $3.4$1.9 million. The grant date fair value of the PSUs was $10.44$5.33 per share.unit or $2.4 million. Also in January 2018,2021, we granted $5.0$3.4 million of fixed value cash awards to select management employees under the 2005 Incentive Plan.
Restricted Stock Awards
We grant restricted stock to members of our Board, 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, |
| | 2017 | | 2016 | | 2015 |
| | Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) | | Shares | | Grant Date Fair Value (1) |
| | | | | | | | | | | | |
| Awards outstanding at beginning of year | 1,577,973 |
| | $ | 7.86 |
| | 661,124 |
| | $ | 16.28 |
| | 554,960 |
| | $ | 17.54 |
|
| Granted | 829,143 |
| | 8.39 |
| | 1,298,121 |
| | 5.70 |
| | 501,076 |
| | 15.57 |
|
Vested (2) | (817,791 | ) | | 8.84 |
| | (305,588 | ) | | 16.94 |
| | (332,223 | ) | | 16.44 |
|
| Forfeited | (10,107 | ) | | 7.01 |
| | (75,684 | ) | | 7.76 |
| | (62,689 | ) | | 20.93 |
|
| Awards outstanding at end of year | 1,579,218 |
| | $ | 7.63 |
| | 1,577,973 |
| | $ | 7.86 |
| | 661,124 |
| | $ | 16.28 |
|
| |
(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, 2017, 2016 and 2015 was $6.9 million, $2.2 million and $5.1 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, 2017, 20162020, 2019 and 2015, $7.92018, $4.2 million, $5.8$6.2 million and $5.5$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, 20172020 totaled approximately $6.8$4.4 million. The weighted average vesting period related to unvested restricted stock at December 31, 20172020 was approximately 1.31.2 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 may be settled in either cash or shares of our common stock upon vesting at the discretion of the Compensation Committee of our Board. In January 2015, in connection with the vesting of the 2012 PSU awards, the decision was made to settle these PSUs in cash (rather than with an equivalent number of shares of our common stock, which was the default payment method for the 2012 PSU awards). Accordingly, PSUs granted before 2017, including those that were previously accounted for as equity awards, are treated as liability awards. PSUs granted in 2017 and 2018 are to be settled solely in shares of our common stock and therefore are accounted for as equity awards.0.
We issued 671,771 PSUs in 2017 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 $12.64 per unit, 1,161,672 PSUs in 2016 withwhich is determined using a grant date fair value of $7.13 per unit and 295,693 PSUs in 2015 with a grant date fair value of $25.06 per unit. Monte Carlo simulation model.
For the years ended December 31, 2017, 20162020, 2019 and 2015, $7.42018, $4.0 million, $6.8$5.1 million and $0.2$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, 2017During 2019 and 2016, the liability balance for unvested PSUs was2018, we cash settled liabilities of $11.1 million and $7.1$0.9 million, respectively. During 2015,respectively, related to PSU awards granted in 2016 and 2017, we paid $4.5 million, $0.2 million and $0.6 million, respectively, to cash settle the PSUs granted in 2012, 2013 and 2014. We paid $0.9 million to cash settle the 2015, grant of PSUs when they vested in January 2018.respectively.
Long-Term Incentive Cash Awards
We have from time to time made long-term incentiveIn 2020, 2019 and 2018, we granted $4.7 million, $4.6 million and $5.2 million, respectively, of fixed value cash awards to our executive officers and select management employees. Theseemployees under the 2005 Incentive Plan. The value of these cash awards were generally indexed to our common stock with the payment amount at each vesting date, if any, determined by the performance of our common stock over the relevant performance period. The cash awards vested equally each yearis recognized on a straight-line basis over a three-yearvesting period and payments under these awards were made on each anniversary date of the award. Our long-term incentive cash awards were considered liability plans and as such were re-measured to fair value each reporting period with corresponding changes in the liability amount being reflected in our results of operations.
No long-term incentive cash awards were granted in the last severalthree years. For the yearyears ended December 31, 2015,2020, 2019 and 2018, we recorded reductions of $3.7 million ($2.1 million related to our executive officers) of previously recognized compensation cost associated withcosts of $4.4 million and $3.2 million and $1.7 million, respectively, which reflected the cash awards, reflecting the effect that decreases in our stock price had on the value of our liability plan. The liability balance for the cash awards issued was reduced down to zero at December 31, 2016. During 2015, we paid $8.9 million of the liability associated with previously granted long-term incentive cash awards. No cash payout waspayouts made in 2016 or 2017 as the stock performance metric for payout was not met.January 2021, 2020 and 2019, respectively.
Note 1215 — 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 Brazil. Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and SILs.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 commencedOur well intervention operations for Petrobras offshore Brazil in April 2017equipment includes IRSs, SILs and the Siem Helix2 commenced operations for Petrobras in December 2017. We returned the Skandi Constructor to its owner in March 2017 upon the expirationROAM, some of the vessel charter. We previously owned the Helix 534, which we sold in December 2016 (Note 4).provide on a stand-alone basis. Our Robotics segment includes ROVs, trenchers and ROVDrillsa ROVDrill, which are designed to complement offshore construction and well intervention services and currently operates 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, including the Grand Canyon II and the Grand Canyon III that went into service for us in May 2017. Our vessel charter for the Deep Cygnus was terminated on February 9, 2018, at which time we returned the vessel to its owner., 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 previously included our former ownership interest in Deepwater Gateway that we sold in February 2016gas properties (Note 5)16). All material intercompany transactions between the segments have been eliminated.
We evaluate our performance based on operating income and income before income taxes 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, | |
| | 2017 | | 2016 | | 2015 | |
| Net revenues — | | | | | | |
| Income (loss) from operations — | | Income (loss) from operations — | |
| Well Intervention | $ | 406,341 |
| | $ | 294,000 |
| | $ | 373,301 |
| Well Intervention | $ | 26,855 | | | $ | 89,564 | | | $ | 87,643 | |
| Robotics | 152,755 |
| | 160,580 |
| | 301,026 |
| Robotics | 13,755 | | | 7,261 | | | (14,054) | |
| Production Facilities | 64,352 |
| | 72,358 |
| | 75,948 |
| Production Facilities | 15,975 | | | 17,160 | | | 27,263 | |
| Intercompany elimination | (42,065 | ) | | (39,356 | ) | | (54,473 | ) | |
| 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 | $ | 581,383 |
| | $ | 487,582 |
| | $ | 695,802 |
| 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) | $ | 52,733 |
| | $ | 14,910 |
| | $ | (194,381 | ) |
Robotics (2) | (42,289 | ) | | (72,250 | ) | | 27,832 |
|
Production Facilities (3) | 28,172 |
| | 33,861 |
| | (106,847 | ) |
| Corporate and other | (40,630 | ) | | (39,384 | ) | | (33,866 | ) |
| Intercompany elimination | 884 |
| | (372 | ) | | (98 | ) |
| Total | $ | (1,130 | ) | | $ | (63,235 | ) | | $ | (307,360 | ) |
| | | | | | | | | | | | | | | | | |
| 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).
|
| | | | | | | | | | | |
| Net interest expense — | | | | | |
| Well Intervention | $ | (156 | ) | | $ | (109 | ) | | $ | (102 | ) |
| Robotics | (30 | ) | | (25 | ) | | 29 |
|
| Production Facilities | — |
| | — |
| | 385 |
|
| Corporate and elimination | 18,964 |
| | 31,373 |
| | 26,602 |
|
| Total | $ | 18,778 |
| | $ | 31,239 |
| | $ | 26,914 |
|
|
| | | | | | | | | | | |
| Equity in losses of investments | $ | (2,368 | ) | | $ | (2,166 | ) | | $ | (124,345 | ) |
|
| | | | | | | | | | | |
| Income (loss) before income taxes — | | | | | |
Well Intervention (1) | $ | 48,948 |
| | $ | 18,813 |
| | $ | (193,572 | ) |
Robotics (2) (4) | (40,271 | ) | | (73,533 | ) | | 2,454 |
|
Production Facilities (3) | 25,804 |
| | 31,695 |
| | (231,577 | ) |
| Corporate and other and eliminations | (54,853 | ) | | (70,890 | ) | | (55,475 | ) |
| Total | $ | (20,372 | ) | | $ | (93,915 | ) | | $ | (478,170 | ) |
|
| | | | | | | | | | | |
| Income tax provision (benefit) — | | | | | |
| Well Intervention | $ | (29,934 | ) | | $ | 12,531 |
| | $ | (1,230 | ) |
| Robotics | (11,972 | ) | | (9,948 | ) | | 515 |
|
| Production Facilities | 9,032 |
| | 11,093 |
| | (81,052 | ) |
| Corporate and other and eliminations | (17,550 | ) | | (26,146 | ) | | (19,423 | ) |
| Total | $ | (50,424 | ) | | $ | (12,470 | ) | | $ | (101,190 | ) |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| Capital expenditures — | | | | | |
| Well Intervention | $ | 230,354 |
| | $ | 185,892 |
| | $ | 307,879 |
|
| Robotics | 648 |
| | 720 |
| | 10,700 |
|
| Production Facilities | — |
| | 74 |
| | 1,867 |
|
| Corporate and other | 125 |
| | (199 | ) | | (135 | ) |
| Total | $ | 231,127 |
| | $ | 186,487 |
| | $ | 320,311 |
|
|
| | | | | | | | | | | |
| Depreciation and amortization — | | | | | |
| Well Intervention | $ | 68,301 |
| | $ | 68,392 |
| | $ | 66,095 |
|
| Robotics | 23,626 |
| | 25,848 |
| | 26,724 |
|
| Production Facilities | 13,936 |
| | 13,952 |
| | 21,340 |
|
| Corporate and eliminations | 2,882 |
| | 5,995 |
| | 6,242 |
|
| Total | $ | 108,745 |
| | $ | 114,187 |
| | $ | 120,401 |
|
| |
(1) | Amount in 2016 included a $1.3 million gain on the sale of the Helix 534 in December 2016. Amount in 2015 included impairment charges of $205.2 million for the Helix 534 and $6.3 million for certain capitalized vessel project costs and a $16.4 million goodwill impairment charge related to our U.K. well intervention reporting unit.
|
| |
(2) | Amount in 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit. |
| |
(3) | Amount in 2015 included a $133.4 million impairment charge for the HP I.
|
| |
(4) | 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.
|
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, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| Well Intervention | $ | 11,489 |
| | $ | 8,442 |
| | $ | 22,855 |
|
| Robotics | 30,576 |
| | 30,914 |
| | 31,618 |
|
| Total | $ | 42,065 |
| | $ | 39,356 |
| | $ | 54,473 |
|
Revenues by individually significant regiongeographic location are as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| Year Ended December 31, |
| 2020 | | 2019 | | 2018 |
| | | | | |
| U.S. | $ | 304,563 | | | $ | 297,162 | | | $ | 271,260 | |
| U.K. | 133,005 | | | 193,903 | | | 194,434 | |
| Brazil | 208,565 | | | 216,796 | | | 208,054 | |
| Other | 87,422 | | | 44,048 | | | 66,070 | |
| Total | $ | 733,555 | | | $ | 751,909 | | | $ | 739,818 | |
|
| | | | | | | | | | | |
| | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 |
| | | | | | |
| United States | $ | 283,933 |
| | $ | 298,279 |
| | $ | 298,391 |
|
North Sea (1) | 159,961 |
| | 137,313 |
| | 263,438 |
|
| Brazil | 70,710 |
| | 2,543 |
| | 28,487 |
|
| Other | 66,779 |
| | 49,447 |
| | 105,486 |
|
| Total | $ | 581,383 |
| | $ | 487,582 |
| | $ | 695,802 |
|
| |
(1) | Includes revenues of $156.0 million, $123.6 million and $187.7 million, respectively, which were from the U.K. |
Our operational assets related to operations, primarily our vessels, operate throughout the yearwork in various regions around the world such as the U.S. Gulf of Mexico, Brazil, the North Sea, Brazil, Asia Pacific and West Africa. The following table provides our property and equipment, net of accumulated depreciation, by individually significant geographic location of our assets (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, |
| | 2017 | | 2016 |
| | | | |
| United States | $ | 894,680 |
| | $ | 956,458 |
|
| United Kingdom | 270,499 |
| | 299,699 |
|
| Brazil | 334,454 |
| | 123,461 |
|
Singapore (1) | 295,798 |
| | 194,649 |
|
| Other | 10,558 |
| | 77,343 |
|
| Total | $ | 1,805,989 |
| | $ | 1,651,610 |
|
| |
(1) | Primarily includes the Q7000 vessel under construction.
|
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, |
| | 2017 | | 2016 |
| | | | |
| Well Intervention | $ | 1,830,733 |
| | $ | 1,596,517 |
|
| Robotics | 179,853 |
| | 186,901 |
|
| Production Facilities | 138,292 |
| | 158,192 |
|
| Corporate and other | 213,959 |
| | 305,331 |
|
| Total | $ | 2,362,837 |
| | $ | 2,246,941 |
|
Note 1316 — 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 charter agreements for the Grand Canyon, Grand Canyon II and Grand Canyon III vessels for use in our robotics operations. In February 2016, we amended the charter agreements to reduce the charter rates and, in connection with those reductions, to extend the terms to October 2019 for the Grand Canyon, to April 2021 for the Grand Canyon II and to 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 with the same shipyard in Singapore that constructed the Q5000 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, including the third amendment that was entered into in November2017, 20% of the contract price was paid upon the signing of the contract in 2013, 20% was paid in 2016, 20% was paid in December2017, 20% is to be paid on December31, 2018, and 20% is to 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, 2017, our total investment in the Q7000 was $295.8 million, including $207.6 million of installment payments to the shipyard. Currently equipment is being manufactured and/or installed for the completion of the vessel.
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil, and in connection with the Petrobras agreements, we entered intolong-term charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohullthe Siem Helix1 and Siem Helix2 vessels, the Siem Helix1 and the Siem Helix2.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 initial termSiem Helix1 charter expires June 2023 and the Siem Helix2 charter expires February 2024. We have time charter agreements for the Grand CanyonII and Grand CanyonIII vessels for use in our robotics operations. The expiration date of the agreementsGrand CanyonII charter was extended in February 2021 from April 2021 until December 2021, with Petrobras is for four years with Petrobras’s optionsan option to extend.renew. The Grand CanyonIII charter expires May 2023.
The Siem Helix1 vessel was delivered to usWe took delivery of the Q7000 in November 2019, and the charter term began on June 14, 2016. The vessel was accepted by Petrobras and commenced operations on April 14, 2017. The Siem Helix2 was delivered to us andin January 2020. With the charter term began on February 10, 2017. The vessel was accepted by Petrobras and commenced operations on December 15, 2017 at contracted rates. At December 31, 2017, our total investment indelivery of the topside equipment for the two vessels was $309.8 million.
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 rentals at December 31, 2017 are as follows (in thousands):
|
| | | | | | | | | | | |
| | Vessels | | Facilities and Other | | Total |
| | | | | | |
| 2018 | $ | 121,811 |
| | $ | 6,207 |
| | $ | 128,018 |
|
| 2019 | 117,731 |
| | 5,354 |
| | 123,085 |
|
| 2020 | 100,373 |
| | 4,807 |
| | 105,180 |
|
| 2021 | 88,425 |
| | 4,706 |
| | 93,131 |
|
| 2022 | 83,617 |
| | 4,778 |
| | 88,395 |
|
| Thereafter | 45,858 |
| | 15,421 |
| | 61,279 |
|
| Total lease commitments | $ | 557,815 |
| | $ | 41,273 |
| | $ | 599,088 |
|
For the years ended December 31, 2017, 2016 and 2015, total rental expense was approximately $114.5 million, $87.8 million and $134.3 million, respectively.
We sublease someQ7000, all of our facilities under non-cancelable sublease agreements. For the years ended December 31, 2017, 2016 and 2015, total rental income was $1.3 million, $1.6 million and $1.4 million, respectively. As of December 31, 2017, the minimum rentals to be received in the future totaled $1.4 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 1418 — Statement of Cash Flow Information
The following table provides supplemental cash flow information (in thousands):
| | | | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Interest paid, net of interest capitalized | $ | 10,367 |
| | $ | 18,749 |
| | $ | 14,555 |
| Interest paid, net of interest capitalized | $ | 15,943 | | | $ | 1,909 | | | $ | 7,369 | |
| Income taxes paid | 6,015 |
| | 5,635 |
| | 16,905 |
| Income taxes paid | 7,434 | | | 8,856 | | | 5,705 | |
Our non-cash investing activitiescapital additions include the acquisition of property and equipment capital expenditures that are incurred butfor which payment has not yet paid.been made. As of December 31, 20172020 and 2016,2019, these non-cash capital expendituresadditions totaled $16.9$1.6 million and $10.1$10.2 million, respectively.
Note 1519 — 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, 20172020 (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, 2014 | $ | 4,735 |
| | $ | 23,076 |
|
Additions (1) | 3,275 |
| | — |
|
Deductions (2) | (7,660 | ) | | — |
|
Adjustments (3) | — |
| | (21,140 | ) |
| Balance at December 31, 2015 | 350 |
| | 1,936 |
|
Additions (1) | 1,778 |
| | — |
|
Deductions (2) | (350 | ) | | — |
|
Adjustments (4) | — |
| | 1,835 |
|
| Balance at December 31, 2016 | 1,778 |
| | 3,771 |
|
Additions (1) (5) | 1,206 |
| | 2,788 |
|
Deductions (2) | (232 | ) | | — |
|
Adjustments (4) | — |
| | 5,778 |
|
| Balance at December 31, 2017 | $ | 2,752 |
| | $ | 12,337 |
|
| |
(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 decrease in valuation allowance primarily reflects a $20.6 million reduction related to the loss of deferred tax assets for net operating losses within our Australian subsidiaries. |
| |
(4) | 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. |
| |
(5) | 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. |
(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.
Additionally, our non-current note receivable balance as of December 31, 2016 included an allowance of $4.2 million (Note 3). 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 1620 — 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 various 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 that are accounted for as cash flow hedges and our note receivable in the form of convertible bonds that are accounted for as investments in available-for-sale debt securities(Note 21) reflects our best estimate and is based upon exchange or over-the-counter quotations whenever they are available. Quoted valuations may not be available due to location differences or terms that extend beyond the period for which quotations are available. Where quotes are not available, we utilize other valuation techniques or models to estimate market values. The fair value of our interest rate swaps is calculated as the discounted cash flows of the difference between the rate fixed by the hedging instrument and the LIBOR forward curve over the remaining term of the hedging instrument. The fair value of our foreign currency
exchange contracts is calculated as the discounted cash flows of the difference between the fixed payment specified by the hedging instrument and the expected cash inflow of the forecasted transaction using a foreign currency forward curve. These modeling techniques require us to make estimations of future prices, price correlation, volatility and liquidity based on market data. 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, 2017 Using | | | | Valuation Approach |
| | Level 1 | | Level 2 | | Level 3 | | Total | |
| Assets: | | | | | | | | | |
| Note receivable | $ | — |
| | $ | 3,758 |
| | $ | — |
| | $ | 3,758 |
| | (c) |
| Interest rate swaps | — |
| | 966 |
| | — |
| | 966 |
| | (c) |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Foreign exchange contracts | — |
| | 12,467 |
| | — |
| | 12,467 |
| | (c) |
| Total net liability | $ | — |
| | $ | 7,743 |
| | $ | — |
| | $ | 7,743 |
| | |
| | | | Fair Value Measurements at
December 31, 2016 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: | | | | | | | | | |
| Interest rate swaps | $ | — |
| | $ | 451 |
| | $ | — |
| | $ | 451 |
| | (c) | Interest rate swaps | $ | 0 | | | $ | 44 | | | $ | 0 | | | $ | 44 | | | (c) |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | Liabilities: | |
| Foreign exchange contracts | — |
| | 38,170 |
| | — |
| | 38,170 |
| | (c) | |
| Interest rate swaps | — |
| | 751 |
| | — |
| | 751 |
| | (c) | |
| Foreign exchange contracts — hedging instruments | | Foreign exchange contracts — hedging instruments | 0 | | | 401 | | | 0 | | | 401 | | | (c) |
| Foreign exchange contracts — non-hedging instruments | | Foreign exchange contracts — non-hedging instruments | 0 | | | 601 | | | 0 | | | 601 | | | (c) |
| Total net liability | $ | — |
| | $ | 38,470 |
| | $ | — |
| | $ | 38,470 |
| | Total net liability | $ | 0 | | | $ | 958 | | | $ | 0 | | | $ | 958 | | |
The carrying valuesprincipal amount and estimated fair valuesvalue 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, |
| | 2017 | | 2016 |
| | Carrying Value (1) | | Fair Value (2) | | Carrying Value (1) | | Fair Value (2) |
| | | | | | | | |
| Former term loan (was scheduled to mature June 2018) | $ | — |
| | $ | — |
| | $ | 192,258 |
| | $ | 192,258 |
|
| Term Loan (matures April 2020) | 97,500 |
| | 98,231 |
| | — |
| | — |
|
| Nordea Q5000 Loan (matures April 2020) | 160,714 |
| | 160,111 |
| | 196,429 |
| | 192,746 |
|
| MARAD Debt (matures February 2027) | 77,000 |
| | 82,058 |
| | 83,222 |
| | 92,049 |
|
| 2022 Notes (mature May 2022) | 125,000 |
| | 124,219 |
| | 125,000 |
| | 130,156 |
|
| 2032 Notes (mature March 2032) | 60,115 |
| | 60,040 |
| | 60,115 |
| | 59,965 |
|
| Total debt | $ | 520,329 |
| | $ | 524,659 |
| | $ | 657,024 |
| | $ | 667,174 |
|
| |
(1) | Carrying value 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 and the 2032 Notes was determined using Level 1 inputs under the market approach. The fair value of the Nordea Q5000 Loan, the MARAD Debt, the Term Loan, and our previous term loan that was scheduled to mature June 2018 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. |
Note 1721 — Derivative Instruments and Hedging Activities
The following table presents the balance sheet location and fair value of the portions of our derivative instruments that was designated as hedging instruments (in thousands):
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
| Asset Derivative Instruments: | | | | | | | |
| Interest rate swaps | Other current assets | | $ | 311 |
| | Other current assets | | $ | — |
|
| Interest rate swaps | Other assets, net | | 655 |
| | Other assets, net | | 451 |
|
| | | | $ | 966 |
| | | | $ | 451 |
|
| | | | | | | | |
| Liability Derivative Instruments: | | | | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 7,492 |
| | Accrued liabilities | | $ | 14,056 |
|
| Interest rate swaps | Accrued liabilities | | — |
| | Accrued liabilities | | 751 |
|
| Foreign exchange contracts | Other non-current liabilities | | 4,975 |
| | Other non-current liabilities | | 13,383 |
|
| | | | $ | 12,467 |
| | | | $ | 28,190 |
|
The following table presents the balance sheet location and fair value of the portions of our derivative instruments that was not designated as hedging instruments (in thousands):
|
| | | | | | | | | | | |
| | December 31, |
| | 2017 | | 2016 |
| | Balance Sheet Location | | Fair Value | | Balance Sheet Location | | Fair Value |
| Liability Derivative Instruments: | | | | | | |
| Foreign exchange contracts | Accrued liabilities | | $ | 3,133 |
| | Accrued liabilities | | $ | 3,923 |
|
| Foreign exchange contracts | Other non-current liabilities | | 3,175 |
| | Other non-current liabilities | | 6,808 |
|
| | | | $ | 6,308 |
| | | | $ | 10,731 |
|
In January 2013,June 2015, we entered into foreign currency exchangeinterest rate swap contracts to fix the interest rate on $187.5 million of the Nordea Q5000 Loan (Note 8). These swap contracts expired in April 2020. Our interest rate swap contracts qualified for cash flow hedge through September 2017 our foreign currency exposure associated with the Grand Canyon charter payments denominated in Norwegian kroner. accounting treatment.
In February 2013, we entered into similar 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. In December 2015, we de-designated theA portion of our foreign currency exchange contracts associated with the charter payment obligations for the Grand Canyon II and Grand Canyon III vessels that no longer qualified for cash flow hedge accounting treatment and we re-designated the hedging relationship between a portion of these contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK434.1 million and NOK185.2 million, respectively, that were expected to remain highly probable of occurring. As a result, we recognized unrealized losses of $18.0 million related to the foreign currency exchange contracts associated with the portion of previously forecasted charter payments that would no longer be made. Reflected in “Other income (expense), net” in the accompanying consolidated statements of operations are these unrealized losses, as well as subsequent changes in unrealized losses associated with the portions of the foreign currency exchange contracts that are no longer designated as cash flow hedges.treatment.
Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying consolidated statementsWe had no derivative instruments that were designated as hedging instruments as of operations. For the year ended December 31, 2017, there2020. The following table presents the balance sheet location and fair value of our derivative instruments that were no gains or losses associated with hedge ineffectiveness. For the years endeddesignated as hedging instruments as of December 31, 2016 and 2015, we recorded gains (losses) of $0.1 million and $(5.1) million, respectively, related to hedge ineffectiveness.2019 (in thousands):
| | | | | | | | | | | |
| 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 | |
In September 2013, we entered into various interest rate swap contracts to fixWe had no derivative instruments that were not designated as hedging instruments as of December 31, 2020. The following table presents the interest rate on $148.1 millionbalance sheet location and fair value of our term loan borrowings. The termderivative instruments that were not designated as hedging instruments as of these swap contracts, which were settled monthly, expired in October 2016. Additionally, in June 2015 we entered into various interest rate swap contracts to fix the interest rate on $187.5 million of our Nordea Q5000 Loan borrowings (Note 6). These swap contracts, which are settled monthly, began in June 2015 and extend through April 2020. Our interest rate swap contracts qualify for cash flow hedge accounting treatment. The amount of ineffectiveness associated with our interest rate swap contracts was immaterial for all periods presented.December 31, 2019 (in thousands):
| | | | | | | | | | | |
| 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 Accumulatedaccumulated OCI (net of tax) and our consolidated statements of operations (in thousands). We estimate that as of December 31, 2017, $4.7 million of net losses in Accumulated OCI associated with our derivative instruments is expected to be reclassified into earnings within the next 12 months.:
| | | | Gain (Loss) Recognized in OCI on Derivative Instruments, Net of Tax (Effective Portion) | | Unrealized Gain (Loss) Recognized in OCI |
| | Year Ended December 31, | | Year Ended December 31, |
| | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | |
| Foreign exchange contracts | $ | 9,732 |
| | $ | 9,397 |
| | $ | 4,734 |
| Foreign exchange contracts | $ | (54) | | | $ | (315) | | | $ | (1,453) | |
| Interest rate swaps | 782 |
| | 473 |
| | (534 | ) | Interest rate swaps | (41) | | | (365) | | | 606 | |
| | $ | 10,514 |
| | $ | 9,870 |
| | $ | 4,200 |
| | $ | (95) | | | $ | (680) | | | $ | (847) | |
| | | | Location of Loss Reclassified from Accumulated OCI into Earnings | | Loss Reclassified from Accumulated OCI into Earnings (Effective Portion) | | 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, |
| | | 2017 | | 2016 | | 2015 | | 2020 | | 2019 | | 2018 |
| | | | | | | | | | | | | | | |
| Foreign exchange contracts | Cost of sales | | $ | (12,300 | ) | | $ | (10,827 | ) | | $ | (11,516 | ) | Foreign exchange contracts | Cost of sales | | $ | (455) | | | $ | (6,125) | | | $ | (7,709) | |
| Interest rate swaps | Net interest expense | | (615 | ) | | (2,024 | ) | | (2,143 | ) | Interest rate swaps | Net interest expense | | 3 | | | 655 | | | 508 | |
| | | $ | (12,915 | ) | | $ | (12,851 | ) | | $ | (13,659 | ) | | $ | (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 on Derivative Instruments | | Gain (Loss) Recognized in Earnings on Derivative Instruments |
| | | Year Ended December 31, |
| | | 2017 | | 2016 | | 2015 |
| | | | | | | | |
| Foreign exchange contracts | Other income (expense), net | | $ | 818 |
| | $ | 1,198 |
| | $ | (18,014 | ) |
| | | | $ | 818 |
| | $ | 1,198 |
| | $ | (18,014 | ) |
Note 1822 — Quarterly Financial Information (Unaudited)
OffshoreIn 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 as well as the timing of capital expenditures by oil and gas companies.conditions. Historically, a substantial portion of our services has been performed during the summer and fall months. As a result, historically 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, |
| 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 |
|
|
| | | | | | | | | | | | | | | |
| | Quarter Ended |
| | March 31, | | June 30, | | September 30, | | December 31, |
| 2016 | | | | | | | |
| Net revenues | $ | 91,039 |
| | $ | 107,267 |
| | $ | 161,245 |
| | $ | 128,031 |
|
| Gross profit (loss) | (16,930 | ) | | 5,658 |
| | 40,184 |
| | 17,604 |
|
Net income (loss) (2) | (27,823 | ) | | (10,671 | ) | | 11,462 |
| | (54,413 | ) |
| Basic earnings (loss) per common share | $ | (0.26 | ) | | $ | (0.10 | ) | | $ | 0.10 |
| | $ | (0.46 | ) |
| Diluted earnings (loss) per common share | $ | (0.26 | ) | | $ | (0.10 | ) | | $ | 0.10 |
| | $ | (0.46 | ) |
| |
(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. |
| |
(2) | Amount in the fourth quarter of 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit (Note 2). |
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, 20172020 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, 2017.2020. 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, 2017,2020, 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, 20172020 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 20172020 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 20182021 Annual Meeting of Shareholders to be held on May 10, 2018.19, 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 20182021 Annual Meeting of Shareholders to be held on May 10, 2018.19, 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 20182021 Annual Meeting of Shareholders to be held on May 10, 2018.19, 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 20182021 Annual Meeting of Shareholders to be held on May 10, 2018.19, 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 20182021 Annual Meeting of Shareholders to be held on May 10, 2018.19, 2021.
PART IV
Item 15. Exhibits Exhibit and Financial Statement Schedules
(1) Financial Statements
The following financial statements included on pages 4946 through 9186 in this Annual Report are for the fiscal year ended December 31, 2017.2020.
•Report of Independent Registered Public Accounting Firm — KPMG
•Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — KPMG
Report of Independent Registered Public Accounting Firm — Ernst & Young
Report of Independent Registered Public Accounting Firm — Deloitte & Touche (Deepwater Gateway)
Report of Independent Registered Public Accounting Firm — Deloitte & Touche (Independence Hub)
•Consolidated Balance Sheets as of December 31, 20172020 and 20162019
•Consolidated Statements of Operations for the Years Ended December 31, 2017, 20162020, 2019 and 20152018
•Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2017, 20162020, 2019 and 20152018
•Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2017, 20162020, 2019 and 20152018
•Consolidated Statements of Cash Flows for the Years Ended December 31, 2017, 20162020, 2019 and 20152018
•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 | | | | |
|
| 4.6 | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
4.5 | | | | |
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 | | | | |
4.154.16 | | | | |
4.164.17 | | | | |
4.174.18 | | | | |
4.184.19 | | | | |
|
| 4.20 | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
4.19 | | | | |
4.204.21 | | | | |
| 4.22 | | Amendment No. 2 to Amended and Restated Credit Agreement, dated as of June 28, 2019, by and among Helix Energy Solutions Group, Inc., as borrower, the guarantors listed therein, and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto. | | |
| 4.23 | | | | |
| 4.24 | | | | |
4.214.25 | | | | |
| | | | | | | | | | | | | | |
| Exhibit Number | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 4.26 | | | | |
4.224.27 | | | | |
| 4.28 | | | | |
| 4.29 | | | | |
| 4.30 | | | | |
| 10.1 * | | | | |
| 10.2 * | | | | |
| 10.3 * | | | | |
10.4 * | | | | |
10.5 * | | | | |
10.6 * | | | | |
10.710.4 * | | | | |
10.8 * | | | | |
10.9 * | | | | |
10.1010.5 * | | | | |
| 10.6 * | | | | |
| 10.7 * | | | | |
10.1110.8 * | | | | |
10.12 * | | | | |
10.1310.9 * | | | | |
|
| 10.10 * | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
10.1410.11 * | | | | |
10.1510.12 * | | | | |
10.1610.13 * | | | | |
10.17 * | | | | |
| | | | | | | | | | | | | | |
10.18Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
| 10.14 * | | | | |
10.1910.15 * | | | | |
| 10.16 * | | | | |
10.2010.17 * | | | | |
10.2110.18 * | | | | |
| 10.19 * | | | | |
10.2210.20 | | | | |
10.23 | | | | |
10.2410.21 | | | | |
10.25 | | Form of Indemnification Agreement, by and among Talos Production LLC, Energy Resource Technology GOM, LLC, CKB Petroleum,, Wells Fargo Securities, LLC and Helix Energy Solutions Group, Inc.Merrill Lynch, Pierce, Fenner & Smith Incorporated. | | |
10.26 | | | | |
10.27 | | | | |
10.28 | | | | |
10.2910.22 | | | | |
| 10.23 | | | | |
10.3010.24 | | | | |
|
| 10.25 | | | | |
Exhibits | | Description | | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number) |
10.31 | | | | |
10.3210.26 | | | | |
10.3310.27 | | | | |
| 14.1 | | | | |
16.1 | | | | |
| 21.1 | | | | |
| 23.1 | | | | |
23.231.1 | | | | |
23.3 | | | | |
23.4 | | | | |
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 | |
| | SeniorExecutive Vice President and | |
| | Chief Financial Officer | |
February 23, 201825, 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 23, 2018 |
Owen Kratz | | | |
| | | | |
/s/ ERIK STAFFELDT | | Senior Vice President and Chief Financial Officer
(principal financial officer and
principal accounting officer)
| | February 23, 2018 |
Erik Staffeldt | | | |
| | | | |
| /s/ JOHN V. LOVOI | | Director | | February 23, 201825, 2021 |
| John V. Lovoi | | | |
| | | | |
/s/ NANCY K. QUINNAMY H. NELSON | | Director | | February 23, 201825, 2021 |
Nancy K. QuinnAmy H. Nelson | | | |
| | | | |
| /s/ JAN A. RASK | | Director | | February 23, 201825, 2021 |
| Jan A. Rask | | | |
| | | | |
| /s/ WILLIAM L. TRANSIER | | Director | | February 23, 201825, 2021 |
| William L. Transier | | | |
| | | | |
| /s/ JAMES A. WATT | | Director | | February 23, 201825, 2021 |
| James A. Watt | | | |
