10-K 1 hlx12312016-10k.htm HELIX ENERGY SOLUTIONS GROUP, INC. - 2016 FORM 10-K

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

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

For the fiscal year ended December 31, 2016
OR

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

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

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

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

Title of each class |  | Name of each exchange on which registered
Common Stock (no par value) |  | 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, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer þ | Accelerated filer ¨ | Non-accelerated filer ¨ | Smaller reporting company ¨
|  | (Do not check if a smaller reporting company) |

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 price of the Registrant’s Common Stock on June 30, 2016 was approximately $707.1 million.
The number of shares of the registrant’s Common Stock outstanding as of February 21, 2017 was 147,660,932.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 11, 2017 are incorporated by reference into Part III hereof.

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

|  | Page
PART I
Item 1. | Business | 4
Item 1A. | Risk Factors | 16
Item 1B. | Unresolved Staff Comments | 23
Item 2. | Properties | 23
Item 3. | Legal Proceedings | 25
Item 4. | Mine Safety Disclosures | 26
Unnumbered Item | Executive Officers of the Company | 26
PART II
Item 5. | Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities | 27
Item 6. | Selected Financial Data | 29
Item 7. | Management’s Discussion and Analysis of Financial Condition and Results of Operations | 32
Item 7A. | Quantitative and Qualitative Disclosures About Market Risk | 48
Item 8. | Financial Statements and Supplementary Data | 49
| Report of Independent Registered Public Accounting Firm — KPMG | 49
| Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting — KPMG | 50
| Report of Independent Registered Public Accounting Firm — Ernst & Young | 51
| Report of Independent Registered Public Accounting Firm — Deloitte & Touche (Deepwater Gateway) | 52
| Report of Independent Registered Public Accounting Firm — Deloitte & Touche (Independence Hub) | 53
| Consolidated Balance Sheets as of December 31, 2016 and 2015 | 54
| Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014 | 55
| Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2016, 2015 and 2014 | 56
| Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014 | 57
| Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014 | 58
| Notes to Consolidated Financial Statements | 59
Item 9. | Changes in and Disagreements with Accountants on Accounting and Financial Disclosure | 95
Item 9A. | Controls and Procedures | 95
Item 9B. | Other Information | 95
PART III
Item 10. | Directors, Executive Officers and Corporate Governance | 96
Item 11. | Executive Compensation | 96
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters | 96
Item 13. | Certain Relationships and Related Transactions, and Director Independence | 96
Item 14. | Principal Accounting Fees and Services | 96
PART IV
Item 15. | Exhibits, Financial Statement Schedules | 97
Item 16. | Form 10-K Summary | 97
| Signatures | 98
| Index to Exhibits | 99

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Forward Looking Statements
This Annual Report on Form 10-K (“Annual Report”) contains various statements that contain forward-looking information regarding Helix Energy Solutions Group, Inc. and represent our expectations and beliefs concerning 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, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements included herein or incorporated herein by reference 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,” “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. Included in forward-looking statements are, among other things:

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

• | statements regarding the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of our Q7000 vessel and the construction of the Siem Helix 2 chartered vessel to be used in connection with our contracts to provide well intervention services offshore Brazil (Note 14);

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

• | statements regarding our backlog and long-term contracts;

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

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

• | statements regarding our trade receivables and their collectability;

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

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

• | statements regarding our ability to retain key members of our senior management and 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 be materially different from those in the forward-looking statements. These factors include:

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

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

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

• | unexpected delays in the delivery or chartering or customer acceptance of new vessels for our well intervention and robotics fleet, including the Q7000, the Grand Canyon III, and the Siem Helix 1 and the Siem Helix 2 to be used to perform contracted well intervention work offshore Brazil;

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

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

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

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

• | the success of our risk management activities;

• | the effects of competition;

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

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• | the impact of current and future laws and governmental regulations, including tax and accounting developments;

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

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

• | the 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 differ materially from those anticipated in any forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors” beginning on page 16 of this Annual Report. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. 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 or provide reasons why actual results may differ.
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 provide services and methodologies that we believe are critical to maximizing production economics. We provide services primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and are expanding our operations offshore Brazil. Our “life of field” services are segregated into three reportable business segments: Well Intervention, Robotics and Production Facilities. For additional information regarding our strategy and business operations, see sections titled “Our Strategy” and “Our Operations” included elsewhere within Item 1. Business of this Annual Report.
Our principal executive offices are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas 77043; our phone number is 281-618-0400. Our common stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “HLX.” Our Chief Executive Officer submitted the annual CEO certification to the NYSE as required under its Listed Company Manual in June 2016. Our principal executive officer and our principal financial officer have made the certifications required under Section 302 of the Sarbanes-Oxley Act, which are included as exhibits to this Annual Report.
Please refer to the subsection “— Certain Definitions” on page 14 for definitions of additional terms commonly used in this Annual Report. Unless otherwise indicated any reference to Notes herein refers to Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data located elsewhere in this Annual Report.
OUR 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. The long-term prospects of our well intervention fleet are enhanced by the delivery of the Siem Helix 1 chartered vessel in June 2016, the delivery of the Siem Helix 2 chartered vessel in February 2017 and the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel which is expected to be in service for us in May 2017, should enable our robotics business to better serve the needs of our customers. It also is beneficial to us from a long-term perspective to have secured our new fixed fee agreement for the Helix Producer I (the “HP I”), a dynamic positioning floating production vessel, to continue to service the Phoenix field for the field operator until at least June 1, 2023.
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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 (“IRS”), which is expected to be completed in the second half of 2017 for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At December 31, 2016, our total investment in the IRS was $6.5 million. In October 2016, we and OneSubsea launched the development of our first Riserless Open-water Abandonment Module (“ROAM”) for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest), almost all of which will be incurred in 2017. The ROAM is expected to be available to customers in the third quarter of 2017.
OUR OPERATIONS
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. We provide a full range of services primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and are expanding our operations offshore Brazil. Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the Gulf of Mexico, North Sea and Brazil. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and the chartered Skandi Constructor, Siem Helix 1 and Siem Helix 2 vessels. We previously owned the Helix 534, which we sold in December 2016. Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and subsea intervention lubricators (“SILs”). Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates three chartered ROV support vessels. Our Production Facilities segment includes the HP I, the Helix Fast Response System (the “HFRS”) and our investment in Independence Hub, LLC (“Independence Hub”), and previously included our former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) that we sold in February 2016. All of our production facilities activities are located in the Gulf of Mexico. See Note 13 for financial results related to our business segments. Our current services include:

• | Production. Well intervention; intervention engineering; production enhancement; inspection, repair and maintenance of production structures, trees, jumpers, risers, pipelines and subsea equipment; and 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 of the services we provide to these alternative energy businesses include subsea power cable installation, trenching and burial, along with seabed coring and preparation for construction of wind turbine foundations.

• | Production facilities. Provision of 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. Currently, the HP I is being utilized to process production from the Phoenix field.

• | Fast Response System. Provision of the HFRS as a response resource that can be identified in permit applications to federal and state agencies and respond in the event of a well control incident.

Well Intervention
We engineer, manage and conduct well construction, intervention and abandonment operations in water depths ranging from 200 to 10,000 feet. As major and independent oil and gas companies conduct operations in the deepwater basins of the world, development of these reserves will often require the installation of subsea trees. Historically, drilling rigs were typically necessary for 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 historically have been less than offshore drilling rigs. 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. These services provide a cost advantage in the development and management of subsea reservoirs. Over time, we expect long-term demand for well intervention services to increase due to the growing number of subsea tree installations and the efficiency gains from specialized intervention assets and equipment.
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In the Gulf of Mexico, our multi-service semi-submersible vessel, the Q4000, has set a series of well intervention “firsts” in increasingly deeper water without the use of a traditional drilling rig. 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. In April 2015, we took delivery of the Q5000, a newbuild semi-submersible well intervention vessel. The Q5000 commenced operations in the Gulf of Mexico during the fourth quarter of 2015. The vessel went on contracted rates in May 2016 under our five-year contract with BP. We previously owned the Helix 534, which we sold in December 2016.
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. The vessel underwent major capital upgrades in 2015 to extend its estimated useful economic life by approximately 15 years. The chartered Skandi Constructor has been performing well intervention services for us in the North Sea since September 2013. In September 2015, we extended the charter through April 1, 2017. The vessel has been stacked at reduced charter rates since November 2015 with the exception of a two-week project during the third quarter of 2016. We currently plan on returning the vessel to its owner when the vessel charter expires on April 1, 2017.
In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000. This contract is for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being built to North Sea standards. This $346 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the terms of this contract and subsequent amendments, 20% of the contract price was paid upon the signing of the contract. The remaining 80% is to be paid in three installments, with 20% in June 2016 (payment was made in October 2016 as agreed between the parties), 20% upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% upon the delivery of the vessel, which at our option can be deferred until December 30, 2018.
In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil, and in connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2. 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 term of the agreements with Petrobras is for four years with Petrobras’s options to extend. As part of Petrobras’s efforts to reduce its costs structure with many of its suppliers, we and Petrobras began discussions in mid-2015 with respect to potentially amending our contracts in a manner that addressed Petrobras’s objectives and was acceptable to us as well. Those negotiations were finalized in early June 2016 such that the contracts for the Siem Helix 1, originally scheduled to begin no later than July 22, 2016, were amended to commence between July 22, 2016 and October 21, 2016, with the day rate reduced to a mutually acceptable level, and the contracts for the Siem Helix 2, originally scheduled to begin no later than January 21, 2017, were amended to commence between October 1, 2017 and December 31, 2017, with no change in the day rate. The Siem Helix 1 is continuing to work through Petrobras’s inspection and acceptance process, including the completion of modifications as agreed between us and Petrobras. Our current expectation is that the vessel will commence operations before the end of the first quarter of 2017. The Siem Helix 2 was delivered to us on February 10, 2017 and is currently undergoing integration and commissioning of our topside equipment onboard. We anticipate that the vessel will commence services for Petrobras in the fourth quarter of 2017.
Robotics
We have been actively engaged in robotics for over three decades. We operate ROVs, trenchers and ROVDrills designed for offshore construction, maintenance and well intervention services. As global marine construction support operates in deeper waters, the use of ROV systems has increased and the scope of ROV services has become essential to deep water operations. Our chartered vessels add value by supporting deployment of our ROVs and trenchers. We provide our customers with vessel availability and schedule flexibility to meet the technological challenges of their subsea activities worldwide. Our robotics assets include 52 ROVs, five trenching systems and two ROVDrills. Our robotics business unit primarily operates in the Gulf of Mexico, North Sea, West Africa and Asia Pacific regions. We currently charter vessels on a long-term basis to support 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 Deep Cygnus, the Grand Canyon and the Grand Canyon II. We also have entered into a long-term charter agreement for the Grand Canyon III, which is scheduled for delivery to us in May 2017. We returned the Rem Installer to its owner as the charter expired in July 2016.
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Over the last decade there has been an increase in offshore activity associated with the growing alternative (renewable) energy industry. Specifically there has been an increase in services performed for the offshore wind farm industry. As the level of activity for offshore alternative energy projects has increased, so has the need for reliable services and related equipment. Historically, this work was performed with the use of barges and other similar vessels, but these types of services are now being contracted to vessels such as our Deep Cygnus and Grand Canyon chartered vessels that are suitable for harsh weather conditions that can occur offshore, especially in northern Europe where offshore wind farming is currently concentrated. In 2016, revenues derived from offshore renewables contracts accounted for 14% of our global robotics revenues. We believe that over the long term our robotics business unit is positioned to continue the services it provides to a range of clients in the alternative 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.
Production Facilities
We own the HP I, a ship-shaped dynamic positioning 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 was previously contracted to process production from the Phoenix field for the field operator until at least December 31, 2017, and in July 2016 we entered into a new fixed fee agreement for the HP I with the same operator, effective June 1, 2016, for service to the Phoenix field until 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 previously owned a 50% interest in Deepwater Gateway, which owns the Marco Polo TLP located in 4,300 feet of water in the Gulf of Mexico. In February 2016, we sold our ownership interest in Deepwater Gateway for $25 million.
We developed the HFRS 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, the HP I and the Q4000, both of which played a key role in the Macondo well control and containment efforts and are currently operating in the Gulf of Mexico. In 2011, we signed an agreement with Clean Gulf Associates (“CGA”), a non-profit industry group, allowing, in exchange for a retainer fee, the HFRS to be named as a response resource in permit applications to federal and state agencies and making the HFRS available to certain CGA participants who executed utilization agreements with us that specified the day rates to be charged should the HFRS be deployed in connection with a well control incident. The original set of agreements expired on March 31, 2013, and we entered into a new set of substantially similar agreements, effective April 1, 2013, with the operators who formed HWCG LLC, a Delaware limited liability company comprised of some of the original CGA members as well as other industry participants, to perform the same functions as CGA with respect to the HFRS. In March 2015, HWCG LLC exercised an option to extend the agreement with us through March 31, 2018.
GEOGRAPHIC AREAS
We primarily operate in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions. We are also expanding our operations offshore Brazil. See Note 13 for revenues as well as property and equipment, net of accumulated depreciation, by geographic areas.
CUSTOMERS
Our customers include major and independent oil and gas producers and suppliers, pipeline transmission companies, alternative (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, customers that account for a significant portion of revenues in one fiscal year may represent an immaterial portion of revenues in subsequent fiscal years. The percent of consolidated revenues from major customers, those whose total represented 10% or more of our consolidated revenues is as follows: 2016 — BP (17%) and Shell (11%), 2015 — Shell (16%) and Talos (11%) and 2014 — Anadarko (13%). We provided services to over 45 customers in 2016.
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COMPETITION
The oilfield services industry is highly competitive. While price is a factor, the ability to access specialized vessels, attract and retain skilled personnel, and demonstrate a good safety record is also important. Our principal competitors in the well intervention business include Island Offshore and international drilling contractors. Our principal competitors in the robotics business include C-Innovation, LLC, DeepOcean Group, DOF Subsea Group, Fugro N.V. and Oceaneering International, Inc. Our competitors may have significantly more financial, personnel, technological and other resources available to them.
TRAINING, SAFETY, HEALTH, ENVIRONMENT AND QUALITY ASSURANCE
Our corporate vision is based on the belief that all incidents should be preventable. Helix strives to achieve this by focusing on controlling major hazard risks and managing behavior. We have established a corporate culture in which QHSE has equal priority to 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.
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 ocean 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.
The management systems of our well intervention and robotics business units have been independently assessed and registered compliant to ISO 9001 (Quality Management Systems) and ISO 14001 (Environmental Management Systems). All of our safety management systems are created in accordance with and conform to OHSAS 18001.
GOVERNMENT REGULATION
Overview
Many aspects of the offshore marine construction industry are subject to extensive governmental regulations. We are subject to the jurisdiction of the U.S. Coast Guard (the “Coast Guard”), the U.S. Environmental Protection Agency (the “EPA”), three divisions of the U.S. Department of the Interior, the Bureau of Ocean Energy Management (the “BOEM”), the Bureau of Safety and Environmental Enforcement (the “BSEE”), and the Office of Natural Resource Revenue (the “ONRR”), 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.
In the North Sea, international regulations govern working hours and a specified 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, we also note that the U.K.’s 2016 decision to exit from the EU may result in the imposition of new laws, rules or regulations affecting operations inside U.K. territorial waters.
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Coast Guard
The Coast Guard sets safety standards and is authorized to investigate vessel 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 are required by various governmental and quasi-governmental agencies to obtain various permits, licenses and certificates with respect to our operations.
BOEM and BSEE
The development and operation of oil and gas properties located on the Outer Continental Shelf (“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.
On April 17, 2015, the BSEE announced its new proposed blowout preventer and well control requirements rule for the OCS federal waters, 30 C.F.R. Part 250. Several years in the making, the proposed rule aims to enhance well control and equipment reliability, and includes a suite of reforms in well design, well control, casing, cementing, real-time well monitoring, and subsea containment.
Finalization of the “Well Control Rule” in 2016 resulted in reforms that establish (phased in over time) 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 a 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 by regulation 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 ROV tooling used on offshore subsea systems are to be held to the industry standards incorporated in API 17H, First Edition.
The Jones Act (Coastwise Trade Rules)
We are also subject to the Merchant Marine Act (commonly known as “the Jones Act”), which regulates the kind of vessels that can carry goods between ports of the U.S. and which has been applied to offshore oil and gas work in the U.S. The Jones Act is interpreted in large part 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.
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In January 2017, the CBP and its parent agency, the Department of Homeland Security (the “DHS”), initiated a proposed modification and revocation of certain letter rulings previously issued by the CBP, subject to public comment by April 18, 2017. The proposed rulemaking would largely reverse the holdings of years of letter rulings from the CBP regarding the application of the Jones Act to offshore oil and gas work. The ramifications of the proposed modification and revocation of prior letter rulings is currently uncertain; however if such proposal is adopted, this development could potentially make it more difficult and/or costly to perform our offshore services in the U.S. Gulf of Mexico.
Other Federal and State Regulatory Agencies
Additional proposals and proceedings before various federal and state regulatory agencies and the courts could affect the oil and gas industry. We cannot predict when or whether any such proposals may become effective.
These regulatory developments and legislative initiatives may curtail production and demand for fossil fuels such as oil and natural gas in areas of the world where our customers operate and thus adversely affect future demand for our services, which may in turn adversely affect our future results of operations.
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 failure to comply.
Under these laws and regulations, we may be liable for remediation or removal costs, damages 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 such acts were performed. Some of the environmental laws and regulations that are applicable to our business operations are discussed in the following paragraphs, but the discussion does not cover all environmental laws and regulations that govern our operations.
OPA 90
The Oil Pollution Act of 1990, as amended (“OPA”), imposes a variety of requirements on “Responsible Parties” related to the prevention of oil spills and liability for damages resulting from such spills in waters of the United States. A “Responsible Party” includes the owner or operator of an onshore facility, a vessel or a pipeline, and the lessee or permittee of the area in which an offshore facility is located. OPA imposes liability on each Responsible Party for oil spill removal costs and for other public and private damages from oil spills. Failure to comply with OPA may result in the assessment of civil and criminal penalties. OPA establishes liability limits equal to the greater of $939,800 or $1,100 per gross ton (effective December 21, 2015) for vessels other than tankers. Liability limits are higher for other 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 such vessels. We currently own and operate six vessels over 300 gross tons. We have provided satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels.
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Clean Water Act
The Clean Water Act imposes strict controls on the discharge of pollutants into the navigable waters of the United States 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. Certain state regulations and the general permits issued under the National Pollutant Discharge Elimination System Program 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 with the requirements of the Clean Water Act and state statutes enacted to control water pollution.
Clean Air Act
The U.S. Supreme Court has held that greenhouse gasses are an air pollutant under the federal Clean Air Act 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.
A variety of regulatory developments, proposals or requirements and legislative initiatives have been introduced in the domestic and international regions in which we operate that are focused on restricting the emissions of carbon dioxide, methane and other greenhouse gases. For example, the U.S. Congress has from time to time considered legislation to reduce greenhouse gas emissions, and almost one-half of the states already have taken legal measures to reduce greenhouse gas emissions, primarily through 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.
CERCLA
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”) contains provisions requiring the remediation of releases of hazardous substances into the environment and imposes liability, without regard to fault or the legality of the original conduct, on certain classes of persons including owners and operators of contaminated sites where the release occurred and those companies that transport, dispose of or arrange for 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, as well as other assets we own or operate or that are owned or operated by our customers or our subcontractors.
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OCSLA
The Outer Continental Shelf Lands Act, as amended (“OCSLA”), provides the federal 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 curtailing operations and cancellation of 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. Equally important, since August 2012, the agency has implemented policy guidelines (IPD No. 12-07) under which BSEE will issue incidents of noncompliance directly to contractors for serious violations of BSEE regulations.
MARPOL
The United States is one of approximately 170 member countries to the International Maritime Organization (“IMO”), a specialized agency of the United Nations that 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.
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. 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 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 the environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future. Such environmental liability could substantially reduce our net income and could have a significant impact on our financial ability to carry out our operations.
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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, 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 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, 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).
Our current insurance program was renewed on July 1, 2016 and is valid until June 30, 2018.
We maintain Hull and Increased Value insurance, which provides coverage for physical damage up to an agreed amount for each vessel. The deductibles are $1.0 million on the Q4000, the Q5000, the HP I and the Well Enhancer, and $500,000 on the Seawell. In addition to the primary deductibles, the vessels are subject to an annual aggregate deductible of $5 million. We also carry Protection and Indemnity (“P&I”) insurance, which covers liabilities arising from the operation of the vessels, and General Liability insurance, which covers liabilities arising from construction operations. The deductible on both the P&I and General Liability is $100,000 per occurrence. Onshore employees are covered by Workers’ Compensation. Offshore employees and marine crews are covered by a Maritime Employers Liability (“MEL”) insurance policy, which covers Jones Act exposures, and includes a deductible of $100,000 per occurrence plus a $750,000 annual aggregate deductible. In addition to the liability policies described above, we currently carry various layers of Umbrella Liability for total limits of $500 million in excess of primary limits. Our self-insured retention on our medical and health benefits program for employees is $250,000 per participant.
We also maintain Operator Extra Expense coverage that provides up to $150 million of coverage per each loss occurrence for a well control issue. Separately, we also maintain $500 million of liability insurance and $150 million of oil pollution insurance. For any given oil spill event we have up to $650 million of insurance coverage.
We customarily have agreements with our customers and vendors in which each contracting party is responsible for its respective personnel. Under these agreements we are indemnified against third party claims related to the injury or death of our customers’ or vendors’ personnel, and vice versa. With respect to well work contracted to us, the customer is generally contractually responsible for pollution emanating from the well. We separately maintain additional coverage for an amount up to $100 million that would cover us under certain circumstances against any such third party claims associated with well control events.
We incur workers’ compensation, MEL and other insurance claims in the normal course of business, which we believe are covered by insurance. We analyze each claim for potential exposure and estimate the ultimate liability of each claim. In January 2017, we settled an ongoing claim in an amount that exceeded our deductible and the excess was covered by insurance. We have not incurred any significant losses as a result of claims denied by our insurance carriers. Our services are provided in hazardous environments where accidents involving catastrophic damage or loss of life could occur, and litigation arising from such an event may result in our being named a defendant in lawsuits asserting large claims. Although there can be no assurance the amount of insurance we carry is sufficient to protect us fully in all events, or that such insurance will continue to be available at current levels of cost or coverage, we believe that our insurance protection is adequate for our business operations.
EMPLOYEES
As of December 31, 2016, we had 1,474 employees, of which 574 were salaried personnel. Our U.S. employees do not belong to a union nor are they employed pursuant to a collective bargaining agreement or any similar arrangement. We believe that our overall relationships with our employees are favorable.
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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, 2016, and previous and subsequent copies of our Quarterly Reports on Form 10-Q and any Current Reports on Form 8-K, and any amendments thereto, are or will be available free of charge at our website as soon as reasonably practicable after they are filed with, or furnished to, the Securities and Exchange Commission (“SEC”). In addition, the Investor Relations portion 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 section of our website at www.HelixESG.com.
CERTAIN DEFINITIONS
Defined below are certain terms helpful to understanding our business that are located through this Annual Report:
BOEM: The Bureau of Ocean Energy Management (“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”) is responsible for safety and environmental oversight of offshore oil and gas operations, including permitting and inspections of offshore oil and gas operations. Its functions include the development and enforcement of safety and environmental regulations, permitting offshore exploration, development and production, inspections, offshore regulatory programs, oil spill response and newly formed training and environmental compliance programs.
Deepwater: Water depths exceeding 1,000 feet.
Dynamic Positioning (DP): Computer directed thruster systems that use satellite based positioning and other positioning technologies to ensure the proper counteraction to wind, current and wave forces enabling a vessel to maintain its position without the use of anchors.
DP2: Two DP systems on a single vessel providing the redundancy that allows the vessel to maintain position even with the failure of one DP system.
DP3: Triple-redundant DP control system comprising a triple-redundant controller unit and three identical operator stations. The system has to withstand fire or flood in any one compartment without the system failing. Loss of position should not occur from any single failure, including a completely burnt fire subdivision or flooded watertight compartment.
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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 system can be utilized for wireline intervention, production logging, coiled-tubing operations, well stimulation, and full plug and abandonment operations. The system provides the well control in order to safely access the well bore for these activities.
Life of Field Services: Services performed on offshore facilities, trees and pipelines from the beginning to the end of the economic life of an oil field, including installation, inspection, maintenance, repair, well intervention and abandonment.
QHSE: Quality, Health, Safety and Environmental programs 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 system that enhances well abandonment capacity from a well intervention vessel.
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 coring system developed to take advantage of existing ROV technology. The coring package, deployed with the ROV system, is capable of taking cores from the seafloor in water depths up to 3,000 meters (9,840 feet). Because the ROV system operates from the seafloor there is no need for surface drilling strings and 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 divers working from special chambers for extended periods at a pressure equivalent to the pressure at the work site.
Spot Vessels: Vessels not owned or under long-term charter but contracted on a short-term basis to perform specific projects.
Subsea Intervention Lubricator (SIL): A riserless system that 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 wire line, 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: A subsea robotics system capable of providing post 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 Services: Activities related to well maintenance and production management/enhancement services. Our well intervention operations include the utilization of slickline and electric line services, pumping services, specialized tooling and coiled tubing services.
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Item 1A. Risk Factors
Shareholders should carefully consider the following risk factors in addition to the other information contained herein. We operate globally in challenging and highly competitive markets and thus our business is subject to a variety of risks. The risks and uncertainties described below are not the only ones facing Helix. We are 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 the events described in these risk factors and elsewhere in this Annual Report could have a material adverse effect on our business, results of operations and financial position.
Our business is adversely affected by low oil and gas prices, which occur from time to time in a cyclical oil and gas industry.
Our services are substantially dependent upon the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to make capital expenditures for offshore exploration, development, drilling and production operations. Although our services are used for other operations during the entire life cycle of a well, when industry conditions are unfavorable such as the current environment, oil and gas companies will likely continue to reduce their budgets for expenditures on all types of operations. The level of both capital and operating expenditures generally depend on the prevailing view of future oil and gas prices, which are influenced by numerous factors, including:

• | worldwide economic activity;

• | supply and demand for oil and natural gas, especially in the United States, Europe, China and India;

• | regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;

• | actions taken by the Organization of Petroleum Exporting Countries (“OPEC”);

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

• | the exploration and production of onshore shale oil and natural gas;

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

• | the level of excess production capacity;

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

• | the sale and expiration dates of offshore leases in the United States and overseas;

• | 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;

• | weather conditions and natural disasters;

• | environmental and other governmental regulations; and

• | tax laws, regulations and policies.

A prolonged period of low level of activity by oil and gas operators may continue to adversely affect demand for our services and could lead to an even greater surplus of available vessels and therefore increasingly downward pressure on the rates we can charge in the market for our services. In the short term, our customers, in reaction to negative market conditions, may continue to seek to renegotiate their contracts with us at lower rates, both for existing contracts and when existing contracts expire, to cancel earlier work and shift it to later years, 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 current unfavorable industry environment and the potential decreased demand for our services.
The majority of our current backlog is concentrated in a small number of long-term contracts.
Although historically our service contracts were of relatively short duration, over the last several years we have been entering into longer term contracts, such as the five-year contract with BP for work in the U.S. Gulf of Mexico, the Petrobras contracts for well intervention services offshore Brazil and the seven-year contract for the HP I. As of December 31, 2016, the BP contract, the Petrobras contracts and the contract for the HP I represent
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approximately 90% of our total backlog. Any cancellation, termination or breach of these contracts would have a larger impact on our operating results and our financial condition than shorter term contracts due to the value at risk. The cancellation or termination of, or unwillingness to perform, these contracts 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, and our contracts may be terminated early.
As of December 31, 2016, backlog for our services supported by written agreements or contracts totaled $1.9 billion, of which $429.2 million is expected to be performed in 2017. 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. In addition, our customers may seek to cancel, terminate, suspend or renegotiate our contracts in the event of our customers’ diminished demand for our services due to industry conditions affecting our customers and their own revenues. Some of these contracts provide for a cancellation fee that is substantially less than the expected rates from the contracts. In addition, some of our customers could experience liquidity issues or could otherwise be unable or unwilling to perform under a contract, which could lead a customer to seek to repudiate, cancel or renegotiate the contract. Our inability or the inability of our customers to perform under our or their contractual obligations, or the early cancellation or termination of our contracts by our customers, could have a material adverse effect on our financial position, results of operations and cash flows.
Time chartering of vessels requires us to make ongoing payments regardless of utilization of and revenue generation from those vessels.
Typically, we charter our ROV support vessels under long-term time charter agreements. We also have entered into long-term charter agreements for the Siem Helix 1 and Siem Helix 2 vessels to perform work under the Petrobras contracts. Should our contracts with customers be canceled, terminated or breached and/or 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.
Vessel upgrade, modification, repair and construction projects, and customer contractual acceptance of new vessels, are subject to risks, including delays, cost overruns, and failure to secure or maintain contracts.
The Q7000, our newbuild semi-submersible well intervention vessel, is currently under construction. Additional ROVs and trenchers are also constructed from time to time. Depending on available opportunities and market conditions, vessels may be constructed for our fleet without first obtaining service contracts covering those vessels. Specifically, our Q7000 vessel does not have any contracted backlog. Our failure to secure service contracts for vessels or other assets under construction could adversely affect our financial position, results of operations and cash flows. In addition, we incur significant upgrade, modification, refurbishment and repair expenditures on our fleet from time to time. While some of these projects are planned, some are unplanned. These projects are subject to risks of delay or cost overruns inherent in any large capital project resulting from numerous factors, including:

• | 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;

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• | disputes with shipyards and suppliers; and

• | work stoppages and other labor disputes.

Delays in the delivery of vessels being constructed or undergoing upgrades, modifications, refurbishment, or repair 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, and/or seek delay damages, under applicable late delivery clauses. For instance, the Siem Helix 1 is continuing to work through Petrobras’s inspection and acceptance process, including the completion of modifications as agreed between us and Petrobras. The contracts with Petrobras for our chartered vessels in Brazil have penalty provisions for late delivery of the vessels to Petrobras, which liquidated damages with respect to the Siem Helix 1 are continuing to accrue until the vessel is accepted by Petrobras. These delay penalties escalate and can become significant with an extended delay, and if the vessels are late in delivery to Petrobras beyond a certain date (a year from the latest required contractual delivery date), the contracts also may be terminated by Petrobras. In the event of termination of these and other contracts, we may not be able to secure a replacement contract on favorable terms, if at all.
The estimated capital expenditures for vessel construction, upgrade, modification and refurbishment projects could materially exceed our planned capital expenditures. Moreover, our vessels undergoing upgrades, modifications, refurbishment or repair may not earn a day rate during the period they are out of service. Additionally, as vessels age, they are more likely to be subject to higher maintenance and repair activities and thus suffer lower levels of utilization. Any significant period of unplanned maintenance and repairs related to our vessels could have a material adverse effect on our financial position, results of operations and cash flows.
Our inability or failure to perform operationally under our contracts could 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, design flaws, weather, currents or soil conditions. 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 ultimately Petrobras has the right to terminate should assessed penalties reach a certain amount. Reduced revenues because of our failure to perform operationally could have a material adverse effect on our financial position, results of operations and cash flows.
A sustained period of unfavorable industry conditions could jeopardize our customers’ and other counterparties’ ability to perform their obligations.
Continued uncertain industry conditions could jeopardize the ability of certain of our counterparties to perform their obligations, including our customers, insurers and financial institutions. 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 level of our capital 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.
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We may not be able to compete successfully against current and future competitors.
The oilfield services business in which we operate is highly competitive. An oversupply of offshore drilling rigs coupled with a significant slowdown in industry activities results in increased competition from drilling rigs as well as substantially lower rates on work that is being performed. Several of our competitors are substantially larger and have greater financial and other resources to better withstand a prolonged period of difficult industry conditions. In order to compete for customers, these larger competitors may undercut us substantially by reducing rates to levels we are unable to withstand. If other companies relocate or acquire vessels for operations in the regions in which we operate, levels of competition may increase further and our business could be adversely affected.
Our indebtedness and the terms of our indebtedness could impair our financial condition and our ability to fulfill our debt obligations.
As of December 31, 2016, we had $626 million of consolidated indebtedness outstanding. The level of indebtedness may have an adverse effect on our future operations, including:

• | limiting our ability to refinance maturing debt or to obtain additional financing on satisfactory terms to fund our working capital requirements, capital expenditures, acquisitions, investments, debt service requirements and other general corporate requirements;

• | increasing our vulnerability to a continued general economic downturn, competition and industry conditions, which could place us at a disadvantage compared to our competitors that are less leveraged;

• | increasing our exposure to potential rising interest rates 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.
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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, our financial position, results of operations, liquidity and cash flows could be adversely impacted.
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 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 business typically declines in winter, and bad weather in the Gulf of Mexico or North Sea can adversely affect our operations.
Marine operations conducted in the Gulf of Mexico and North Sea are seasonal and depend, in part, on weather conditions. Historically, we have enjoyed our highest vessel utilization rates during the summer and fall when weather conditions are favorable for offshore exploration, development and construction activities. We typically have experienced our lowest utilization rates in the first quarter. As is common in the industry, we may bear the risk of delays caused by some adverse weather conditions. Accordingly, our results in any one quarter are not necessarily indicative of annual results or continuing trends.
Certain areas in and near the Gulf of Mexico and North Sea experience unfavorable weather conditions including hurricanes and extreme storms on a relatively frequent basis. Substantially all of our facilities and assets offshore and along the Gulf of Mexico and the North Sea are susceptible to damage and/or total loss by these storms. Damage caused by high winds and turbulent seas could potentially cause us to curtail service operations for significant periods of time until damage can be assessed and repaired. Moreover, even if we do not experience direct damage from any of these weather events, we may experience disruptions in our operations because customers may curtail their offshore activities due to damage to their platforms, pipelines and other related facilities.
The operation of marine vessels is risky, and we do not have insurance coverage for all risks.
Vessel-based offshore services involve a high degree of operational risk. Hazards, such as vessels sinking, grounding, colliding and sustaining damage from severe weather conditions, are inherent in marine operations. These hazards can cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage, and suspension of operations. Damage arising from such occurrences may result in lawsuits asserting large claims. Insurance may not be sufficient or effective under all circumstances or against all hazards to which we may be subject. A successful liability claim for which we are not fully insured could have a material adverse effect on our financial condition. Moreover, we cannot assure you 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 requiring broad exclusions for losses due to war risk and terrorist acts, and limitations for wind storm damages. The current insurance on our vessels 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 vessels could have a material adverse effect on us.
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Our customers may be unable or unwilling to indemnify us.
Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they agree to protect and indemnify us for liabilities resulting from various hazards associated with offshore operations. We can provide no assurance, however, that our customers will be willing or financially able to meet these indemnification obligations. Also, we may choose not to enforce these indemnities because of business reasons.
Enhanced regulations for deepwater offshore drilling may reduce the need for our services.
Exploration and development activities and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulations. To conduct deepwater drilling in the U.S. Gulf of Mexico, an operator is required to comply with existing and newly developed regulations and enhanced safety standards. Before drilling may commence, the BSEE conducts many inspections of deepwater drilling operations for compliance with its regulations, including the testing of blowout preventers. Operators also are required to comply with the Safety and Environmental Management System regulations (SEMS) within the deadlines specified by the regulations, and ensure that their contractors have SEMS compliant safety and environmental policies and procedures. Additionally, each operator must demonstrate that it has containment resources that are available promptly in the event of a deepwater blowout, regardless of the company or operator involved. It is expected that the BOEM and the BSEE will continue to issue further regulations regarding deepwater offshore drilling. Our business, a significant portion of which is in the Gulf of Mexico, provides development services to newly drilled wells, and therefore relies heavily on the industry’s drilling of new oil and gas wells. If the issuance of permits is significantly delayed, or if other oil and gas operations are delayed or reduced due to increased costs, demand for our services in the Gulf of Mexico may also decline. Moreover, if our vessels are 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.
We cannot predict with any certainty the substance or effect of any new or additional regulations in the United States or in other areas around the world. If the United States or other countries where our customers operate enact stricter restrictions on offshore drilling or further regulate offshore drilling and thereby increase costs and/or cause delays for our customers, and this results in decreased demand for or profitability of our services, our business, financial condition, results of operations and cash flows could be materially adversely affected.
Government regulations may affect our business operations.
Our business is affected by changes in public policy and by federal, state, local and foreign laws and regulations relating to the offshore oil and gas industry. Offshore oil and gas operations are affected by tax, environmental, safety, labor, cabotage and other laws, by changes in those laws, application or interpretation of existing laws, and changes in related administrative regulations or enforcement priorities. It is also possible that these laws and regulations may in the future add significantly to our operating costs or those of our customers or otherwise directly or indirectly affect our operations. For example, CBP has recently proposed a modification and revocation of prior letter rulings regarding the interpretation of the Jones Act, which proposal is currently in the public comment period. The ramifications of this interpretation of the Jones Act are uncertain. However we believe that, if adopted as proposed, the new interpretation of the Jones Act could adversely impact the operations of non-coastwise qualified vessels working in the U.S. Gulf of Mexico, including the Q5000 and the chartered Grand Canyon II, which currently operate in the area. Industry is challenging the proposal; whether the revised interpretation will be adopted is uncertain.
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 foreign 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, and those permits are subject to revocation, modification and renewal. Government authorities have the power to enforce compliance with their regulations, and violations are subject to fines, injunctions or both. In some cases, those governmental requirements can impose liability for the entire cost of cleanup on any responsible party without regard to negligence or fault and impose liability on us for the conduct of others or conditions others have caused, or for our acts that complied with all applicable requirements when we performed them. It is possible that other developments, such as stricter environmental laws and regulations, and claims for damages to property or persons resulting from our operations, would result in substantial costs and liabilities. Our insurance policies and the contractual indemnity protection we seek to obtain from our customers may not be sufficient or effective to protect us under all circumstances or against all risk involving compliance with environmental laws and regulations.
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Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation 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 the FCPA or other anti-bribery legislation could subject us to civil and criminal penalties, 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 those jurisdictions and the seizure of vessels or other assets.
Our operations outside of the United States subject us to additional 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 foreign 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, increases or decreases 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.
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The loss of the services of one or more of our key employees, or our failure to attract and retain other highly qualified personnel in the future, could disrupt our operations and adversely affect our financial results.
Our industry has lost a significant number of experienced professionals over the years due to its cyclical nature, which is attributable, among other reasons, to the volatility in oil and gas prices. Many companies, including us, have had employee lay-offs 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 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 projects we may have competition for personnel with the requisite skill set, including from drilling companies.
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 aspects of our business. Although we take measures to protect against cybersecurity risks, including unauthorized access to our confidential and proprietary information, our security measures may not be able to detect or prevent every attempted breach. Similar to other companies, we may be subject to cybersecurity breaches caused by, among other things, illegal hacking, computer viruses, ransomware, or acts of vandalism or terrorism. A breach could result in an interruption in our operations, unauthorized publication of our confidential business or proprietary information, unauthorized release of customer or employee data, violation of privacy or other laws, and exposure to litigation. Any such breach could materially harm our business and operating results.
Certain provisions of our corporate documents and Minnesota law may discourage a third party from making a takeover proposal.
We are authorized to fix, without any action by our shareholders, the rights and preferences on up to 5,000,000 shares of preferred stock, including dividend, liquidation and voting rights. In addition, our by-laws divide the 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 require cash payments in the event of a “change of control.” Any or all of the provisions or factors described above may discourage a takeover proposal or tender offer not approved by management and the Board of Directors and could result in shareholders who may wish to participate in such a proposal or tender offer receiving less 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
We own a fleet of five vessels, four IRSs, four SILs, 52 ROVs, five trenchers and two ROVDrills. We also charter six vessels. Currently all of our vessels, both owned and chartered, have DP capabilities specifically designed to meet the needs of our customers’ deepwater activities. Our Seawell and Well Enhancer vessels have built-in saturation diving systems.
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Listing of Vessels and Other Assets Related to Operations (1)

| Flag State |  | Placed in Service (2) |  | Length (Feet) |  | 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
Skandi Constructor (5) | Bahamas |  | 4/2013 |  | 395 |  | — |  | DP3
Q5000 (6) | Bahamas |  | 4/2015 |  | 358 |  | — |  | DP3
Siem Helix 1 (5) | Bahamas |  | 6/2016 |  | 521 |  | — |  | DP3
Siem Helix 2 (5) | Bahamas |  | 2/2017 |  | 521 |  | — |  | DP3
4 IRSs and 4 SILs | — |  | Various |  | — |  | — |  | —
Robotics — |  |  |  |  |  |  |  |  |
52 ROVs, 5 Trenchers and 2 ROVDrills (3), (7) | — |  | Various |  | — |  | — |  | —
Deep Cygnus (5) | Panama |  | 4/2010 |  | 400 |  | — |  | DP2
Grand Canyon (5) | Panama |  | 10/2012 |  | 419 |  | — |  | DP3
Grand Canyon II (5) | Panama |  | 4/2015 |  | 419 |  | — |  | DP3

(1) | Under government regulations and our insurance policies, we are required to maintain our vessels in accordance with standards of seaworthiness and safety set by government regulations and classification organizations. We maintain our fleet to the standards for seaworthiness, safety and health set by the ABS, Bureau Veritas (“BV”), Det Norske Veritas (“DNV”), Lloyds Register of Shipping (“Lloyds”), and the Coast Guard. ABS, BV, DNV and Lloyds are classification societies used by ship owners to certify that their vessels meet certain structural, mechanical and safety equipment standards.

(2) | Represents the date we placed our owned vessels in service (rather than the date of commissioning) or the date the charters for our chartered vessels commenced, as applicable.

(3) | Serves as security for our Credit Agreement described in Note 7.

(4) | Subject to a vessel mortgage securing our MARAD debt described in Note 7.

(5) | Chartered vessel.

(6) | Serves as security for our Nordea Q5000 Loan described in Note 7.

(7) | Average age of our fleet of ROVs, trenchers and ROVDrills is approximately 7.7 years.

We incur routine dry dock, inspection, maintenance and repair costs pursuant to applicable statutory regulations in order to maintain our vessels under the rules of the applicable class society. In addition to complying with these requirements, we have our own vessel maintenance program that we believe permits us to continue to provide our customers with well-maintained, reliable vessels. In the normal course of business, we charter other vessels on a short-term basis, such as tugboats, cargo barges, utility boats and additional robotics support vessels.
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. We previously owned a 50% interest in Deepwater Gateway, which owns the Marco Polo TLP located in the Gulf of Mexico. In February 2016, we sold our ownership interest in Deepwater Gateway for $25 million.
FACILITIES
Our corporate headquarters are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas. We currently lease all of our facilities. The list of our facilities as of December 31, 2016 is as follows:
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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 three 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 |  | 3,168 square feet

Item 3. Legal Proceedings
On July 31, 2015, a purported stockholder, Parviz Izadjoo, filed a class action lawsuit styled Parviz Izadjoo v. Owen Kratz and Helix Energy Solutions Group, Inc. against the Company and Mr. Kratz, our President and Chief Executive Officer, in the United States District Court for the Southern District of Texas on behalf of a putative class of all purchasers of shares of our common stock between October 21, 2014, and July 21, 2015, inclusive (the “Class Period”). The lawsuit asserted violations of Section 10(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and SEC Rule 10b-5 as to both us and Mr. Kratz, and Section 20(a) of the Exchange Act against Mr. Kratz, based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding projections for 2015 dry docks of two of our vessels working in the Gulf of Mexico that allegedly caused the price at which putative class members bought stock during the proposed class period to be artificially inflated. On January 28, 2016, the judge in the case approved a motion for the appointment of lead plaintiff and lead counsel. On March 14, 2016, the plaintiffs filed an amended class action complaint, adding Mr. Tripodo (our Executive Vice President and Chief Financial Officer) and Mr. Chamblee (our former Executive Vice President and Chief Operating Officer) as individual defendants, alleging the same types of claims made in the original complaint (alleged violations during the Class Period of Section 10(b) of the Exchange Act and SEC Rule 10b-5 with respect to all defendants, and Section 20(a) of the Exchange Act against the individual defendants), but asserting that the alleged misrepresentations and omissions in SEC filings and other public disclosures are related to the condition of and repairs to certain equipment aboard the Q4000 vessel. The defendants filed a motion to dismiss on April 28, 2016, and on February 14, 2017, the defendants’ motion to dismiss the complaint was granted. The dismissal was without prejudice, with leave for plaintiff to amend the complaint by no later than March 17, 2017.
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Item 4. Mine Safety Disclosures
Not applicable.
Executive Officers of the Company
The executive officers of Helix are as follows:

Name |  | Age |  | Position
Owen Kratz |  | 62 |  | President, Chief Executive Officer and Chairman of the Board
Anthony Tripodo |  | 64 |  | Executive Vice President, Chief Financial Officer and Director
Scott A. Sparks |  | 42 |  | Executive Vice President and Chief Operating Officer
Alisa B. Johnson |  | 59 |  | Executive Vice President, General Counsel and Corporate Secretary

Owen Kratz is President and Chief Executive Officer of Helix. He was named Executive Chairman in October 2006 and served in that capacity until February 2008 when he resumed the position of President and Chief Executive Officer. He was appointed Chairman in May 1998 and 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 of Helix since 1990. He served as Chief Operating Officer from 1990 through 1997. Mr. Kratz joined Helix in 1984 and held various offshore positions, including saturation diving supervisor, and management responsibility for client relations, marketing and estimating. From 1982 to 1983, Mr. Kratz was the owner of an independent marine construction company operating in the Bay of Campeche. Prior to 1982, he was a superintendent for Santa Fe and various international diving companies, and a diver in the North Sea. From February 2006 to December 2011, Mr. Kratz was a member of the Board of Directors of Cal Dive International, Inc., a once publicly-traded company, which at one time was a subsidiary of Helix. Mr. Kratz has a Bachelor of Science degree from State University of New York (SUNY).
Anthony Tripodo was elected as Executive Vice President and Chief Financial Officer of Helix on June 25, 2008. Mr. Tripodo oversees the finance, treasury, accounting, tax, information technology and corporate planning functions. Mr. Tripodo was elected as a director of Helix in May 2015, and was also a director of Helix from February 2003 until June 2008 when he joined Helix. Prior to joining Helix, Mr. Tripodo was the Executive Vice President and Chief Financial Officer of Tesco Corporation. From 2003 through the end of 2006, he was a Managing Director of Arch Creek Advisors LLC, a Houston based investment banking firm. From 1997 to 2003, Mr. Tripodo was Executive Vice President of Veritas DGC, Inc., an international oilfield service company specializing in geophysical services, including serving as Executive Vice President, Chief Financial Officer and Treasurer of Veritas from 1997 to 2001. Previously, Mr. Tripodo served 16 years in various executive capacities with Baker Hughes, including serving as Chief Financial Officer of both the Baker Performance Chemicals and Baker Oil Tools divisions. Mr. Tripodo also has served as a director of three publicly-traded companies in the oilfield services industry in addition to his current service as a director of Helix. He graduated Summa Cum Laude with a Bachelor of Arts degree from St. Thomas University (Miami).
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, Canyon Offshore, Inc., including as Senior Vice President from 2007 to September 2012. Mr. Sparks has over 26 years of experience and in the subsea industry, including Operations Manager and Vessel Superintendent at Global Marine Systems and BT Marine Systems.
Alisa B. Johnson joined Helix as Senior Vice President, General Counsel and Secretary of Helix in September 2006 and in November 2008 became Executive Vice President, General Counsel and Corporate Secretary of Helix. Ms. Johnson oversees the legal, human resources and contracts and insurance functions. Ms. Johnson has been involved with the energy industry for over 26 years. 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. Prior to that Ms. Johnson was in private law practice. Ms. Johnson received her Bachelor of Arts degree Cum Laude from Rice University and her law degree Cum Laude from the University of Houston.
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PART II
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is traded on the New York Stock Exchange (“NYSE”) under the symbol “HLX.” 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
2015 |  |  |
First Quarter | $ | 21.99 |  |  | $ | 13.06 |
Second Quarter | $ | 17.73 |  |  | $ | 12.45 |
Third Quarter | $ | 13.00 |  |  | $ | 4.57 |
Fourth Quarter | $ | 7.75 |  |  | $ | 4.51 |
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 (1) | $ | 9.82 |  |  | $ | 7.28 |

(1) | Through February 21, 2017

On February 21, 2017, the closing sale price of our common stock on the NYSE was $8.50 per share. As of February 21, 2017, there were 311 registered shareholders and approximately 15,100 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 financing arrangements prohibit the payment of cash dividends on our common stock. See Management’s Discussion and Analysis of Financial Condition and Results of Operations “— Liquidity and Capital Resources.”
Shareholder Return Performance Graph
The following graph compares the cumulative total shareholder return on our common stock for the period since December 31, 2011 to the cumulative total shareholder return for (i) the stocks of 500 large-cap corporations maintained by Standard & Poor’s (“S&P 500”), assuming the reinvestment of dividends; (ii) the Philadelphia Oil Service Sector index (the “OSX”), a price-weighted index of leading oil service companies, assuming the reinvestment of dividends; and (iii) a peer group selected by us (the “Peer Group”) consisting of the following companies: Atwood Oceanics, Inc., Diamond Offshore Drilling, Inc., FMC Technologies, Inc., Forum Energy Technologies, Inc., GulfMark Offshore, Inc., Hornbeck Offshore Services, Inc., McDermott International, Inc., Oceaneering International, Inc., Oil States International, Inc., Rowan Companies plc, TETRA Technologies, Inc., and Tidewater 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, 2016 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, 2011 in our common stock at the closing price on that date price and on December 31, 2011 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 — (44.2)%; the Peer Group — (39.8)%; the OSX — (15.0)%; and S&P 500 — 98.2%. These results are not necessarily indicative of future performance.
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Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group

| As of December 31,
| 2011 |  | 2012 |  | 2013 |  | 2014 |  | 2015 |  | 2016
Helix | $ | 100.0 |  |  | $ | 130.6 |  |  | $ | 146.7 |  |  | $ | 137.3 |  |  | $ | 33.3 |  |  | $ | 55.8 |
Peer Group Index | $ | 100.0 |  |  | $ | 102.8 |  |  | $ | 120.8 |  |  | $ | 89.4 |  |  | $ | 53.9 |  |  | $ | 60.2 |
Oil Service Index | $ | 100.0 |  |  | $ | 101.8 |  |  | $ | 129.9 |  |  | $ | 97.5 |  |  | $ | 72.9 |  |  | $ | 85.0 |
S&P 500 | $ | 100.0 |  |  | $ | 116.0 |  |  | $ | 153.6 |  |  | $ | 174.6 |  |  | $ | 177.0 |  |  | $ | 198.2 |

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, 2016 |  | — |  |  | $ | — |  |  | — |  |  | 2,232,928 |
November 1 to November 30, 2016 |  | — |  |  | — |  |  | — |  |  | 2,232,928 |
December 1 to December 31, 2016 |  | 13,350 |  |  | 11.11 |  |  | — |  |  | 2,327,608 |
|  | 13,350 |  |  | $ | 11.11 |  |  | — |  |  |

(1) | Includes shares forfeited by certain members of our Board of Directors in satisfaction of withholding taxes upon vesting of restricted shares.

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(2) | Under the terms of our stock repurchase program, the issuance of shares to members of our Board of Directors and to certain employees, including shares issued to our employees under the Employee Stock Purchase Plan (the “ESPP”) (Note 12), increases the number of shares available for repurchase. For additional information regarding our stock repurchase program, see Note 10.

(3) | In January 2017, we issued approximately 0.7 million shares of restricted stock to our executive officers, select management employees and certain members of our Board of Directors who have elected to take their quarterly fees in stock in lieu of cash. These issuances increase the number of shares available for repurchase by a corresponding amount (Note 10).

Item 6. Selected Financial Data.
The financial data presented below for each of the five years ended December 31, 2016 should be read in conjunction with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included elsewhere in this Annual Report. In February 2013, we sold our former domestic oil and gas subsidiary, Energy Resource Technology GOM, Inc. (“ERT”), and as a result, the assets and liabilities included in the sale of ERT 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,
| 2016 |  | 2015 |  | 2014 |  | 2013 |  | 2012
| (in thousands, except per share amounts)
Statement of Operations Data: |  |  |  |  |  |  |  |  |
Net revenues | $ | 487,582 |  |  | $ | 695,802 |  |  | $ | 1,107,156 |  |  | $ | 876,561 |  |  | $ | 846,109 |
Gross profit (loss) (1) | 46,516 |  |  | (233,774 | ) |  | 344,036 |  |  | 260,685 |  |  | 49,915 |
Income (loss) from operations (2) | (63,235 | ) |  | (307,360 | ) |  | 261,756 |  |  | 179,034 |  |  | (68,483 | )
Net income (loss) from continuing operations (3) | (81,445 | ) |  | (376,980 | ) |  | 195,550 |  |  | 111,976 |  |  | (66,840 | )
Income from discontinued operations, net of tax (4) | — |  |  | — |  |  | — |  |  | 1,073 |  |  | 23,684 |
Net income (loss), including noncontrolling interests | (81,445 | ) |  | (376,980 | ) |  | 195,550 |  |  | 113,049 |  |  | (43,156 | )
Net income applicable to noncontrolling interests | — |  |  | — |  |  | (503 | ) |  | (3,127 | ) |  | (3,178 | )
Net income (loss) applicable to common shareholders | (81,445 | ) |  | (376,980 | ) |  | 195,047 |  |  | 109,922 |  |  | (46,334 | )
Adjusted EBITDA from continuing operations (5) | 89,544 |  |  | 172,736 |  |  | 378,010 |  |  | 268,311 |  |  | 233,612 |
Basic earnings (loss) per share of common stock: |  |  |  |  |  |  |  |  |
Continuing operations | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |  |  | $ | 1.03 |  |  | $ | (0.67 | )
Discontinued operations | — |  |  | — |  |  | — |  |  | 0.01 |  |  | 0.23 |
Net income (loss) per common share | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |  |  | $ | 1.04 |  |  | $ | (0.44 | )
Diluted earnings (loss) per share of common stock: |  |  |  |  |  |  |  |  |
Continuing operations | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |  |  | $ | 1.03 |  |  | $ | (0.67 | )
Discontinued operations | — |  |  | — |  |  | — |  |  | 0.01 |  |  | 0.23 |
Net income (loss) per common share | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |  |  | $ | 1.04 |  |  | $ | (0.44 | )
Weighted average common shares outstanding: |  |  |  |  |  |  |  |  |
Basic | 111,612 |  |  | 105,416 |  |  | 105,029 |  |  | 105,032 |  |  | 104,449 |
Diluted | 111,612 |  |  | 105,416 |  |  | 105,045 |  |  | 105,184 |  |  | 104,449 |

(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). Amount in 2012 included impairment charges of approximately $177.1 million, including $14.6 million for the Intrepid, $157.8 million for the Caesar and related mobile pipelay equipment, and $4.6 million for well intervention assets associated with our former well intervention business in Australia.

(2) | Amount in 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit (Notes 2 and 6). Amount in 2015 included a $16.4 million goodwill impairment charge related to our U.K. well intervention reporting unit.

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(3) | 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 18).

(4) | Oil and gas property impairment charges and asset retirement obligation overruns totaled $144.3 million in 2012 (including a $138.6 million charge to reduce the value of ERT’s properties to their estimated fair value in connection with the announcement in December 2012 of the sale of ERT).

(5) | 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,
| 2016 |  | 2015 |  | 2014 |  | 2013 |  | 2012
| (in thousands)
Balance Sheet Data: |  |  |  |  |  |  |  |  |
Working capital | $ | 336,387 |  |  | $ | 473,123 |  |  | $ | 468,660 |  |  | $ | 553,427 |  |  | $ | 351,061 |
Total assets (1) (2) | 2,246,941 |  |  | 2,399,959 |  |  | 2,690,179 |  |  | 2,531,934 |  |  | 3,368,537 |
Total debt (2) | 625,967 |  |  | 749,335 |  |  | 540,853 |  |  | 553,806 |  |  | 1,001,185 |
Total controlling interest shareholders’ equity | 1,281,814 |  |  | 1,278,963 |  |  | 1,653,474 |  |  | 1,499,051 |  |  | 1,393,385 |
Noncontrolling interests | — |  |  | — |  |  | — |  |  | 25,059 |  |  | 26,029 |
Total shareholders’ equity | 1,281,814 |  |  | 1,278,963 |  |  | 1,653,474 |  |  | 1,524,110 |  |  | 1,419,414 |

(1) | Amount at December 31, 2012 included assets of discontinued oil and gas operations totaling $900.2 million.

(2) | Prior year amounts reflected the reclassification of debt issuance costs related to recognized debt liabilities from an asset to a direct deduction from the carrying amounts of those debt liabilities.

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, a non-GAAP financial measure that is commonly used but is not a recognized accounting term under U.S. GAAP. We use EBITDA 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 measure of EBITDA provides useful information to the public regarding our 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.
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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 and the unrealized loss on our commodity derivative contracts. In addition, we include realized losses from the cash settlements of our ineffective foreign currency exchange contracts, 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 differently than we do, which may limit their usefulness as comparative measures. Because EBITDA and Adjusted EBITDA are not financial measures calculated in accordance with U.S. GAAP, they should not be considered in isolation or as a substitute for, but instead are supplemental to, income from operations, net income or other income data prepared in accordance with U.S. GAAP. The reconciliation of our net income (loss) from continuing operations to EBITDA from continuing operations and Adjusted EBITDA from continuing operations is as follows:

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014 |  | 2013 |  | 2012
Net income (loss) from continuing operations | $ | (81,445 | ) |  | $ | (376,980 | ) |  | $ | 195,550 |  |  | $ | 111,976 |  |  | $ | (66,840 | )
Adjustments: |  |  |  |  |  |  |  |  |
Income tax provision (benefit) | (12,470 | ) |  | (101,190 | ) |  | 66,971 |  |  | 31,612 |  |  | (59,158 | )
Net interest expense | 31,239 |  |  | 26,914 |  |  | 17,859 |  |  | 32,898 |  |  | 48,160 |
Loss on early extinguishment of long-term debt | 3,540 |  |  | — |  |  | — |  |  | 12,100 |  |  | 17,127 |
Other (income) expense, net (1) | (3,510 | ) |  | 24,310 |  |  | (814 | ) |  | (6 | ) |  | 662 |
Depreciation and amortization | 114,187 |  |  | 120,401 |  |  | 109,345 |  |  | 98,535 |  |  | 97,201 |
Asset impairments (2) | — |  |  | 345,010 |  |  | — |  |  | — |  |  | 177,135 |
Goodwill impairments (3) | 45,107 |  |  | 16,399 |  |  | — |  |  | — |  |  | — |
Losses on equity investments (4) | 1,674 |  |  | 122,765 |  |  | — |  |  | — |  |  | — |
EBITDA from continuing operations | 98,322 |  |  | 177,629 |  |  | 388,911 |  |  | 287,115 |  |  | 214,287 |
Adjustments: |  |  |  |  |  |  |  |  |
Noncontrolling interests | — |  |  | — |  |  | (661 | ) |  | (4,077 | ) |  | (4,128 | )
(Gain) loss on disposition of assets, net | (1,290 | ) |  | (92 | ) |  | (10,240 | ) |  | (14,727 | ) |  | 13,476 |
Unrealized loss on commodity derivative contracts | — |  |  | — |  |  | — |  |  | — |  |  | 9,977 |
Realized losses from cash settlements of ineffective foreign currency exchange contracts | (7,488 | ) |  | (4,801 | ) |  | — |  |  | — |  |  | — |
Adjusted EBITDA from continuing operations | $ | 89,544 |  |  | $ | 172,736 |  |  | $ | 378,010 |  |  | $ | 268,311 |  |  | $ | 233,612 |

(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 18).

(2) | Amount in 2015 reflects asset impairment charges for the Helix 534, the HP I and certain capitalized vessel project costs (Note 4). Amount in 2012 included impairment charges of $14.6 million for the Intrepid, $157.8 million for the Caesar and related mobile pipelay equipment, and $4.6 million for well intervention assets associated with our former well intervention business in Australia.

(3) | Amount in 2016 reflects a goodwill impairment charge related to our robotics reporting unit (Notes 2 and 6). Amount in 2015 reflects a goodwill impairment charge related to our U.K. well intervention reporting unit.

(4) | Amount in 2015 primarily reflects losses from our share of impairment charges that Deepwater Gateway and Independence Hub recorded in December 2015 and the write-offs of the remaining capitalized interest related to these equity investments (Note 5).

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Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis should be read in conjunction with our historical consolidated financial statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. Any reference to Notes in the following management’s discussion and analysis refers to the Notes to Consolidated Financial Statements located in Item 8. Financial Statements and Supplementary Data of this Annual Report. The results of operations reported and summarized below are not necessarily indicative of future operating results. This discussion also contains forward-looking statements that reflect our current views with respect to future events and financial performance. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of certain factors, such as those set forth under Item 1A. Risk Factors and located earlier in this Annual Report.
EXECUTIVE SUMMARY
Our Strategy
We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We believe that focusing on these services 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. The long-term prospects of our well intervention fleet are enhanced by the delivery of the Siem Helix 1 chartered vessel in June 2016, the delivery of the Siem Helix 2 chartered vessel in February 2017 and the completion and delivery of the Q7000, a newbuild semi-submersible vessel, in 2018. Chartering newer vessels with additional capabilities, including the Grand Canyon III chartered vessel which is expected to be in service for us in May 2017, should enable our robotics business to better serve the needs of our customers. It also is beneficial to us from a long-term perspective to have secured our new fixed fee agreement for the Helix Producer I (the “HP I”), a dynamic positioning floating production vessel, to continue to service 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. IRS, which is expected to be completed in the second half of 2017 for a total cost of approximately $28 million (approximately $14 million for our 50% interest). At December 31, 2016, our total investment in the IRS was $6.5 million. In October 2016, we and OneSubsea launched the development of our first ROAM for an estimated cost of approximately $12 million (approximately $6 million for our 50% interest), almost all of which will be incurred in 2017. The ROAM is expected to be available to customers in the third quarter of 2017.
Economic Outlook and Industry Influences
Demand for our services is primarily influenced by the condition of the oil and gas industry, and in particular, the willingness of oil and gas companies to spend on operational activities as well as capital projects. The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by domestic and global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including:

• | worldwide economic activity, including available access to global capital and capital markets;

• | supply and demand for oil and natural gas, especially in the United States, Europe, China and India;

• | regional conflicts and economic and political conditions in the Middle East and other oil-producing regions;

• | actions taken by OPEC;

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

• | the exploration and production of onshore shale oil and natural gas;

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

• | the level of excess production capacity;

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

• | the sale and expiration dates of offshore leases in the United States and overseas;

• | 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;

• | weather conditions and natural disasters;

• | environmental and other governmental regulations; and

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

The significant decline in oil prices since mid-year 2014 and the resulting difficult industry environment has had a significant adverse impact on investments in oil and gas exploration and production. Many oil and gas companies have terminated or not renewed contracts for many of their contracted rigs and have drastically cut investments in exploration and production as well as other operational activities. We expect these challenging industry conditions to continue through 2017 and beyond if oil and gas prices fail to increase to a level conducive to increased activity levels. Increased competition for limited offshore oil and gas projects has driven down rates that drilling rig contractors are charging for their services, which affects all offshore oil and gas services contractors, including us. Increased competition is also expected to affect utilization of our assets. In addition, the current volatile and uncertain macroeconomic conditions in some countries around the world, such as Brazil and more recently 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. We are continuing to monitor the impact of Brexit and any exit agreements as they are negotiated, but the impact from Brexit on our business and operations will depend on the outcome of tariff, tax treaties, trade, regulatory and other negotiations, as well as the impact of Brexit on macroeconomic growth and currency volatility, which are uncertain at this time.
Many oil and gas companies are increasingly focusing 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 when oil and gas companies begin to increase overall spending levels, it will likely be for production activities rather than for exploration projects. Our well intervention and robotics operations are intended to service the life span of an oil and gas field as well as to provide abandonment services at the end of the life of a field as required by governmental regulations. Thus over the longer term, we believe that fundamentals for our business remain favorable as the need for prolongation of well life in oil and gas production is the primary driver of demand for our services.
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: (1) the need to extend the life of subsea wells is significant to the commercial viability of the wells as plug and abandonment 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 one of the first activities to recover, and in a prolonged market downturn are important to the commercial viability of deepwater wells.
At December 31, 2016, we had cash on hand of $356.6 million and $18.9 million available for borrowing under our Revolving Credit Facility. Our capital expenditures for 2017 are currently anticipated to total approximately $200 million. With $96.5 million in net proceeds from two at-the-market (“ATM”) equity offering programs in 2016 and approximately $220 million in net proceeds from the underwritten public equity offering in January 2017 (Note 9), we believe that we have sufficient liquidity without incurring additional indebtedness beyond the availability under the Revolving Credit Facility (Note 7) in 2017.
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Business Activity Summary
We have enhanced our financial position and strengthened our balance sheet with proceeds from the sale of certain non-core business assets, which, together with net proceeds from our equity offerings in 2016 and early 2017 as well as liquidity under our Revolving Credit Facility, allow us to strategically focus on our core well intervention and robotics businesses. Since 2009, we have generated approximately $1.5 billion in pre-tax proceeds from asset sale transactions. These dispositions primarily include approximately $55 million from the sale of individual oil and gas properties, over $500 million from the sale of our stockholdings in Cal Dive International Inc., $25 million from the sale of our former reservoir consulting business, approximately $238 million from the sale of our two remaining pipelay vessels, the Caesar and the Express, and $624 million from the sale of ERT.
Our business activities in 2016 included the following:

• | 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;

• | In February 2016, we sold our ownership interest in Deepwater Gateway to a subsidiary of Genesis Energy, L.P. for $25 million;

• | The Siem Helix 1 vessel was delivered to us and the charter term began in June 2016. The vessel has transited to Brazil after integration and commissioning of our topside equipment onboard, and is continuing to work through Petrobras’s inspection and acceptance process, including the completion of modifications as agreed between us and Petrobras;

• | We returned the Rem Installer, a chartered vessel, to its owner as the charter expired in July 2016; and

• | In December 2016, we sold the Helix 534 vessel to a third party for approximately $2.8 million.

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 are expanding our operations offshore Brazil. 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, 2016, our consolidated backlog that is supported by written agreements or contracts totaled $1.9 billion, of which $429.2 million is expected to be performed in 2017. The substantial majority of our backlog is associated with our Well Intervention business segment. As of December 31, 2016, our well intervention backlog was $1.5 billion, including $337.3 million expected to be performed in 2017. Our five-year contract with BP to provide well intervention services with our Q5000 semi-submersible vessel, our four-year agreements with Petrobras to provide well intervention services offshore Brazil with the Siem Helix 1 and Siem Helix 2 chartered vessels, and our new seven-year fixed fee agreement for the HP I represent approximately 90% of our total backlog. At December 31, 2015, the total backlog associated with our operations was $1.8 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.
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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):
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| 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 accepting 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. 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 accepting work with lower profit margins.
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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 (Notes 2 and 6). 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 12), 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 7). 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 Repurchase 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 7).
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 2016 included net gains totaling $1.3 million associated with our foreign currency exchange contracts, which primarily related to the contracts that were not designated as cash flow hedges (Note 18). 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 million and $(1.2) million, respectively, in the comparable year-over-year periods. These amounts primarily reflect foreign exchange fluctuations in our non-U.S. dollar functional 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.
Other Income – Oil and Gas. Our other income - oil and gas decreased by $2.0 million in 2016 as compared to 2015. The decrease was primarily attributable to the reduction in our overriding royalty income, which was significantly affected by the decline in oil prices and lower volumes.
Income Tax Benefit. Income taxes reflected a benefit of $12.5 million in 2016 as compared to $101.2 million in 2015. This variance is primarily due to the decrease in pre-tax loss for the current year period. The 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 by the earnings mix between our higher and lower tax rate jurisdictions.
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Comparison of Years Ended December 31, 2015 and 2014
The following table details various financial and operational highlights for the periods presented (dollars in thousands):

| Year Ended December 31, |  | Increase/
| 2015 |  | 2014 |  | (Decrease)
Net revenues — |  |  |  |  |
Well Intervention | $ | 373,301 |  |  | $ | 667,849 |  |  | $ | (294,548 | )
Robotics | 301,026 |  |  | 420,224 |  |  | (119,198 | )
Production Facilities | 75,948 |  |  | 93,175 |  |  | (17,227 | )
Other | — |  |  | 358 |  |  | (358 | )
Intercompany elimination | (54,473 | ) |  | (74,450 | ) |  | 19,977 |
| $ | 695,802 |  |  | $ | 1,107,156 |  |  | $ | (411,354 | )
Gross profit — |  |  |  |  |
Well Intervention (1) | $ | (165,049 | ) |  | $ | 219,554 |  |  | $ | (384,603 | )
Robotics | 41,446 |  |  | 86,419 |  |  | (44,973 | )
Production Facilities (1) | (106,112 | ) |  | 41,762 |  |  | (147,874 | )
Corporate and other | (3,961 | ) |  | (2,778 | ) |  | (1,183 | )
Intercompany elimination | (98 | ) |  | (921 | ) |  | 823 |
| $ | (233,774 | ) |  | $ | 344,036 |  |  | $ | (577,810 | )
Gross margin — |  |  |  |  |
Well Intervention | (44 | )% |  | 33 | % |  |
Robotics | 14 | % |  | 21 | % |  |
Production Facilities | (140 | )% |  | 45 | % |  |
Total company | (34 | )% |  | 31 | % |  |
Number of vessels or robotics assets (2) / Utilization (3) |  |  |  |  |
Well Intervention vessels | 6/58% |  |  | 5/88% |  |  |
Robotics assets | 59/57% |  |  | 57/78% |  |  |
Chartered robotics vessels | 4/78% |  |  | 4/85% |  |  |

(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 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):
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| Year Ended December 31, |  | Increase/
| 2015 |  | 2014 |  | (Decrease)
Well Intervention | $ | 22,855 |  |  | $ | 29,875 |  |  | $ | (7,020 | )
Robotics | 31,618 |  |  | 44,575 |  |  | (12,957 | )
| $ | 54,473 |  |  | $ | 74,450 |  |  | $ | (19,977 | )

Net Revenues. Our total net revenues decreased by 37% in 2015 as compared to 2014. In general, decreased revenues for 2015 reflect both the reduced opportunities for work and the acceptance of work at reduced rates for some of our assets following the industry-wide reaction to the substantial decline in oil prices.
Our Well Intervention revenues decreased by 44% in 2015 as compared to 2014 primarily reflecting decreased utilization of our available well intervention vessels due to lack of work, idle days associated with the dry docks for the Q4000 and the Helix 534, and the Seawell being out of service in 2015 undergoing certain capital upgrades to extend its estimated useful life and being stacked after those life extension activities were completed in September 2015. In the North Sea, the Skandi Constructor was 56% utilized during 2015. The vessel was idle for the majority of the first four months of 2015 and had been stacked since November 2015 at reduced charter rates. The vessel was 88% utilized during 2014, including the 29 idle days associated with the vessel being in regulatory dry dock during the fourth quarter of 2014. The Well Enhancer was 89% utilized during 2015 as compared to 87% utilized during 2014, including the 24 idle days associated with the vessel being in regulatory dry dock in January 2014. In the Gulf of Mexico, we attempted to arrange replacement projects to fill the 150-day void in the Helix 534’s schedule caused by a contract cancellation (for which we received a termination fee of $11.6 million). We were successful in filling all but 26 days in the first quarter of 2015 but were only able to secure 50 days of utilization for the vessel in the second quarter of 2015. The Helix 534 commenced its regularly scheduled regulatory dry dock in September 2015. The vessel was stacked and out of service following the completion of its dry dock in November 2015 due to low levels of activity. The Helix 534 was 83% utilized during 2014 with 53 idle days during the fourth quarter of 2014, including 14 days for required annual inspections and 39 days following the cancellation of a contract. The Q4000 was 71% utilized during 2015 as compared to being 91% utilized during 2014. Idle time for the Q4000 included 64 days in the second quarter of 2015 for its scheduled dry dock. The Q5000 joined our well intervention fleet in the Gulf of Mexico in October 2015 following completion of certain modifications and upgrades necessary for its operations for BP in the Gulf of Mexico. The Q5000 was utilized for 58 days during the fourth quarter of 2015.
Our Robotics revenues decreased by 28% in 2015 as compared to 2014. The decrease primarily reflects lower utilization of our Robotics assets, accepting work at generally reduced rates, and 442 fewer days of spot vessel utilization. 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 in the fourth quarter of 2015 reflecting the end of a long-term project offshore India and a reduction in near term work opportunities as a result of further market deterioration in the offshore energy industry.
Our Production Facilities revenues decreased by 18% in 2015 as compared to 2014, which reflects the decrease in our variable throughput fee as a result of both the decline in oil prices and lower production volumes. The decrease in production volumes reflects natural declines in subsea reservoirs and the Phoenix field being shut in for the majority of March 2015 for some development activities within the field and during which time the HP I underwent required maintenance.
Gross Profit. Excluding the impact of impairment charges related to the Helix 534 and HP I vessels and certain capitalized vessel project costs (Note 4), our gross profit decreased by 68% as compared to 2014. Excluding the $211.6 million impairment charges related to the Helix 534 and certain capitalized vessel project costs, the gross profit related to our Well Intervention segment decreased by 79% in 2015 as compared to 2014 reflecting reduced revenues as a result of the Q4000, the Seawell and the Helix 534 being idle while undergoing their respective regulatory dry dock inspections and repairs during 2015, and our vessels operating under reduced rates or being idle for considerable periods of time during 2015 due to lack of available projects as a result of the ongoing industry downturn.
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The gross profit associated with our Robotics segment decreased by 52% in 2015 as compared to 2014 primarily reflecting decreased utilization for our Robotics assets, less spot work in 2015 and reduced profit margins on any newly awarded work.
Excluding the $133.4 million impairment charge for the HP I, the gross profit related to our Production Facilities segment decreased by 35% in 2015 as compared to 2014. The decrease primarily reflects the decrease in revenues associated with our variable throughput fee, which was adversely affected by the decrease in oil prices and lower production volumes from the Phoenix field.
Goodwill Impairment. 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 (Notes 2 and 6).
Gain on Disposition of Assets, Net. The $10.2 million net gain on disposition of assets in 2014 primarily reflects a $10.5 million gain associated with the sale of our Ingleside spoolbase in January 2014 (Note 4).
Selling, General and Administrative Expenses. Our selling, general and administrative expenses decreased by $35.2 million in 2015 as compared to 2014. The decrease was primarily attributable to a reduction in payroll-related costs including costs associated with our variable performance-based incentive compensation programs (Note 12) and overhead cost saving measures including headcount reductions. Our selling, general and administrative expenses as a percentage of net revenues remained consistent in the comparable year-over-year periods.
Equity in Earnings (Losses) of Investments. Equity in earnings (losses) of investments was $(124.3) million in 2015 and $0.9 million in 2014. 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 $26.9 million in 2015 as compared to $17.9 million in 2014 primarily reflecting an increase in interest expense and a decrease in interest income, partially offset by an increase in capitalized interest. The increase in interest expense was associated with the Nordea Q5000 Loan, which was funded in April 2015 (Note 7). Interest income totaled $2.1 million for 2015 as compared to $4.8 million for 2014. The amount of interest income for 2014 included $2.1 million from a U.S. Internal Revenue Service income tax refund (Note 8). Interest on debt used to finance capital projects is capitalized and thus reduces overall interest expense. Capitalized interest totaled $11.0 million for 2015 as compared to $10.4 million for 2014.
Other Income (Expense), Net. We reported other expense, net, of $24.3 million for 2015 as compared to other income, net, of $0.8 million in 2014. 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 (Note 18). Net other income for 2014 included losses of $1.7 million related to our hedge ineffectiveness. Also included in other income (expense), net, were foreign currency transaction gains (losses) of $(1.2) million and $2.5 million, respectively, in the comparable year-over-year periods. These amounts primarily reflect foreign exchange fluctuations in our non-U.S. dollar functional currencies.
Other Income – Oil and Gas. Our other income - oil and gas decreased by $12.2 million in 2015 as compared to 2014. The decrease was primarily attributable to a $7.2 million insurance reimbursement in the first quarter of 2014 related to asset retirement work previously performed as well as the decrease in our overriding royalty interests. The reduction in our overriding royalty income reflects the decline in oil prices and lower production volumes as previously discussed.
Income Tax Provision (Benefit). Income taxes reflected a benefit of $101.2 million in 2015 as compared to a provision of $67.0 million in 2014. The variance primarily reflected decreased profitability in 2015 as compared to 2014. The effective tax rate was 21.2% for 2015 as compared to 25.5% for 2014. The variance was primarily attributable to the earnings mix between our higher and lower tax rate jurisdictions.
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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,
| 2016 |  | 2015
Net working capital | $ | 336,387 |  |  | $ | 473,123 |
Long-term debt (1) | 558,396 |  |  | 677,695 |
Liquidity (2) | 375,504 |  |  | 743,577 |

(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 7 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 the facility. Our liquidity at December 31, 2016 included cash and cash equivalents of $356.6 million (including $150 million of minimum cash balance required by our Credit Agreement) and $18.9 million of available borrowing capacity under our Revolving Credit Facility (Note 7). Our liquidity has subsequently increased by approximately $220 million of net proceeds from our underwritten public equity offering in January 2017. Our liquidity at December 31, 2015 included cash and cash equivalents of $494.2 million and $249.4 million of available borrowing capacity under our Revolving Credit Facility.

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

| December 31,
| 2016 |  | 2015
Term Loan (matures June 2018) | $ | 190,867 |  |  | $ | 253,181 |
Nordea Q5000 Loan (matures April 2020) | 193,879 |  |  | 228,840 |
MARAD Debt (matures February 2027) | 78,221 |  |  | 83,659 |
2022 Notes (mature May 2022) (1) | 105,697 |  |  | — |
2032 Notes (mature March 2032) (2) | 57,303 |  |  | 183,655 |
Total debt | $ | 625,967 |  |  | $ | 749,335 |

(1) | The 2022 Notes will increase to their face amount through accretion of non-cash interest charges through May 1, 2022.

(2) | The 2032 Notes will increase to their face amount through accretion of non-cash interest charges through March 15, 2018, which is the first date on which the holders of the notes 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,
| 2016 |  | 2015 |  | 2014
Cash provided by (used in): |  |  |  |  |
Operating activities | $ | 38,714 |  |  | $ | 110,805 |  |  | $ | 359,485 |
Investing activities | (147,110 | ) |  | (295,719 | ) |  | (335,512 | )
Financing activities | (25,524 | ) |  | 204,625 |  |  | (30,071 | )

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Our current requirements for cash primarily reflect the need to fund capital spending for our current lines of business and to service our debt. Historically, we have funded our capital program with cash flows from operations, borrowings under credit facilities, and project financing, along with other debt and equity alternatives.
As a further response to the industry-wide spending reductions, 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 cancel certain planned capital expenditures. We believe that our cash on hand, internally generated cash flows and available borrowing capacity under our Revolving Credit Facility will be sufficient to fund our operations over at least the next 12 months.
In accordance with our Credit Agreement, the 2022 Notes and the 2032 Notes, the MARAD Debt agreements, and the Nordea Credit Agreement, we are required to comply with certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and a consolidated leverage ratio, 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 5000 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, 2016 and 2015, we were in compliance with all of the covenants in our long-term debt agreements.
A prolonged period of weak industry activity may make it difficult to comply with our covenants and other restrictions in agreements governing our debt. Furthermore, during any period of sustained weak economic activity and reduced EBITDA, our ability to access the full available commitment under our Revolving Credit Facility may be impacted. At December 31, 2016, our available borrowing capacity under our Revolving Credit Facility, based on the leverage ratio covenant, was restricted to $18.9 million, net of $4.1 million of letters of credit issued. We currently have no plans or forecasted requirements to borrow under our Revolving Credit Facility other than for issuances of letters of credit. Our ability to comply with these covenants and other restrictions is affected by economic conditions and other events beyond our control. If we fail to comply with these covenants and other restrictions, that failure could lead to an event of default, the possible acceleration of our repayment of outstanding debt and the exercise of certain remedies by our lenders, including foreclosure against our collateral.
Subject to the terms and restrictions of the Credit Agreement, we may borrow and/or obtain letters of credit up to $400 million under our Revolving Credit Facility. Pursuant to our Credit Agreement, subject to existing lender participation and/or the participation of new lenders, and subject to standard conditions precedent, we may obtain an increase of up to $200 million in aggregate commitments with respect to the Revolving Credit Facility, additional term loans or a combination thereof. See Note 7 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 to our common stock prior to their stated maturity upon certain triggering events specified in the applicable Indenture governing the notes. Beginning on March 15, 2018, the holders of the 2032 Notes may require us to repurchase these notes or we may at our own option elect to repurchase them. To the extent we do not have cash on hand or long-term financing secured to cover the conversion, the 2032 Notes would be classified as current liabilities in our consolidated balance sheet. No conversion triggers were met during the years ended December 31, 2016 and 2015.
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Operating Cash Flows
Total cash flows from operating activities decreased by $72.1 million in 2016 as compared to 2015 primarily reflecting decreases in income from operations and changes in our working capital. Our operating cash flows for 2016 included the receipt of $28.4 million in U.S. and foreign income tax refunds.
Total cash flows from operating activities decreased by $248.7 million in 2015 as compared to 2014 primarily reflecting the significant reduction in our operating results as a result of the industry downturn and changes in our working capital. Our operating cash flows for 2014 included the receipt of $35.2 million in U.S. income tax refund.
Investing Activities
Capital expenditures consist principally of the acquisition, construction, upgrade, modification and refurbishment of long-lived property and equipment such as dynamically positioned vessels, topside equipment and subsea systems. Significant sources (uses) of cash associated with investing activities for the years ended December 31, 2016, 2015 and 2014 are as follows (in thousands):

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Capital expenditures: |  |  |  |  |
Well Intervention | $ | (185,892 | ) |  | $ | (307,879 | ) |  | $ | (283,635 | )
Robotics | (720 | ) |  | (10,700 | ) |  | (51,348 | )
Production Facilities | (74 | ) |  | (1,867 | ) |  | (869 | )
Other | 199 |  |  | 135 |  |  | (1,060 | )
Distributions from equity investments, net (1) | 1,200 |  |  | 7,000 |  |  | 7,911 |
Proceeds from sale of equity investment (2) | 25,000 |  |  | — |  |  | — |
Proceeds from sale of assets (3) | 13,177 |  |  | 17,592 |  |  | 13,574 |
Acquisition of noncontrolling interests (4) | — |  |  | — |  |  | (20,085 | )
Net cash used in investing activities | $ | (147,110 | ) |  | $ | (295,719 | ) |  | $ | (335,512 | )

(1) | Distributions from equity investments are net of undistributed equity earnings from our equity investments. Gross distributions from our equity investments for the years ended December 31, 2016, 2015 and 2014 were $1.2 million, $7.0 million and $8.8 million, respectively (Note 5).

(2) | Amount in 2016 reflects cash received from the sale of our former ownership interest in Deepwater Gateway (Notes 1 and 5)

(3) | Amount in 2016 primarily reflects cash received from the sale of our office and warehouse property located in Aberdeen, Scotland and the sale of the Helix 534 (Note 4). Amounts in 2014 and 2015 primarily reflect cash received from the sale of our Ingleside spoolbase.

(4) | Relates to the acquisition in February 2014 of our former minority partner’s noncontrolling interests in the entity that owns the HP I.

Capital expenditures associated with our business primarily have included payments associated with the construction of our Q5000 and Q7000 vessels (see below), payments in connection with the Seawell life extension activities in 2015, the upgrades and modifications of the Helix 534 in 2014, the investment in the topside well intervention equipment for the Siem Helix 1 and Siem Helix 2 vessels chartered to perform under our agreements with Petrobras (see below), and the acquisition of additional ROVs and trenchers for our robotics business.
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 on May 19, 2016.
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In September 2013, we executed a second contract with the same shipyard in Singapore that constructed the Q5000. This contract is for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being built to North Sea standards. This $346 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the original terms of this contract, 20% of the contract price was paid upon the signing of the contract. In June 2015, we entered into a contract amendment with the shipyard to extend the scheduled delivery of the Q7000 from mid-2016 to July 30, 2017 and to defer certain payment obligations, and in connection with this extension, we agreed to pay the shipyard incremental costs of up to $14.5 million. In December 2015, we entered into a second contract amendment with the shipyard. Pursuant to this amendment, the remaining 80% is to be paid in three installments, with 20% in June 2016 (payment was made in October 2016 as agreed between the parties), 20% upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% upon the delivery of the vessel, which at our option can be deferred until December 30, 2018. Also pursuant to this second amendment, we agreed to reimburse the shipyard for incremental costs in connection with the further deferment of the Q7000’s delivery. At December 31, 2016, our total investment in the Q7000 was $194.6 million, including $69.2 million paid to the shipyard upon signing the contract and the $69.2 million installment payment in October 2016. In 2017, we plan to incur approximately $90 million of costs related to the construction of the Q7000, including the second installment payment of $69.2 million.
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil. The initial term of the agreements with Petrobras is for four years 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 is expected to be in service for Petrobras before the end of the first quarter of 2017, and the Siem Helix 2, which is expected to be in service for Petrobras in the fourth quarter of 2017. We have invested $200.7 million as of December 31, 2016 and plan to invest approximately $75 million in the topside equipment in 2017.
Financing Activities
Cash flows from financing activities consist primarily of proceeds from debt and equity financings and repayments of our long-term debt. Our $250 million Nordea Q5000 Loan was funded in April 2015 at the time the Q5000 vessel was delivered to us. In 2016, we sold 13,018,732 shares of our common stock under two ATM programs for $100 million, which generated net proceeds of $96.5 million. We also issued $125 million of the 2022 Notes. Repayments of our long-term debt increased by $196.8 million in 2016 as compared to 2015 primarily reflecting an additional $17.9 million in repayment of the Nordea Q5000 Loan, an additional $40.2 million in repayment of the Term Loan, and the payments to repurchase $139.9 million in aggregate principal amount of the 2032 Notes including approximately $122 million with proceeds from the issuance of the 2022 Notes.
Outlook
We anticipate that our capital expenditures and deferred dry dock costs for fiscal year 2017 will approximate $200 million. We believe that our cash on hand, including approximately $220 million in net proceeds from the underwritten public equity offering in January 2017, internally generated cash flows and availability under our Revolving Credit Facility if necessary will provide the capital necessary to continue funding our 2017 capital spending. Our estimate of future capital expenditures may change based on various factors. We may seek to reduce the level of our planned capital expenditures given a prolonged industry downturn.
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Contractual Obligations and Commercial Commitments
The following table summarizes our contractual cash obligations as of December 31, 2016 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 | $ | 192,258 |  |  | $ | 25,634 |  |  | $ | 166,624 |  |  | $ | — |  |  | $ | — |
Nordea Q5000 Loan | 196,429 |  |  | 35,715 |  |  | 71,428 |  |  | 89,286 |  |  | — |
MARAD debt | 83,222 |  |  | 6,222 |  |  | 13,390 |  |  | 14,760 |  |  | 48,850 |
2022 Notes (2) | 125,000 |  |  | — |  |  | — |  |  | — |  |  | 125,000 |
2032 Notes (3) | 60,115 |  |  | — |  |  | — |  |  | — |  |  | 60,115 |
Interest related to debt (4) | 117,840 |  |  | 31,182 |  |  | 37,308 |  |  | 21,117 |  |  | 28,233 |
Property and equipment (5) | 270,725 |  |  | 109,745 |  |  | 160,980 |  |  | — |  |  | — |
Operating leases (6) | 836,652 |  |  | 162,234 |  |  | 284,358 |  |  | 220,633 |  |  | 169,427 |
Total cash obligations | $ | 1,882,241 |  |  | $ | 370,732 |  |  | $ | 734,088 |  |  | $ | 345,796 |  |  | $ | 431,625 |

(1) | Excludes unsecured letters of credit outstanding at December 31, 2016 totaling $4.1 million. These letters of credit support various obligations, such as contractual obligations, customs duties, 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 their issuance price on that 30th trading day (i.e., $18.06 per share). At December 31, 2016, the conversion trigger was not met. See Note 7 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 their issuance price on that 30th trading day (i.e., $32.53 per share). At December 31, 2016, 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 7 for additional information.

(4) | Interest payment obligations were calculated using stated coupon rates for fixed rate debt and interest rates applicable at December 31, 2016 for variable rate debt.

(5) | Primarily reflects costs associated with our Q7000 semi-submersible vessel currently under construction and the topside equipment for the Siem Helix 2 chartered vessel (Note 14).

(6) | Operating leases include vessel charters and facility leases. At December 31, 2016, our vessel charter commitments totaled approximately $791.6 million, including the Grand Canyon III that we expect to place in service in May 2017, the Siem Helix 1, which is expected to be in service for Petrobras before the end of the first quarter of 2017, and the Siem Helix 2, which is expected to be in service for Petrobras in the fourth quarter of 2017.

Contingencies
We believe that there are currently no contingencies that would have a material adverse effect on our financial position, results of operations and cash flows.
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CRITICAL ACCOUNTING ESTIMATES AND POLICIES
Our results of operations and financial condition, as reflected in the accompanying consolidated financial statements and related footnotes, are prepared in conformity with accounting principles generally accepted in the United States. As such, we are required to make certain estimates, judgments and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the periods presented. We base our estimates on historical experience, available information and various other assumptions we believe to be reasonable under the circumstances. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We believe that the most critical accounting policies in this regard are those described below. While these issues require us to make judgments that are somewhat subjective, they are generally based on a significant amount of historical data and current market data. See Note 2 for a detailed discussion on the application of our accounting policies.
Revenue Recognition
Revenues from our services are derived from contracts, which are both short-term and long-term in duration. Our long-term contracts are contracts that contain either lump-sum provisions or provisions for specific time, material and equipment charges, which 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. 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.
Property and Equipment
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 whenever changes in facts and circumstances indicate that the carrying amount of the asset or asset group may not be recoverable and may exceed its 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, considering all 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 impairment has occurred, we recognize a loss for the difference between the carrying amount and the fair value of the asset.
See Note 4 for additional information regarding our property and equipment.
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Goodwill and Other Intangible Assets
We are required to perform an impairment analysis of goodwill at least annually or more frequently whenever events or circumstances occur indicating that it might be impaired. We have elected November 1 to be our annual impairment assessment date for goodwill.
Under the first step of the goodwill impairment test, the fair value of each reporting unit is compared to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, goodwill impairment is indicated and a second step is performed to measure the amount of impairment loss. At November 1, 2016, we had one reporting unit with goodwill, our robotics reporting unit. We used both the income approach (discounted cash flow method) and the market approach to estimate the fair value of our reporting units. The fair value of our robotics reporting unit was lower than its carrying amount by approximately 15%. We performed a market capitalization reconciliation by comparing the fair value of equity (fair value of total invested capital less fair value of total debt) to market capitalization, which we used to validate the results of the first step of our goodwill impairment analysis.
Based on the results of the first step, we performed the second step of the impairment test for our robotics reporting unit. There was no implied fair value of goodwill after we allocated the fair value of the reporting unit to all the assets and liabilities as if the reporting unit were acquired in a business combination. We therefore concluded that goodwill of our robotics reporting unit was fully impaired and recorded an impairment charge of $45.1 million.
See Note 6 for additional information regarding our goodwill.
Income Taxes
Deferred 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. 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. We have not provided deferred U.S. income tax on the accumulated earnings and profits from our non-U.S. subsidiaries without operations in the U.S. as we consider them permanently reinvested.
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.
See Note 8 for discussion of net operating loss carry forwards, deferred income taxes and uncertain tax positions taken by us.
Derivative Instruments and Hedging Activities
Our risk management activities involve the use of derivative financial instruments to hedge 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 have entered into certain derivative contracts, including interest rate swaps and foreign currency exchange contracts. All derivative contracts are reflected in our balance sheet at fair value. 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).
See Note 18 for additional information regarding our derivative contracts.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
As of December 31, 2016, we were exposed to market risk in two areas: interest rates and foreign currency exchange rates.
Interest Rate Risk. As of December 31, 2016, $388.7 million of our outstanding debt was subject to floating rates. The interest rate applicable to our variable rate debt may rise, thereby increasing our interest expense and related cash outlay. To reduce the impact of this market risk, in September 2013 we entered into various interest rate swap contracts to fix the interest rate on $148.1 million of our Term Loan debt. The term 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 debt. 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 by 100 basis points for our variable rate long-term debt that is not hedged. Based on this hypothetical assumption, we would have incurred an additional $2.0 million in interest expense for the year ended December 31, 2016.
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 subject to movements in foreign currency exchange rates when transactions are denominated in (i) currencies other than the U.S. dollar, which is our functional currency, or (ii) the functional currency of our subsidiaries, which is not necessarily the U.S. dollar. In order to mitigate the effects of exchange rate risk in areas outside the United States, we generally pay a portion of our expenses in local currencies. In addition, a substantial portion of our contracts provide for collections from customers in U.S. dollars.
Assets and liabilities of our subsidiaries that do not have the U.S. dollar as their functional currency are translated using the exchange rates in effect at the balance sheet date, resulting in translation adjustments that are reflected in “Accumulated other comprehensive loss” (“Accumulated OCI”) in the shareholders’ equity section of our consolidated balance sheets. At December 31, 2016, approximately 15% of our assets are impacted by changes in foreign currencies in relation to the U.S. dollar. We recorded foreign currency translation unrealized losses of $35.9 million, $12.8 million and $19.5 million to Accumulated OCI for the years ended December 31, 2016, 2015 and 2014, respectively. 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. dollar are to be paid or received, the resulting transaction gain or loss is recognized in the consolidated statements of operations as a component of “Other income (expense), net.” For the years ended December 31, 2016, 2015 and 2014, these amounts resulted in gains (losses) of $0.2 million, $(1.2) million and $2.5 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 outflows related to certain vessel charters denominated in Norwegian kroners. In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK591.3 million). 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 ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK594.7 million and NOK595.0 million, respectively), through July 2019 and February 2020, respectively. In December 2015, we re-designated the hedging relationship between a portion of our foreign currency exchange 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 (Note 18). The foreign currency exchange contracts associated with the Grand Canyon charter payments and the re-designated foreign currency exchange contracts associated with the Grand Canyon II and Grand Canyon III charter payments currently qualify for cash flow hedge accounting treatment. For the years ended December 31, 2016, 2015 and 2014, we recorded gains (losses) totaling $0.1 million and $(5.1) million and $(1.7) million, respectively, in “Other income (expense), net” related to foreign currency hedge ineffectiveness.
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Item 8. Financial Statements and Supplementary Data
Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Helix Energy Solutions Group, Inc.:
We have audited the accompanying consolidated balance sheet of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the year ended December 31, 2016. 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 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. 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 provides a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2016, and the results of their operations and their cash flows for the year ended December 31, 2016, in conformity with U.S. generally accepted accounting principles.
As discussed in Note 2 to the consolidated financial statements, the Company changed its accounting method for debt issuance costs effective January 1, 2015 due to the adoption of FASB ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Helix Energy Solutions Group, Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 24, 2017 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.
/s/ KPMG LLP
Houston, Texas
February 24, 2017
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders
Helix Energy Solutions Group, Inc.:
We have audited Helix Energy Solutions Group, Inc.’s internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Helix Energy Solutions Group, Inc.’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 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 effective internal control over financial reporting was maintained in all material respects. Our audit 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.
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.
In our opinion, Helix Energy Solutions Group, Inc. maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheet of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2016, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for the year ended December 31, 2016, and our report dated February 24, 2017 expressed an unqualified opinion on those consolidated financial statements.
/s/ KPMG LLP
Houston, Texas
February 24, 2017
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Report of Independent Registered Public Accounting Firm
The Board of Directors and Shareholders of
Helix Energy Solutions Group, Inc. and subsidiaries
We have audited the accompanying consolidated balance sheet of Helix Energy Solutions Group, Inc. and subsidiaries as of December 31, 2015, and the related consolidated statements of operations, comprehensive income (loss), shareholders’ equity, and cash flows for each of the two years in the period 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 audits. 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 investment in Deepwater Gateway, L.L.C. is stated at approximately $26 million and the Company’s obligation associated with its investment in Independence Hub, LLC is stated at approximately $8 million as of December 31, 2015. 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, as of and for the year ended December 31, 2015, is based solely on the reports of the other auditors.
We conducted our audits 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 audits and the reports of other auditors provide a reasonable basis for our opinion.
In our opinion, based on our audits and the reports of other auditors, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Helix Energy Solutions Group, Inc. and subsidiaries at December 31, 2015, and the consolidated results of their operations and their cash flows for each of the two years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.
/s/ Ernst & Young LLP
Houston, Texas
February 29, 2016
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Management Committee of
Deepwater Gateway, L.L.C.
Houston, Texas
We have audited the balance sheet of Deepwater Gateway, L.L.C. (the “Company”) as of December 31, 2015, and the related statements of operations, cash flows, and members’ equity 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 financial position of Deepwater Gateway, L.L.C. as of December 31, 2015 and the results of its operations and its cash flows 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
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Management Committee of
Independence Hub, LLC
Houston, Texas
We have audited the balance sheet of Independence Hub, LLC (the “Company”) as of December 31, 2015, and the related statements of operations, cash flows, and members’ equity 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 financial position of Independence Hub, LLC as of December 31, 2015 and the results of its operations and its cash flows 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
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(in thousands)

| December 31,
| 2016 |  | 2015
ASSETS
Current assets: |  |  |
Cash and cash equivalents | $ | 356,647 |  |  | $ | 494,192 |
Accounts receivable: |  |  |
Trade, net of allowance for uncollectible accounts of $1,778 and $350, respectively | 101,825 |  |  | 76,287 |
Unbilled revenue and other | 10,328 |  |  | 20,465 |
Current deferred tax assets | 16,594 |  |  | 53,573 |
Other current assets | 37,388 |  |  | 39,518 |
Total current assets | 522,782 |  |  | 684,035 |
Property and equipment | 2,450,890 |  |  | 2,544,857 |
Less accumulated depreciation | (799,280 | ) |  | (941,848 | )
Property and equipment, net | 1,651,610 |  |  | 1,603,009 |
Other assets: |  |  |
Equity investments | — |  |  | 26,200 |
Goodwill | — |  |  | 45,107 |
Other assets, net | 72,549 |  |  | 41,608 |
Total assets | $ | 2,246,941 |  |  | $ | 2,399,959 |
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities: |  |  |
Accounts payable | $ | 60,210 |  |  | $ | 65,370 |
Accrued liabilities | 58,614 |  |  | 71,641 |
Income tax payable | — |  |  | 2,261 |
Current maturities of long-term debt | 67,571 |  |  | 71,640 |
Total current liabilities | 186,395 |  |  | 210,912 |
Long-term debt | 558,396 |  |  | 677,695 |
Deferred tax liabilities | 167,351 |  |  | 180,974 |
Other non-current liabilities | 52,985 |  |  | 51,415 |
Total liabilities | 965,127 |  |  | 1,120,996 |
Commitments and contingencies |  |  |
Shareholders’ equity: |  |  |
Common stock, no par, 240,000 shares authorized, 120,630 and 106,289 shares issued, respectively | 1,055,934 |  |  | 945,565 |
Retained earnings | 322,854 |  |  | 404,299 |
Accumulated other comprehensive loss | (96,974 | ) |  | (70,901 | )
Total shareholders’ equity | 1,281,814 |  |  | 1,278,963 |
Total liabilities and shareholders’ equity | $ | 2,246,941 |  |  | $ | 2,399,959 |

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

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Net revenues | $ | 487,582 |  |  | $ | 695,802 |  |  | $ | 1,107,156 |
Cost of sales: |  |  |  |  |
Cost of sales | 441,066 |  |  | 584,566 |  |  | 763,120 |
Asset impairments | — |  |  | 345,010 |  |  | — |
Total cost of sales | 441,066 |  |  | 929,576 |  |  | 763,120 |
Gross profit (loss) | 46,516 |  |  | (233,774 | ) |  | 344,036 |
Goodwill impairments | (45,107 | ) |  | (16,399 | ) |  | — |
Gain on disposition of assets, net | 1,290 |  |  | 92 |  |  | 10,240 |
Selling, general and administrative expenses | (65,934 | ) |  | (57,279 | ) |  | (92,520 | )
Income (loss) from operations | (63,235 | ) |  | (307,360 | ) |  | 261,756 |
Equity in earnings (losses) of investments | (2,166 | ) |  | (124,345 | ) |  | 879 |
Net interest expense | (31,239 | ) |  | (26,914 | ) |  | (17,859 | )
Loss on repurchase of long-term debt | (3,540 | ) |  | — |  |  | — |
Other income (expense), net | 3,510 |  |  | (24,310 | ) |  | 814 |
Other income – oil and gas | 2,755 |  |  | 4,759 |  |  | 16,931 |
Income (loss) before income taxes | (93,915 | ) |  | (478,170 | ) |  | 262,521 |
Income tax provision (benefit) | (12,470 | ) |  | (101,190 | ) |  | 66,971 |
Net income (loss), including noncontrolling interests | (81,445 | ) |  | (376,980 | ) |  | 195,550 |
Less net income applicable to noncontrolling interests | — |  |  | — |  |  | (503 | )
Net income (loss) applicable to common shareholders | $ | (81,445 | ) |  | $ | (376,980 | ) |  | $ | 195,047 |
Earnings (loss) per share of common stock: |  |  |  |  |
Basic | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |
Diluted | $ | (0.73 | ) |  | $ | (3.58 | ) |  | $ | 1.85 |
Weighted average common shares outstanding: |  |  |  |  |
Basic | 111,612 |  |  | 105,416 |  |  | 105,029 |
Diluted | 111,612 |  |  | 105,416 |  |  | 105,045 |

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

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Net income (loss), including noncontrolling interests | $ | (81,445 | ) |  | $ | (376,980 | ) |  | $ | 195,550 |
Other comprehensive loss, net of tax: |  |  |  |  |
Unrealized gain (loss) on hedges arising during the period | 2,366 |  |  | (25,259 | ) |  | (37,364 | )
Reclassification adjustments for loss on hedges included in net income (loss) | 12,851 |  |  | 13,659 |  |  | 3,365 |
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 | (5,347 | ) |  | (2,214 | ) |  | 11,899 |
Unrealized gain (loss) on hedges, net of tax | 9,870 |  |  | 4,200 |  |  | (22,100 | )
Foreign currency translation loss arising during the period | (33,899 | ) |  | (12,849 | ) |  | (19,464 | )
Reclassification adjustment for net translation gain realized upon liquidation | (2,044 | ) |  | — |  |  | — |
Foreign currency translation loss | (35,943 | ) |  | (12,849 | ) |  | (19,464 | )
Other comprehensive loss, net of tax | (26,073 | ) |  | (8,649 | ) |  | (41,564 | )
Comprehensive income (loss) | (107,518 | ) |  | (385,629 | ) |  | 153,986 |
Less comprehensive income applicable to noncontrolling interests | — |  |  | — |  |  | (503 | )
Comprehensive income (loss) applicable to common shareholders | $ | (107,518 | ) |  | $ | (385,629 | ) |  | $ | 153,483 |

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

| Helix Energy Solutions Group, Inc. Shareholders’ Equity |  |  |  |
| Common Stock |  | Retained Earnings |  | Accumulated Other Comprehensive Income (Loss) |  | Total Controlling Interest Shareholders’ Equity |  | Non- controlling Interests |  | Total Equity
| Shares |  | Amount |  |  |  |  |
Balance, December 31, 2013 | 105,640 |  |  | $ | 933,507 |  |  | $ | 586,232 |  |  | $ | (20,688 | ) |  | $ | 1,499,051 |  |  | $ | 25,059 |  |  | $ | 1,524,110 |
Net income | — |  |  | — |  |  | 195,047 |  |  | — |  |  | 195,047 |  |  | 503 |  |  | 195,550 |
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | (19,464 | ) |  | (19,464 | ) |  | — |  |  | (19,464 | )
Unrealized loss on hedges, net | — |  |  | — |  |  | — |  |  | (22,100 | ) |  | (22,100 | ) |  | — |  |  | (22,100 | )
Distributions to noncontrolling interests | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1,018 | ) |  | (1,018 | )
Acquisition of noncontrolling interests | — |  |  | 2,898 |  |  | — |  |  | — |  |  | 2,898 |  |  | (24,544 | ) |  | (21,646 | )
Stock repurchases | (321 | ) |  | (7,698 | ) |  | — |  |  | — |  |  | (7,698 | ) |  | — |  |  | (7,698 | )
Activity in company stock plans, net and other | 267 |  |  | 3,496 |  |  | — |  |  | — |  |  | 3,496 |  |  | — |  |  | 3,496 |
Share-based compensation | — |  |  | 2,176 |  |  | — |  |  | — |  |  | 2,176 |  |  | — |  |  | 2,176 |
Excess tax from share-based compensation | — |  |  | 68 |  |  | — |  |  | — |  |  | 68 |  |  | — |  |  | 68 |
Balance, December 31, 2014 | 105,586 |  |  | $ | 934,447 |  |  | $ | 781,279 |  |  | $ | (62,252 | ) |  | $ | 1,653,474 |  |  | $ | — |  |  | $ | 1,653,474 |
Net loss | — |  |  | — |  |  | (376,980 | ) |  | — |  |  | (376,980 | ) |  | — |  |  | (376,980 | )
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | (12,849 | ) |  | (12,849 | ) |  | — |  |  | (12,849 | )
Unrealized gain on hedges, net | — |  |  | — |  |  | — |  |  | 4,200 |  |  | 4,200 |  |  | — |  |  | 4,200 |
Activity in company stock plans, net and other | 703 |  |  | 3,443 |  |  | — |  |  | — |  |  | 3,443 |  |  | — |  |  | 3,443 |
Share-based compensation | — |  |  | 5,463 |  |  | — |  |  | — |  |  | 5,463 |  |  | — |  |  | 5,463 |
Cumulative share-based compensation in excess of fair value of modified liability awards | — |  |  | 2,915 |  |  | — |  |  | — |  |  | 2,915 |  |  | — |  |  | 2,915 |
Excess tax from share-based compensation | — |  |  | (703 | ) |  | — |  |  | — |  |  | (703 | ) |  | — |  |  | (703 | )
Balance, December 31, 2015 | 106,289 |  |  | $ | 945,565 |  |  | $ | 404,299 |  |  | $ | (70,901 | ) |  | $ | 1,278,963 |  |  | $ | — |  |  | $ | 1,278,963 |
Net loss | — |  |  | — |  |  | (81,445 | ) |  | — |  |  | (81,445 | ) |  | — |  |  | (81,445 | )
Foreign currency translation adjustments | — |  |  | — |  |  | — |  |  | (35,943 | ) |  | (35,943 | ) |  | — |  |  | (35,943 | )
Unrealized gain on hedges, net | — |  |  | — |  |  | — |  |  | 9,870 |  |  | 9,870 |  |  | — |  |  | 9,870 |
Equity component of debt discount on Convertible Senior Notes due 2022 | — |  |  | 10,719 |  |  | — |  |  | — |  |  | 10,719 |  |  | — |  |  | 10,719 |
Re-acquisition of equity component of debt discount on Convertible Senior Notes due 2032 | — |  |  | (1,625 | ) |  | — |  |  | — |  |  | (1,625 | ) |  | — |  |  | (1,625 | )
Issuance of common stock, net of transaction costs | 13,019 |  |  | 96,547 |  |  | — |  |  | — |  |  | 96,547 |  |  | — |  |  | 96,547 |
Activity in company stock plans, net and other | 1,322 |  |  | 463 |  |  | — |  |  | — |  |  | 463 |  |  | — |  |  | 463 |
Share-based compensation | — |  |  | 5,767 |  |  | — |  |  | — |  |  | 5,767 |  |  | — |  |  | 5,767 |
Cumulative share-based compensation in excess of fair value of modified liability awards | — |  |  | 203 |  |  | — |  |  | — |  |  | 203 |  |  | — |  |  | 203 |
Excess tax from share-based compensation | — |  |  | (1,705 | ) |  | — |  |  | — |  |  | (1,705 | ) |  | — |  |  | (1,705 | )
Balance, December 31, 2016 | 120,630 |  |  | $ | 1,055,934 |  |  | $ | 322,854 |  |  | $ | (96,974 | ) |  | $ | 1,281,814 |  |  | $ | — |  |  | $ | 1,281,814 |

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

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Cash flows from operating activities: |  |  |  |  |
Net income (loss), including noncontrolling interests | $ | (81,445 | ) |  | $ | (376,980 | ) |  | $ | 195,550 |
Adjustments to reconcile net income (loss), including noncontrolling interests, to net cash provided by operating activities: |  |  |  |  |
Depreciation and amortization | 114,187 |  |  | 120,401 |  |  | 109,345 |
Non-cash impairment charges | 45,107 |  |  | 361,409 |  |  | — |
Amortization of debt discount | 5,905 |  |  | 5,957 |  |  | 5,596 |
Amortization of debt issuance costs | 7,733 |  |  | 5,664 |  |  | 4,870 |
Share-based compensation | 5,862 |  |  | 6,543 |  |  | 3,133 |
Excess tax benefit from share-based compensation | — |  |  | — |  |  | (68 | )
Deferred income taxes | 14,849 |  |  | (103,022 | ) |  | 23,154 |
Equity in losses of investments | 2,166 |  |  | 124,345 |  |  | — |
Gain on disposition of assets, net | (1,290 | ) |  | (92 | ) |  | (10,240 | )
Loss on repurchase of long-term debt | 3,540 |  |  | — |  |  | — |
Unrealized losses and ineffectiveness on derivative contracts, net | (8,800 | ) |  | 18,281 |  |  | 1,320 |
Changes in operating assets and liabilities: |  |  |  |  |  |  |  |
Accounts receivable, net | (22,437 | ) |  | 36,354 |  |  | 43,963 |
Other current assets | (2,386 | ) |  | 7,956 |  |  | (6,461 | )
Income tax payable | (4,571 | ) |  | (7,464 | ) |  | 9,088 |
Accounts payable and accrued liabilities | (630 | ) |  | (63,817 | ) |  | 12,841 |
Oil and gas asset retirement costs | — |  |  | — |  |  | (1,024 | )
Other non-current, net | (39,076 | ) |  | (24,730 | ) |  | (31,582 | )
Net cash provided by operating activities | 38,714 |  |  | 110,805 |  |  | 359,485 |
Cash flows from investing activities: |  |  |  |  |  |  |  |
Capital expenditures | (186,487 | ) |  | (320,311 | ) |  | (336,912 | )
Distributions from equity investments, net of earnings | 1,200 |  |  | 7,000 |  |  | 7,911 |
Proceeds from sale of equity investment | 25,000 |  |  | — |  |  | — |
Proceeds from sale of assets | 13,177 |  |  | 17,592 |  |  | 13,574 |
Acquisition of noncontrolling interests | — |  |  | — |  |  | (20,085 | )
Net cash used in investing activities | (147,110 | ) |  | (295,719 | ) |  | (335,512 | )
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 Nordea Q5000 Loan | — |  |  | 250,000 |  |  | — |
Repayment of Nordea Q5000 Loan | (35,714 | ) |  | (17,857 | ) |  | — |
Repayment of Term Loan | (62,742 | ) |  | (22,500 | ) |  | (15,000 | )
Repayment of MARAD Debt | (5,926 | ) |  | (5,644 | ) |  | (5,376 | )
Debt issuance costs | (4,655 | ) |  | (1,737 | ) |  | (3,586 | )
Distributions to noncontrolling interests | — |  |  | — |  |  | (1,018 | )
Net proceeds from issuance of common stock | 96,547 |  |  | — |  |  | — |
Repurchases of common stock | (341 | ) |  | (1,121 | ) |  | (8,382 | )
Excess tax benefit from share-based compensation | — |  |  | — |  |  | 68 |
Proceeds from issuance of ESPP shares | 708 |  |  | 3,484 |  |  | 3,223 |
Net cash provided by (used in) financing activities | (25,524 | ) |  | 204,625 |  |  | (30,071 | )
Effect of exchange rate changes on cash and cash equivalents | (3,625 | ) |  | (2,011 | ) |  | 4,390 |
Net increase (decrease) in cash and cash equivalents | (137,545 | ) |  | 17,700 |  |  | (1,708 | )
Cash and cash equivalents: |  |  |  |  |  |  |  |
Balance, beginning of year | 494,192 |  |  | 476,492 |  |  | 478,200 |
Balance, end of year | $ | 356,647 |  |  | $ | 494,192 |  |  | $ | 476,492 |

The accompanying notes are an integral part of these consolidated financial statements.
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HELIX ENERGY SOLUTIONS GROUP, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 — Organization
Unless the context indicates otherwise, the terms “we,” “us” and “our” in this Annual Report refer collectively to Helix Energy Solutions Group, Inc. and its subsidiaries (“Helix” or the “Company”). We are an international offshore energy services company that provides specialty services to the offshore energy industry, with a focus on well intervention and robotics operations. We provide services primarily in deepwater in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, and are expanding our operations offshore Brazil.
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 three reportable business segments: Well Intervention, Robotics and Production Facilities (Note 13).
Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, North Sea and Brazil. Our Well Intervention segment also 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 chartered Skandi Constructor, Siem Helix 1 and Siem Helix 2 vessels. The Q5000 vessel went on contracted rates in May 2016 under our five-year contract with BP. We currently have another semi-submersible well intervention vessel under construction, the Q7000. The two chartered newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2, are to be used in connection with our contracts to provide well intervention services offshore Brazil. We previously also owned the Helix 534, which we sold in December 2016 (Note 4).
Our Robotics segment includes remotely operated vehicles (“ROVs”), trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates three chartered ROV support vessels following the expiration of the Rem Installer charter in July 2016. Another chartered ROV support vessel, the Grand Canyon III, is expected to be in service for us in May 2017.
Our Production Facilities segment includes the Helix Producer I (the “HP I”), a ship-shaped dynamic positioning floating production vessel, and the Helix Fast Response System (the “HFRS”), which provides certain operators access to our Q4000 and HP I vessels in the event of a well control incident in the Gulf of Mexico. The HP I was previously contracted to process production from the Phoenix field for the field operator until at least December 31, 2017, and in July 2016 we entered into a new fixed fee agreement for the HP I with the same operator, effective June 1, 2016, for service to the Phoenix field until at least June 1, 2023. The HFRS is currently under contract through March 31, 2018. The Production Facilities segment also includes our ownership interest in Independence Hub, LLC (“Independence Hub”) and previously included our former ownership interest in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) that we sold for $25 million in February 2016 (Note 5).
Note 2 — Summary of Significant Accounting Policies
Principles of Consolidation
Our consolidated financial statements include the accounts of majority owned subsidiaries. The equity method is used to account for investments in affiliates in which we do not have majority ownership, but have the ability to exert significant influence. We account for our former ownership interest in Deepwater Gateway and our ownership interest in Independence Hub under the equity method of accounting. Noncontrolling interests represent the minority shareholders’ proportionate share of the equity in Kommandor LLC, a Delaware limited liability company formed for the purpose of converting a ferry vessel into the HP I. In February 2014, we acquired our former minority partner’s noncontrolling interests (approximately 19%) in Kommandor LLC for $20.1 million. The consolidated results of Kommandor LLC are included in our Production Facilities segment. All material intercompany accounts and transactions have been eliminated.
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Basis of Presentation
Our consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles (“U.S. GAAP”). 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.
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.
Accounts and Notes Receivable and Allowance for Uncollectible Accounts
Accounts and notes receivable are stated at the historical carrying amount net of write-offs and allowance for uncollectible accounts. The amount of our net accounts receivable and our note receivable approximates fair value. We establish an allowance for uncollectible accounts based on historical experience as well as any specific collection issues that we have identified. Uncollectible receivables are written off when a settlement is reached for an amount that is less than the outstanding historical balance or when we have determined that the balance will definitively not be collected (Note 16).
Property and Equipment
Property and equipment is recorded at historical cost. Property and equipment is depreciated on a straight line basis over the estimated useful life of each asset. The cost of improvements is capitalized while the cost of repairs and maintenance is charged to expense as incurred. For the years ended December 31, 2016, 2015 and 2014, repair and maintenance expense totaled $25.5 million, $32.8 million and $44.6 million, respectively.
Assets used in operations are assessed for impairment whenever 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. If, upon review, the sum of undiscounted future cash flows expected to be generated by the asset or asset group is less than its carrying amount, an impairment is recorded. The amount of the impairment recorded is calculated as the difference between the carrying amount of the asset or asset group and its estimated fair value. Individual assets are grouped for impairment purposes at the lowest level where there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The expected future cash flows used for impairment reviews and related fair value calculations are based on assessments of operating costs, project margins and capital project decisions, 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.
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Capitalized Interest
Interest from external borrowings is capitalized on major projects until the assets are ready for their intended use. Capitalized interest is added to the cost of the underlying asset and is amortized over the useful life of the asset in the same manner as the underlying asset. Capitalized interest is a component of our net interest expense (Note 7).
Equity Investments
We periodically review our equity investments for impairment. Under 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 an equity investment and reduce our investment balance to zero, we would not record additional losses unless (i) we guaranteed obligations of the investee, (ii) we are otherwise committed to provide further financial support for the investee, or (iii) it is anticipated that the investee’s return to profitability is imminent. If we provided a commitment to fund losses, we would continue to record losses resulting in a negative equity method investment, which is presented as a liability.
Goodwill
We are required to perform an annual impairment analysis of goodwill. We elected November 1 to be our annual impairment assessment date for goodwill. However, we could be required to evaluate the recoverability of goodwill prior to the annual assessment date if we experience disruption to the business, unexpected significant declines in operating results, divestiture of a significant component of the business, emergence of unanticipated competition, loss of key personnel or a sustained decline in market capitalization. At the time of our annual assessment of goodwill on November 1, 2016, we had one reporting unit with goodwill.
We first assess qualitative factors in order to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount, including goodwill. Some of the qualitative factors evaluated include, among other things, the results of the most recent impairment analysis, the most recent operating results of the reporting unit, the current outlook for the reporting unit, and the current conditions of the market in which the reporting unit operates. If the qualitative assessment indicates a potential impairment, we perform the first step of the goodwill impairment analysis as described below. Our policy is to bypass the qualitative assessment at least once every three years and perform the first step of the goodwill impairment analysis. We elected to perform the first step of the goodwill impairment analysis for both 2015 and 2016 in light of the continuation of industry-wide downturn as a result of the substantial decline in oil prices since late 2014.
The goodwill impairment analysis is a two-step process. The first step is to identify whether a potential impairment exists by comparing the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered to have a potential impairment and the second step of the impairment analysis is not necessary. However, if the carrying amount of a reporting unit exceeds its fair value, the second step is performed to determine if goodwill is impaired and to measure the amount of impairment loss to recognize, if any.
The second step compares the implied fair value of goodwill with the carrying amount of goodwill. If the implied fair value of goodwill exceeds the carrying amount, then goodwill is not considered impaired. However, if the carrying amount of goodwill exceeds the implied fair value, an impairment loss is recognized in an amount equal to that excess. The implied fair value of goodwill is determined in the same manner as the amount of goodwill recognized in a business combination (i.e., the fair value of the reporting unit is allocated to all the assets and liabilities, including any unrecognized intangible assets, as if the reporting unit were acquired in a business combination).
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We use both the income approach and the market approach to estimate the fair value of our reporting units under the first step of our goodwill impairment analysis. Under the income approach, a discounted cash flow analysis is performed requiring us to make various judgmental assumptions about future revenue, operating margins, growth rates and discount rates. These judgmental assumptions are based on our budgets, long-term business plans, economic projections, anticipated future cash flows and market place data. Under the market approach, the fair value of each reporting unit is calculated by applying an average peer total invested capital EBITDA (defined as earnings before interest, income taxes and depreciation and amortization) multiple to future forecasted EBITDA for each reporting unit. Judgment is required when selecting peer companies that operate in the same or similar lines of business and are potentially subject to the same economic risks. We also perform a market capitalization reconciliation by comparing the fair value of equity (fair value of total invested capital less fair value of total debt) to market capitalization and evaluate the reasonableness of the implied equity premium.
Our goodwill subject to impairment analysis in 2016 was associated with our Robotics segment. As a result of our 2016 goodwill impairment analysis, we recorded an impairment charge of $45.1 million to write off the goodwill associated with our robotics reporting unit. Our goodwill subject to impairment analysis in 2015 and 2014 was associated with our Well Intervention and Robotics segments. 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 of November 1, 2015, the fair value of our robotics reporting unit exceeded the carrying amount of goodwill based on the first step of the impairment analysis and no impairment was recorded. In 2014, we performed the qualitative assessment as described above and concluded that there was no indication of goodwill impairment. We did not record any amount of goodwill impairment in 2014.
Recertification Costs and Deferred Dry Dock Costs
Our vessels are required by regulation to be periodically recertified. Recertification costs are incurred while a 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 dry dock and related recertification costs over the length of time for which we expect 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 dry dock and related recertification process typically lasts one to two months, a period during which the vessel 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 are capitalized and depreciated over the vessel’s remaining economic useful life.
As of December 31, 2016 and 2015, capitalized deferred dry dock costs included within “Other assets, net” in the accompanying consolidated balance sheets (Note 3) totaled $14.8 million and $19.6 million (net of accumulated amortization of $10.7 million and $18.3 million), respectively. During the years ended December 31, 2016, 2015 and 2014, dry dock amortization expense was $14.0 million, $10.8 million and $14.1 million, respectively.
Revenue Recognition
Revenues from our services are derived from contracts, which are both short-term and long-term in duration. Our long-term services contracts are contracts that contain either lump-sum provisions or provisions for specific time, material and equipment charges, which 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.
Unbilled revenue represents revenue attributable to work completed prior to period end that has not yet been invoiced. All amounts included in unbilled revenue are expected to be billed and collected within one year. However, we also monitor the collectability of our outstanding trade receivables on a continual basis in connection with our evaluation of allowance for doubtful accounts.
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Dayrate 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 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.
Lump Sum Contracts. Revenue on significant lump sum contracts is recognized under the percentage-of-completion method based on the ratio of costs incurred to total estimated costs at completion. In determining whether a contract should be accounted for using the percentage-of-completion method, we consider whether:

• | the customer provides specifications for the provision of services;

• | we can reasonably estimate our progress towards completion and our costs;

• | the contract includes provisions for enforceable rights regarding the goods or services to be provided, consideration to be received, and the manner and terms of payment;

• | the customer can be expected to satisfy its obligations under the contract; and

• | we can be expected to perform our contractual obligations.

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.
Revenue from Royalty Interests
Revenues from royalty interests are recognized according to monthly oil and gas production on an entitlement basis. Revenues for royalty interests are reflected in “Other income - oil and gas” in the accompanying 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 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. At December 31, 2016, we believe that we have appropriately accounted for any unrecognized tax benefits. To the extent we prevail in matters for which a liability for an unrecognized tax benefit is established or are required to pay amounts in excess of the liability, our effective tax rate in a given financial statement period may be affected.
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Share-Based Compensation
Share-based compensation is measured at the grant date based on the estimated fair value of an award. Share-based compensation based solely on service conditions is recognized on a straight-line basis over the vesting period of the related shares. 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 grant date fair value of each share and the number of shares granted and is recognized over the respective vesting periods 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 that are accounted for as equity awards is measured based on the estimated grant date fair value and recognized over the vesting period on a straight-line basis. PSUs that are accounted for as liability awards are measured based on the estimated fair value at the balance sheet date and changes in fair value of the awards are recognized in earnings. Cumulative compensation cost for vested liability PSU awards equals the actual cash payout amount upon vesting. To the extent the recognized fair value of the modified liability awards is less than the compensation cost associated with the grant date fair value of the original equity awards at the end of a reporting period, 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.
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. subsidiaries are translated into U.S. dollars using average exchange rates during the period. Assets and liabilities of these foreign subsidiaries are translated into U.S. dollars using the exchange rate in effect at December 31, 2016 and 2015 and the resulting translation adjustments, which were unrealized losses of $35.9 million and $12.8 million, respectively, are included in “Accumulated other comprehensive loss” (“Accumulated OCI”), a component of shareholders’ equity.
For the years ended December 31, 2016, 2015 and 2014, our foreign currency transaction gains (losses) totaled $0.2 million, $(1.2) million and $2.5 million, respectively. These realized amounts are exclusive of any gains or losses from our foreign currency exchange derivative contracts. All foreign currency transaction gains and losses are recognized currently in the consolidated statements of operations.
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 hedge 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. All derivative instruments are reflected in the accompanying consolidated balance sheets at fair value.
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-going 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 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, deferred gains or losses on the hedging instruments are recognized in earnings immediately. If the forecasted transaction continues to be probable of occurring, any deferred gains or losses in Accumulated OCI are amortized to earnings over the remaining period of the original forecasted transaction.
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We engage solely in cash flow hedges. Hedges of cash flow exposure are entered into to hedge a forecasted transaction or the variability of cash flows to be received or paid related to a recognized asset or liability. 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. Changes in the fair value of derivative instruments that are designated as cash flow hedges are deferred to the extent that the hedges are effective. These fair value changes are recorded as a component of Accumulated OCI until the hedged transactions occur and are recognized in earnings. The ineffective portion of changes in the fair value of cash flow hedges is recognized immediately in earnings. In addition, any change in the fair value of a derivative instrument that does not qualify for hedge accounting is recorded in earnings in the period in which the change occurs.
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 deferred to the extent the swaps are effective. These changes are recorded as a component of Accumulated OCI until 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 deferred to the extent the contracts are effective. These changes are recorded as a component of Accumulated OCI until 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 basic earnings per share (“EPS”) amounts on the face of the accompanying consolidated statements of operations is computed by dividing the net income applicable to our common shareholders by the weighted average shares of our outstanding common stock. The calculation of diluted EPS is similar to 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. 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 and the shares of restricted stock are thus considered participating securities. Under applicable accounting guidance, the undistributed earnings for each period are allocated based on the participation rights of both the common shareholders and 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 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 for our products and services is primarily the offshore oil and gas and renewable industries. Oil and gas companies spend capital on exploration, drilling and production operations, the amount of which is generally dependent on the prevailing view of future oil and gas prices which are subject to many external factors that may contribute to significant volatility. Our customers consist primarily of major and independent oil and gas producers and suppliers, pipeline transmission companies, alternative (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. The percent of consolidated revenue from major customers (those representing 10% or more of our consolidated revenues) is as follows: 2016 — BP (17%) and Shell (11%), 2015 — Shell (16%) and Talos (11%), and 2014 — Anadarko (13%). Most of the concentration of revenues was generated by our Well Intervention business.
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Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. The fair value accounting rules establish a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value as follows:

• | Level 1. Observable inputs such as quoted prices in active markets;

• | Level 2. Inputs, other than the quoted prices in active markets, that are observable either directly or indirectly; and

• | Level 3. Unobservable inputs for which there is little or no market data, which require the reporting entity to develop its own assumptions.

Assets and liabilities measured at fair value are based on one or more of three valuation approaches as described in Note 17.
Asset Retirement Obligations
We retained the reclamation obligations associated with one oil and gas property located in the U.S. Gulf of Mexico, which we sold in February 2013. For the year ended December 31, 2014, we recorded a $7.2 million insurance reimbursement related to asset retirement work previously performed on this property.
New Accounting Standards
In May 2014, the Financial Accounting Standards Board (the “FASB”) issued Accounting Standards Update (“ASU”) No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” This ASU provides a single five-step approach to account for revenue arising from contracts with customers. The ASU requires an entity to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This revenue standard was originally effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. In August 2015, the FASB issued ASU No. 2015-14 to defer the effective date of ASU No. 2014-09 by one year to annual reporting periods beginning after December 15, 2017. Adoption as of the original effective date is permitted. In March 2016, the FASB issued ASU No. 2016-08, which amends the guidance to clarify the implementation issues on principal versus agent considerations (gross versus net revenue presentation). In April 2016, the FASB issued ASU No. 2016-10, which amends the guidance with respect to certain implementation issues on identifying performance obligations and accounting for licenses of intellectual property. In May 2016, the FASB issued ASU No. 2016-12, which provides certain narrow-scope improvements and practical expedients to the guidance. In December 2016, the FASB issued ASU No. 2016-20, which provides certain technical corrections and improvements to the guidance. The new revenue standard permits companies to either apply the requirements retrospectively to all prior periods presented or apply the requirements in the year of adoption through a cumulative adjustment. We are in the process of assessing differences between the new revenue standard and current accounting practices (gap analysis). Remaining implementation matters include completing the gap analysis, establishing new policies, procedures and controls, and quantifying any adjustments upon adoption. We have not yet determined if we will apply the full retrospective or the modified retrospective method.
In April 2015, the FASB issued ASU No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” This ASU requires that debt issuance costs related to a recognized debt liability be reported on the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, the FASB issued ASU No. 2015-15, “Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.” This ASU includes an SEC staff announcement that the SEC staff will not object to an entity presenting the cost of securing a revolving line of credit as an asset, regardless of whether a balance is outstanding. The subject of this ASU was not previously addressed by ASU No. 2015-03. We adopted this guidance retrospectively in the first quarter of 2016. As a result, we presented $12.0 million of unamortized debt issuance costs that had been included in “Other assets, net” in our consolidated balance sheet as of December 31, 2015 as direct deductions from the carrying amounts of the related debt liabilities.
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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 current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount is not affected by this guidance. The guidance is effective prospectively for annual reporting periods beginning after December 15, 2016, including interim periods. We do not expect this ASU to materially affect our consolidated financial statements except for certain reclassifications between current deferred tax assets and non-current deferred tax liabilities.
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. We are currently evaluating the impact these amendments 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 the income tax consequences, forfeitures, classification of awards as either equity or liabilities, and classification in the statement of cash flows. The guidance is effective for annual reporting periods beginning after December 15, 2016, including interim periods. We do not expect this ASU to materially affect our consolidated financial statements with the exception of recognizing excess tax benefits or tax deficiencies on our statements of operations in future periods.
In June 2016, the FASB issued ASU No. 2016-13, “Measurement of Credit Losses on Financial Instruments.” This ASU replaces the current incurred loss model for measurement of credit losses on financial assets including trade receivables with a forward-looking expected loss model based on historical experience, current conditions and reasonable and supportable forecasts. The guidance is effective for annual reporting periods beginning after December 15, 2019, including interim periods. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
In August 2016, the FASB issued ASU No. 2016-15, “Classification of Certain Cash Receipts and Cash Payments.” This ASU addresses how certain cash receipts and cash payments are presented and classified in the statement of cash flows with the objective of reducing the existing diversity in practice. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. An entity that elects early adoption of the amendment under this ASU must adopt all aspects of the amendment in the same period. We do not expect this ASU to have a material impact on our statements of cash flows.
In October 2016, the FASB issued ASU No. 2016-16, “Intra-Entity Transfers of Assets Other Than Inventory.” This ASU eliminates the exception in current guidance that prohibits the recognition of current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party. Under the new ASU, an entity should recognize the income tax consequences of an intra-entity transfer of an asset other than inventory when the transfer occurs. The guidance is effective for annual reporting periods beginning after December 15, 2017, including interim periods. Early adoption is permitted. We are currently evaluating the impact this guidance will have on our consolidated financial statements.
We do not expect any other recent accounting standards to have a material impact on our financial position, results of operations or cash flows.
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Note 3 — Details of Certain Accounts
Other current assets consist of the following (in thousands):

| December 31,
| 2016 |  | 2015
Note receivable (Note 4) | $ | 10,000 |  |  | $ | 10,000 |
Prepaid insurance | 4,426 |  |  | 5,433 |
Other prepaids | 9,547 |  |  | 10,142 |
Deferred costs | 7,971 |  |  | 609 |
Spare parts inventory | 2,548 |  |  | 4,985 |
Income tax receivable | 880 |  |  | — |
Value added tax receivable | 1,345 |  |  | 7,842 |
Other | 671 |  |  | 507 |
Total other current assets | $ | 37,388 |  |  | $ | 39,518 |

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

| December 31,
| 2016 |  | 2015
Note receivable, net (1) | $ | 2,827 |  |  | $ | — |
Prepaids | 6,418 |  |  | — |
Deferred dry dock costs, net (Note 2) | 14,766 |  |  | 19,615 |
Deferred costs (2) | 30,738 |  |  | — |
Deferred financing costs, net (3) | 3,745 |  |  | 7,863 |
Charter fee deposit (Note 14) | 12,544 |  |  | 12,544 |
Other | 1,511 |  |  | 1,586 |
Total other assets, net | $ | 72,549 |  |  | $ | 41,608 |

(1) | Amount, net of allowance of $4.2 million, relates to an agreement we entered into with one of our customers to defer their payment obligations until June 30, 2018. Interest at a rate of 3% per annum is payable semi-annually.

(2) | Amount relates to deferred mobilization costs (Note 2).

(3) | Represents unamortized debt issuance costs related to our Revolving Credit Facility (Note 7).

Accrued liabilities consist of the following (in thousands):

| December 31,
| 2016 |  | 2015
Accrued payroll and related benefits | $ | 20,705 |  |  | $ | 14,775 |
Deferred revenue | 8,911 |  |  | 12,841 |
Accrued interest | 3,758 |  |  | 4,854 |
Derivative liability (Note 18) | 18,730 |  |  | 23,192 |
Taxes payable excluding income tax payable | 1,214 |  |  | 8,136 |
Other | 5,296 |  |  | 7,843 |
Total accrued liabilities | $ | 58,614 |  |  | $ | 71,641 |

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

| December 31,
| 2016 |  | 2015
Investee losses in excess of investment (Note 5) | $ | 10,238 |  |  | $ | 8,308 |
Deferred gain on sale of property (Note 4) | 5,761 |  |  | — |
Deferred revenue | 8,598 |  |  | — |
Derivative liability (Note 18) | 20,191 |  |  | 39,709 |
Other | 8,197 |  |  | 3,398 |
Total other non-current liabilities | $ | 52,985 |  |  | $ | 51,415 |

Note 4 — Property and Equipment
The following is a summary of the gross components of property and equipment (dollars in thousands):

|  |  | December 31,
| Estimated Useful Life |  | 2016 |  | 2015
Vessels | 15 to 30 years |  | $ | 1,860,379 |  |  | $ | 1,944,753 |
ROVs, trenchers and ROVDrills | 10 years |  | 309,603 |  |  | 311,971 |
Machinery, equipment, buildings and leasehold improvements | 5 to 30 years |  | 280,908 |  |  | 288,133 |
Total property and equipment |  |  | $ | 2,450,890 |  |  | $ | 2,544,857 |

In January 2014, we sold our spoolbase located in Ingleside, Texas for $45 million. In connection with this sale, we received $15 million in cash and a $30 million secured promissory note. Interest on the note is payable quarterly at a rate of 6% per annum. We received $2.5 million, $7.5 million and $10 million of principal payments on this note in December 2014, January 2015 and December 2015, respectively. The remaining $10 million principal balance, which was due on December 31, 2016, has not been paid. A notice of foreclosure of our lien against this property to secure the $30 million promissory note has been filed and we expect to collect the full balance of this note receivable.
Our assessment at December 31, 2015 indicated impairment on the Helix 534 and the HP I. We impaired these assets based on the difference between the carrying amount and the estimated fair value. The fair value of the Helix 534 was based on its estimated salvage value according to current market pricing. 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 deferred dry dock costs of $9.0 million associated with the Helix 534. We estimated the fair value of the HP I based on the present value of its expected future cash flows. 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. 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 Helix 534 vessel to a third party for approximately $2.8 million, including $0.4 million held in escrow until certain contingencies are resolved. We recorded a gain of approximately $1.3 million from the sale of the vessel, net of selling expenses. The $0.4 million contingent gain is deferred and will not be recognized until the payment is released to us from escrow.
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Note 5 — Equity Investments
We have a 20% ownership interest in Independence Hub that we account for using the equity method of accounting. Independence Hub owns the “Independence Hub” platform 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 Polo field in the Deepwater Gulf of Mexico. Our Production Facilities segment includes our investment in Independence Hub that is accounted for under the equity method, and previously included our former ownership interest in Deepwater Gateway.
In July 2015, Enterprise Products Partners L.P. (“Enterprise”) sold its offshore Gulf of Mexico pipelines and services business to Genesis Energy, L.P. (“Genesis”) for approximately $1.5 billion. Enterprise’s ownership interests in both Deepwater Gateway and Independence Hub were included in the sale. In December 2015, we were notified by Genesis that the operator of the facility no longer forecasted utilization of the “Independence Hub” platform and planned to turn over the platform for decommissioning. In December 2015, 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. At December 31, 2016 and 2015, Independence Hub’s estimated asset retirement obligations amounted to $52.5 million and $42.1 million, respectively, reflecting the estimated costs to decommission the platform. 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 $10.2 million and $8.3 million at December 31, 2016 and 2015, respectively, for our share of the estimated obligations, net of remaining working capital. These liabilities are reflected in “Other non-current liabilities” in the accompanying consolidated balance sheets. For the year ended December 31, 2016, we recorded losses totaling $2.2 million to account for our share of losses from Independence Hub. 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 $3.6 million and a $1.0 million participation fee that we paid in 2004. These losses included our share of the impairment charge that Independence Hub recorded in December 2015.
Additionally in December 2015, Deepwater Gateway recorded an impairment charge of $96.7 million to reduce the carrying amount of its long-lived assets to their estimated fair value of $70.8 million. Deepwater Gateway’s estimated asset retirement obligations as of December 31, 2015 amounted to $20.8 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. Our investment in Deepwater Gateway totaled $26.2 million as of December 31, 2015. In February 2016, we received a cash distribution of $1.2 million and sold our ownership interest in Deepwater Gateway to a subsidiary of Genesis for $25 million.
We received the following distributions from our equity method investments (in thousands):

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Deepwater Gateway | $ | 1,200 |  |  | $ | 5,200 |  |  | $ | 6,150 |
Independence Hub | — |  |  | 1,800 |  |  | 2,640 |
Total | $ | 1,200 |  |  | $ | 7,000 |  |  | $ | 8,790 |

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Equity method investments were immaterial to our 2016 consolidated financial results. The summarized aggregated financial information related to our equity method investments for 2014 and 2015 is as follows (in thousands):

| Year Ended December 31,
| 2015 |  | 2014
Revenues | $ | 14,791 |  |  | $ | 23,284 |
Operating income (loss) | (448,138 | ) |  | 411 |
Net income (loss) | (448,138 | ) |  | 411 |

| December 31,
| 2015
Current assets | $ | 3,181 |
Non-current assets | 70,812 |
Current liabilities | 180 |
Non-current liabilities | 62,951 |

Note 6 — Goodwill
The changes in the carrying amount of goodwill are as follows (in thousands):

| Well Intervention |  | Robotics |  | Total
Balance at December 31, 2014 | $ | 17,039 |  |  | $ | 45,107 |  |  | $ | 62,146 |
Impairment loss | (16,399 | ) |  | — |  |  | (16,399 | )
Other adjustments (1) | (640 | ) |  | — |  |  | (640 | )
Balance at December 31, 2015 | — |  |  | 45,107 |  |  | 45,107 |
Impairment loss | — |  |  | (45,107 | ) |  | (45,107 | )
Balance at December 31, 2016 | $ | — |  |  | $ | — |  |  | $ | — |

(1) | Reflects foreign currency adjustment related to the goodwill of our U.K. well intervention reporting unit.

Note 7 — Long-Term Debt
Long-term debt consists of the following (in thousands):

| December 31,
| 2016 |  | 2015
Term Loan (matures June 2018) | $ | 192,258 |  |  | $ | 255,000 |
2022 Notes (mature May 2022) | 125,000 |  |  | — |
2032 Notes (mature March 2032) | 60,115 |  |  | 200,000 |
MARAD Debt (matures February 2027) | 83,222 |  |  | 89,148 |
Nordea Q5000 Loan (matures April 2020) | 196,429 |  |  | 232,143 |
Unamortized debt discounts | (19,094 | ) |  | (14,963 | )
Unamortized debt issuance costs | (11,963 | ) |  | (11,993 | )
Total debt | 625,967 |  |  | 749,335 |
Less current maturities | (67,571 | ) |  | (71,640 | )
Long-term debt | $ | 558,396 |  |  | $ | 677,695 |

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Credit Agreement
In June 2013, we entered into a credit agreement (the “Credit Agreement”) with a group of lenders pursuant to which we borrowed $300 million under a term loan (the “Term Loan”) and, subject to the terms of the Credit Agreement, may borrow additional amounts (the “Revolving Loans”) and/or obtain letters of credit under a revolving credit facility (the “Revolving Credit Facility”) up to $600 million (reduced to $400 million pursuant to the February 2016 amendment to the Credit Agreement, as described below). 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 obtain an increase of up to $200 million in aggregate commitments with respect to the Revolving Credit Facility, additional term loans or a combination thereof. As of December 31, 2016, we had no borrowings under the Revolving Credit Facility and our available borrowing capacity under that facility, based on the leverage ratio covenant, totaled $18.9 million, net of $4.1 million of letters of credit issued.
The Term Loan and the Revolving Loans (together, the “Loans”) bear interest, at our election, in relation to either the base rate established by Bank of America N.A. or to a LIBOR rate, provided that all Swing Line Loans (as defined in the Credit Agreement) will be base rate loans.
The Loans or portions thereof bearing interest at the base rate currently bear interest at a per annum rate equal to the base rate plus a margin ranging from 1.00% to 3.00%. The Loans or portions thereof bearing interest at a LIBOR rate currently bear interest at the LIBOR rate selected by us plus a margin ranging from 2.00% to 4.00%. A letter of credit fee is payable by us equal to our applicable margin for LIBOR rate Loans multiplied by the daily amount available to be drawn under outstanding letters of credit. Margins on the Loans vary in relation to the consolidated interest coverage ratio, as provided by the Credit Agreement. We also pay a fixed commitment fee of 0.50% on the unused portion of our Revolving Credit Facility. The Term Loan currently bears interest at the one-month LIBOR rate plus 4.50%. In September 2013, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Term Loan (Note 18). The total notional amount of the swaps (initially $148.1 million) decreased in proportion to the reduction in the principal amount outstanding under our Term Loan. The fixed LIBOR rates were approximately 75 basis points. The term of these swap contracts, which were settled monthly, expired in October 2016.
The Term Loan is repayable in scheduled principal installments (currently $25.6 million per year), payable quarterly, with a balloon payment of $160.2 million at maturity. These installment amounts are subject to adjustment for any prepayments on the Term Loan. We may elect to prepay amounts outstanding under the Term Loan without premium or penalty, but may not reborrow any amounts prepaid. We elected to prepay $8 million in September 2016 and $25 million in December 2016. We may also prepay amounts outstanding under the Revolving Loans without premium or penalty, and may reborrow any amounts paid up to the amount of the Revolving Credit Facility. The Loans mature on June 19, 2018.
The Credit Agreement and the other documents entered into in connection with the Credit Agreement (together, the “Loan Documents”) include terms and conditions, including covenants and prepayment requirements, that we consider customary for this type of transaction. The covenants include restrictions on our and our subsidiaries’ ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, pay dividends and incur capital expenditures. In addition, the Credit Agreement obligates us to meet certain financial ratios, including the Consolidated Interest Coverage Ratio and the Consolidated Leverage Ratio (as defined in the Credit Agreement).
In January 2016, we amended the Credit Agreement to permit the sale and lease back of certain office and warehouse property located in Aberdeen, Scotland. In February 2016, we amended the Credit Agreement to decrease the lenders’ commitment under the Revolving Credit Facility from $600 million to $400 million, and as a result, we recorded a $2.5 million interest charge to accelerate the amortization of debt issuance costs in proportion to the reduced commitment.
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Also pursuant to the February 2016 amendment to the Credit Agreement,

(a) | The minimum permitted Consolidated Interest Coverage Ratio was revised as follows:

Four Fiscal Quarters Ending | Minimum Consolidated Interest Coverage Ratio
December 31, 2016 through and including March 31, 2017 | 2.75 |  | to 1.00
June 30, 2017 and each fiscal quarter thereafter | 3.00 |  | to 1.00

(b) | The maximum permitted Consolidated Leverage Ratio was revised as follows:

Four Fiscal Quarters Ending | Maximum Consolidated Leverage Ratio
December 31, 2016 | 5.00 |  | to 1.00
March 31, 2017 | 4.75 |  | to 1.00
June 30, 2017 | 4.25 |  | to 1.00
September 30, 2017 | 3.75 |  | to 1.00
December 31, 2017 and each fiscal quarter thereafter | 3.50 |  | to 1.00

(c) | A financial covenant was established requiring us to maintain a minimum cash balance if our Consolidated Leverage Ratio is 3.50x or greater, as described below. 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 as cash and cash equivalents on our balance sheet. As of December 31, 2016, we needed to maintain an aggregate cash balance of at least $150 million in order to comply with this covenant.

Consolidated Leverage Ratio | Minimum Cash Balance
Greater than or equal to 4.50x | $150,000,000.00
Greater than or equal to 4.00x but less than 4.50x | 100,000,000.00
Greater than or equal to 3.50x but less than 4.00x | 50,000,000.00
Less than 3.50x | 0.00

We have designated five of our foreign subsidiaries, and may designate any newly established foreign subsidiaries, as subsidiaries that are not generally subject to the Credit Agreement’ covenants (the “Unrestricted Subsidiaries”), provided we meet certain liquidity requirements, in which case EBITDA (net of cash distributions to the parent) of the Unrestricted Subsidiaries is not included in the calculations with respect to our financial covenants. Our obligations under the Credit Agreement are guaranteed by our wholly owned 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 the guarantors under their guaranty, are secured by most of our assets of the parent and our wholly owned domestic subsidiaries (except Cal Dive I – Title XI, Inc.) and Canyon Offshore Limited, plus pledges of up to two-thirds of the shares of certain foreign subsidiaries.
Convertible Senior Notes Due 2022
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 of aggregate principal amount of the 2032 Notes (see “Convertible Senior Notes Due 2032” below), in separate, privately negotiated transactions.
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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 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. We have the right and the intention to settle any such future conversions in cash.
Prior to November 1, 2019, the 2022 Notes are not redeemable. On or after November 1, 2019, holders of the 2022 Notes may require us to repurchase the notes following a “fundamental change,” as defined in the 2022 Notes documentation. On or after November 1, 2019, 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 the present value of the remaining scheduled interest payments of the 2022 Notes to be redeemed through May 1, 2022.
The Indenture 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 of the 2022 Notes then outstanding 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 principal 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.
In connection with the issuance of the 2022 Notes, we recorded a debt discount of $16.9 million as required under existing accounting rules. To arrive at this discount amount, 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 pricing and an expected life of 5.5 years. The effective interest rate for the 2022 Notes is 7.3% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2022 Notes at their inception. We recorded $11.0 million, net of tax, related to the carrying amount of the equity component of the 2022 Notes. The remaining unamortized amount of the debt discount of the 2022 Notes was $16.5 million at December 31, 2016.
Convertible Senior Notes Due 2032
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. The 2032 Notes bear interest at a rate of 3.25% per annum, and are payable semi-annually in arrears on March 15 and September 15 of each year, beginning on September 15, 2012. The 2032 Notes mature on March 15, 2032, unless earlier converted, redeemed or repurchased. The 2032 Notes are convertible in certain circumstances and during certain periods at an initial conversion rate of 39.9752 shares of common stock per $1,000 principal amount (which represents an initial conversion price of approximately $25.02 per share of common stock), subject to adjustment in certain circumstances as set forth in the Indenture governing the 2032 Notes. We have the right and the intention to settle any such future conversions in cash.
Prior to March 20, 2018, the 2032 Notes are not redeemable. On or after March 20, 2018, we, at our option, may redeem some or all of the 2032 Notes in cash, at any time upon at least 30 days’ notice, at a price equal to 100% of the principal amount 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 at 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 (either a Change of Control or a Termination of Trading, as those terms are defined in the Indenture governing the 2032 Notes).
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In connection with the issuance of the 2032 Notes, we recorded a debt discount of $35.4 million as required under existing accounting rules. To arrive at this discount amount, 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 pricing 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). The effective interest rate for the 2032 Notes is 6.9% after considering the effect of the accretion of the related debt discount that represented the equity component of the 2032 Notes at their inception. We recorded $22.5 million, net of tax, related to the carrying amount of the equity component of the 2032 Notes. The remaining unamortized amount of the debt discount of the 2032 Notes was $2.6 million and $15.0 million at December 31, 2016 and 2015, respectively.
In June 2016, we repurchased $7.3 million in aggregate principal amount of the 2032 Notes for $6.5 million. In July 2016, we repurchased an additional $7.6 million in aggregate principal amount of the 2032 Notes for $7.0 million including $0.1 million in accrued interest. The purchase price reflects the market price of the notes at the time of purchase. In association with the issuance of the 2022 Notes in November 2016, we repurchased $125 million in aggregate principal amount of the 2032 Notes at par and paid $0.5 million in accrued interest. For the year ended December 31, 2016, we recognized a net loss of $3.5 million, which is presented as “Loss on repurchase of long-term debt” in the accompanying consolidated statement of operations. Included in the loss were charges totaling $7.5 million for the acceleration of a pro rata portion of unamortized debt discount and debt issuance costs related to the 2032 Notes, offset in part by $2.5 million related to the re-acquisition of the equity component of the 2032 Notes.
MARAD Debt
This U.S. government guaranteed financing (the “MARAD Debt”) is pursuant to Title XI of the Merchant Marine Act of 1936 administered by the Maritime Administration, and was used to finance the construction of the Q4000. The MARAD Debt is payable in equal semi-annual installments beginning in August 2002 and matures in February 2027. The MARAD Debt is collateralized by the Q4000, is guaranteed 50% by us, and initially bore interest at a floating rate that approximated AAA Commercial Paper yields plus 20 basis points. As required by the MARAD Debt agreements, in September 2005, we fixed the interest rate on the debt through the issuance of a 4.93% fixed-rate note with the same maturity date.
Nordea Credit Agreement
In September 2014, a wholly owned subsidiary incorporated in Luxembourg, Helix Q5000 Holdings S.à r.l. (“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., also a wholly owned Luxembourg subsidiary, guaranteed the Nordea Q5000 Loan. The loan is secured by the Q5000 and its charter earnings as well as by a pledge of the shares of Q5000 Holdings. This indebtedness is non-recourse to Helix.
The Nordea Q5000 Loan bears interest at a LIBOR rate plus a margin of 2.5%. The Nordea Q5000 Loan matures on April 30, 2020 and is repayable in scheduled quarterly principal installments of $8.9 million with a balloon payment of $80.4 million at maturity. Q5000 Holdings may elect to prepay amounts outstanding under the Nordea Q5000 Loan without premium or penalty, but may not reborrow any amounts prepaid. Installment amounts are subject to adjustment for any prepayments on this debt. In June 2015, we entered into various interest rate swap contracts to fix the one-month LIBOR rate on a portion of our borrowings under the Nordea Q5000 Loan (Note 18). The total notional amount of the swaps (initially $187.5 million) decreases in proportion to the reduction in the principal amount outstanding under our Nordea Q5000 Loan. The fixed LIBOR rates are approximately 150 basis points.
The Nordea Credit Agreement and related loan documents include terms and conditions, including covenants and prepayment requirements, that are considered customary for this type of transaction. The covenants include restrictions on Q5000 Holdings’s ability to grant liens, incur indebtedness, make investments, merge or consolidate, sell or transfer assets, and pay dividends. In addition, the Nordea Credit Agreement obligates Q5000 Holdings to meet certain minimum financial requirements, including liquidity, consolidated debt service coverage and collateral maintenance.
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Other
In accordance with our Credit Agreement, the 2032 Notes, the MARAD Debt agreements, and the Nordea Credit Agreement, we are required to comply with certain covenants, including certain financial ratios such as a consolidated interest coverage ratio and a consolidated leverage ratio, as well as the maintenance of minimum net worth, working capital and debt-to-equity requirements. As of December 31, 2016, we were in compliance with these covenants.
Scheduled maturities of long-term debt outstanding as of December 31, 2016 are as follows (in thousands):

| Term Loan |  | 2022 Notes |  | 2032 Notes (1) |  | MARAD Debt |  | Nordea Q5000 Loan |  | Total
Less than one year | $ | 25,634 |  |  | $ | — |  |  | $ | — |  |  | $ | 6,222 |  |  | $ | 35,715 |  |  | $ | 67,571 |
One to two years | 166,624 |  |  | — |  |  | — |  |  | 6,532 |  |  | 35,714 |  |  | 208,870 |
Two to three years | — |  |  | — |  |  | — |  |  | 6,858 |  |  | 35,714 |  |  | 42,572 |
Three to four years | — |  |  | — |  |  | — |  |  | 7,200 |  |  | 89,286 |  |  | 96,486 |
Four to five years | — |  |  | — |  |  | — |  |  | 7,560 |  |  | — |  |  | 7,560 |
Over five years | — |  |  | 125,000 |  |  | 60,115 |  |  | 48,850 |  |  | — |  |  | 233,965 |
Total debt | 192,258 |  |  | 125,000 |  |  | 60,115 |  |  | 83,222 |  |  | 196,429 |  |  | 657,024 |
Current maturities | (25,634 | ) |  | — |  |  | — |  |  | (6,222 | ) |  | (35,715 | ) |  | (67,571 | )
Long-term debt, less current maturities | 166,624 |  |  | 125,000 |  |  | 60,115 |  |  | 77,000 |  |  | 160,714 |  |  | 589,453 |
Unamortized debt discounts (2) | — |  |  | (16,513 | ) |  | (2,581 | ) |  | — |  |  | — |  |  | (19,094 | )
Unamortized debt issuance costs (3) | (1,391 | ) |  | (2,790 | ) |  | (231 | ) |  | (5,001 | ) |  | (2,550 | ) |  | (11,963 | )
Long-term debt | $ | 165,233 |  |  | $ | 105,697 |  |  | $ | 57,303 |  |  | $ | 71,999 |  |  | $ | 158,164 |  |  | $ | 558,396 |

(1) | Beginning in March 2018, the holders of the 2032 Notes may require us to repurchase these notes or we may at our option elect to repurchase these notes. The notes will mature in March 2032.

(2) | The 2022 Notes will increase to their face amount through accretion of non-cash interest charges through May 2022. The 2032 Notes will increase to their face amount through accretion of non-cash interest charges through March 2018.

(3) | 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,
| 2016 |  | 2015 |  | 2014
Interest expense | $ | 45,110 |  |  | $ | 40,024 |  |  | $ | 33,064 |
Interest income | (2,086 | ) |  | (2,068 | ) |  | (4,786 | )
Capitalized interest | (11,785 | ) |  | (11,042 | ) |  | (10,419 | )
Net interest expense | $ | 31,239 |  |  | $ | 26,914 |  |  | $ | 17,859 |

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Note 8 — Income Taxes
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 tax litigation is inherently uncertain, and 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,
| 2016 |  | 2015 |  | 2014
Current | $ | (27,319 | ) |  | $ | 1,832 |  |  | $ | 43,817 |
Deferred | 14,849 |  |  | (103,022 | ) |  | 23,154 |
| $ | (12,470 | ) |  | $ | (101,190 | ) |  | $ | 66,971 |

Domestic | $ | (9,631 | ) |  | $ | (102,978 | ) |  | $ | 29,613 |
Foreign | (2,839 | ) |  | 1,788 |  |  | 37,358 |
| $ | (12,470 | ) |  | $ | (101,190 | ) |  | $ | 66,971 |

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

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Domestic | $ | (61,484 | ) |  | $ | (485,760 | ) |  | $ | 73,700 |
Foreign | (32,431 | ) |  | 7,590 |  |  | 188,821 |
| $ | (93,915 | ) |  | $ | (478,170 | ) |  | $ | 262,521 |

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 U.S. statutory rate and our effective rate are as follows:

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Statutory rate | 35.0 | % |  | 35.0 | % |  | 35.0 | %
Foreign provision | (5.1 | ) |  | (13.7 | ) |  | (9.1 | )
Goodwill impairment | (16.8 | ) |  | — |  |  | — |
Other | 0.2 |  |  | (0.1 | ) |  | (0.4 | )
Effective rate | 13.3 | % |  | 21.2 | % |  | 25.5 | %

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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,
| 2016 |  | 2015
Deferred tax liabilities: |  |  |
Depreciation | $ | 192,777 |  |  | $ | 173,863 |
Original issuance discount on 2022 Notes and 2032 Notes | 11,802 |  |  | 17,957 |
Equity investments in production facilities | — |  |  | 8,029 |
Prepaid and other | 1,448 |  |  | 1,883 |
Total deferred tax liabilities | $ | 206,027 |  |  | $ | 201,732 |
Deferred tax assets: |  |  |
Net operating losses | $ | (20,910 | ) |  | $ | (23,595 | )
Reserves, accrued liabilities and other | (38,131 | ) |  | (52,672 | )
Total deferred tax assets | (59,041 | ) |  | (76,267 | )
Valuation allowance | 3,771 |  |  | 1,936 |
Net deferred tax liabilities | $ | 150,757 |  |  | $ | 127,401 |
Deferred income tax is presented as: |  |  |
Current deferred tax assets | $ | (16,594 | ) |  | $ | (53,573 | )
Non-current deferred tax liabilities | 167,351 |  |  | 180,974 |
Net deferred tax liabilities | $ | 150,757 |  |  | $ | 127,401 |

At December 31, 2016, our U.S. net operating losses available for carryforward totaled $43.2 million and our foreign tax credits available for carryforward totaled $7.2 million. The net operating loss carryforward would expire in 2036 if unused. Foreign tax credits of $2.8 million and $4.4 million if unused would expire in 2025 and 2026, respectively. At December 31, 2016, the U.K. net operating losses of our well intervention company available for carryforward totaled $3.2 million. Realization is dependent on generating sufficient taxable income prior to expiration of the loss carryforwards. Although realization is not assured, management believes it is more likely than not that all of these tax attributes will be utilized. The amount of the deferred tax asset considered realizable, however, could be reduced in the near term if estimates of future taxable income during the carryforward are reduced.
At December 31, 2016, we had a $3.8 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 operations in the U.K., as management believes it is more likely than not that we will not be able to utilize the tax benefit. Additional valuation allowances may be made in the future if in management’s opinion it is more likely than not that the tax benefit will not be utilized.
We consider the undistributed earnings of our non-U.S. subsidiaries without operations in the U.S. to be permanently reinvested. At December 31, 2016 and 2015, our non-U.S. subsidiaries without operations in the U.S. had accumulated earnings and profits of approximately $74.9 million and $304.0 million, respectively. We have not provided deferred U.S. income tax on the accumulated earnings and profits from our non-U.S. subsidiaries without operations in the U.S. as we consider them permanently reinvested. Due to complexities in the tax laws and the manner of repatriation, it is not practicable to estimate the unrecognized amount of deferred income taxes and the related dividend withholding taxes associated with these undistributed earnings.
We account for tax-related interest in interest expense and tax penalties in selling, general and administrative expenses. No significant penalties or interest expense were accrued on our uncertain tax positions. We had unrecognized tax benefits of $0.3 million related to uncertain tax positions as of December 31, 2016, which if recognized would affect the annual effective tax rate. We had no uncertain tax positions as of December 31, 2015 and 2014. In 2014, in connection with the recognition of a $3.4 million tax benefit as a result of the completion of examination procedures for the 2006 through 2010 audit period by the U.S. Internal Revenue Service (see below), we reversed approximately $1.3 million of previously accrued interest and penalties.
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A reconciliation of the beginning and ending amount of unrecognized tax benefits for the years ended December 31, 2016, 2015 and 2014 is as follows (in thousands):

| 2016 |  | 2015 |  | 2014
Balance at January 1, | $ | — |  |  | $ | — |  |  | $ | 4,723 |
Additions for tax positions of prior years | 343 |  |  | — |  |  | — |
Reductions for tax positions of prior years | — |  |  | — |  |  | (4,723 | )
Balance at December 31, | $ | 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 June 2014, the Internal Revenue Service and the Joint Committee on Taxation completed the examination procedures including all appeals and administrative reviews that the taxing authorities are required and expected to perform for the 2006 through 2010 audit period, and in September 2014, we received an income tax refund in the amount of $35.2 million. The refund was primarily attributable to the utilization of a net operating loss carryback from 2010. 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 2012 through 2016 remain open to review and examination by the Internal Revenue Service. In non-U.S. jurisdictions, the open tax periods include 2010 through 2016.
Note 9 — Shareholders’ Equity
Our amended and restated Articles of Incorporation provide for authorized Common Stock of 240,000,000 shares with no stated par value per share and 5,000,000 shares of preferred stock, $0.01 par value per share issuable in one or more series.
On April 25, 2016, we launched an at-the-market (“ATM”) equity offering program and executed an Equity Distribution Agreement with Wells Fargo Securities, LLC (“Wells Fargo”) to sell up to $50 million of our common stock through Wells Fargo. As of December 31, 2016, we had sold a total of 6,309,355 shares of our common stock under this ATM program for $50 million, or an average of $7.92 per share. The proceeds from this ATM program totaled $47.7 million, net of transaction costs, including commissions of $1.3 million to Wells Fargo.
On August 11, 2016, we executed another Equity Distribution Agreement with Wells Fargo to sell an additional $50 million of our common stock under an ATM program. As of December 31, 2016, we had sold a total of 6,709,377 shares of our common stock under this ATM program for $50 million, or an average of $7.45 per share. The proceeds from this ATM program totaled $48.8 million, net of transaction costs, including commissions of $1.0 million to Wells Fargo.
Subsequently on January 10, 2017, we completed an underwritten public offering (the “Offering”) of 26,450,000 shares of our common stock, no par value, at a public offering price of $8.65 per share. The net proceeds from the Offering approximated $220 million, after deducting underwriting discounts and commissions and estimated offering expenses. We intend to use the net proceeds from the Offering for general corporate purposes, which may include debt repayment, capital expenditures, working capital, acquisitions or investments in our subsidiaries.
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The components of Accumulated OCI are as follows (in thousands):

| December 31,
| 2016 |  | 2015
Cumulative foreign currency translation adjustment | $ | (78,953 | ) |  | $ | (43,010 | )
Unrealized loss on hedges, net (1) | (18,021 | ) |  | (27,891 | )
Accumulated other comprehensive loss | $ | (96,974 | ) |  | $ | (70,901 | )

(1) | Amounts relate to foreign currency hedges for the Grand Canyon, the Grand Canyon II and the Grand Canyon III charters as well as interest rate swap contracts for the Term Loan and the Nordea Q5000 Loan, and are net of deferred income taxes totaling $9.7 million and $15.1 million as of December 31, 2016 and 2015, respectively (Note 18).

Note 10 — Stock Buyback Program
Our Board of Directors 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 plans (Note 12). We may continue to make repurchases pursuant to this authority from time to time as additional equity is issued under our stock based plans depending on prevailing market conditions and other factors. As described in an announced plan, all repurchases may be commenced or suspended at any time as determined by management. We have not purchased any shares available under this program since 2015. As of December 31, 2016, we had repurchased a total of 3,589,425 shares of our common stock. As of December 31, 2016, we had 2,327,608 shares of our common stock available for repurchase under the program.
Note 11 — 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,
| 2016 |  | 2015 |  | 2014
| Income |  | Shares |  | Income |  | Shares |  | Income |  | Shares
Basic: |  |  |  |  |  |  |  |  |  |  |
Net income (loss) applicable to common shareholders | $ | (81,445 | ) |  |  |  | $ | (376,980 | ) |  |  |  | $ | 195,047 |  |  |
Less: Undistributed earnings allocated to participating securities | — |  |  |  |  | — |  |  |  |  | (1,018 | ) |  |
Undistributed earnings (loss) allocated to common shares | $ | (81,445 | ) |  | 111,612 |  |  | $ | (376,980 | ) |  | 105,416 |  |  | $ | 194,029 |  |  | 105,029 |

Diluted: |  |  |  |  |  |  |  |  |  |  |
Undistributed earnings (loss) allocated to common shares | $ | (81,445 | ) |  | 111,612 |  |  | $ | (376,980 | ) |  | 105,416 |  |  | $ | 194,029 |  |  | 105,029 |
Effect of dilutive securities: |  |  |  |  |  |  |  |  |  |  |
Share-based awards other than participating securities | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 16 |
Undistributed earnings reallocated to participating securities | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Net income (loss) applicable to common shareholders | $ | (81,445 | ) |  | 111,612 |  |  | $ | (376,980 | ) |  | 105,416 |  |  | $ | 194,029 |  |  | 105,045 |

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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, the following potentially dilutive shares related to the 2022 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 7) (in thousands):

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
2022 Notes | 1,475 |  |  | — |  |  | — |
2032 Notes | 6,891 |  |  | 7,995 |  |  | 7,995 |

Note 12 — Employee Benefit Plans
Defined Contribution Plan
We sponsor a defined contribution 401(k) retirement plan covering substantially all of our employees. Our discretionary contributions are in the form of cash. Beginning in 2014, our matching contributions consisted of a 75% match of each employee’s contribution up to 5% of the employee’s salary. Our discretionary matching contributions were suspended for an indefinite period beginning February 2016. For the years ended December 31, 2016, 2015 and 2014, our costs related to the 401(k) plan totaled $0.5 million, $2.8 million and $2.2 million, respectively.
Employee Stock Purchase Plan
We have an employee stock purchase plan (the “ESPP”). The ESPP has 1.5 million shares authorized for issuance, of which 0.7 million shares were available for issuance as of December 31, 2016. 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 of Directors 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 the first trading day of the purchase period or (ii) its fair market value on the last trading day of the purchase period. In February 2016, we suspended ESPP purchases for the January through April 2016 purchase period and indefinitely imposed a purchase limit of 130 shares per employee for subsequent purchase periods. For the years ended December 31, 2016, 2015 and 2014, share-based compensation with respect to the ESPP was $0.1 million, $1.1 million and $1.0 million, respectively.
Long-Term Incentive Stock-Based Plan
We currently have one active long-term incentive stock-based plan, the 2005 Long-Term Incentive Plan, as amended and restated effective January 1, 2017 (the “2005 Incentive Plan”). The 2005 Incentive Plan has 10.3 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, 2016, there were 3.7 million shares available for issuance under the 2005 Incentive Plan.
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The 2005 Incentive Plan is administered by the Compensation Committee of our Board of Directors. 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 granted 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-year anniversary date of the grant.
The following grants of share-based awards were made in 2016 under the 2005 Incentive Plan:

Date of Grant |  |  | Shares |  |  |  | Grant Date Fair Value Per Share |  |  | Vesting Period
January 4, 2016 (1) |  |  | 1,143,062 |  |  |  |  | $ | 5.26 |  |  |  | 33% per year over three years
January 4, 2016 (2) |  |  | 1,143,062 |  |  |  |  | $ | 7.13 |  |  |  | 100% on January 1, 2019
January 4, 2016 (3) |  |  | 11,763 |  |  |  |  | $ | 5.26 |  |  |  | 100% on January 1, 2018
February 1, 2016 (1) |  |  | 18,610 |  |  |  |  | $ | 4.03 |  |  |  | 33% per year over three years
February 1, 2016 (2) |  |  | 18,610 |  |  |  |  | $ | 7.13 |  |  |  | 100% on January 1, 2019
April 1, 2016 (3) |  |  | 13,727 |  |  |  |  | $ | 5.60 |  |  |  | 100% on January 1, 2018
July 1, 2016 (3) |  |  | 8,476 |  |  |  |  | $ | 6.76 |  |  |  | 100% on January 1, 2018
October 3, 2016 (3) |  |  | 7,803 |  |  |  |  | $ | 8.13 |  |  |  | 100% on January 1, 2018
December 2, 2016 (4) |  |  | 94,680 |  |  |  |  | $ | 11.09 |  |  |  | 33% per year over three years

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

(2) | Reflects the grant of PSUs to our executive officers and select management employees.

(3) | Reflects the grant of restricted stock to certain independent members of our Board of Directors 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 of Directors.

In January 2017, we granted our executive officers and select management employees 671,771 shares of restricted stock under the 2005 Incentive Plan. The market value of the restricted shares was $8.82 per share or $5.9 million. Concurrently, we issued our executive officers and the select management employees 671,771 PSUs under the 2005 Incentive Plan.
Restricted Stock
We grant restricted stock to members of our Board of Directors, executive officers and select management employees. The following table summarizes information about our restricted stock:

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
| Shares |  | Grant Date Fair Value (1) |  | Shares |  | Grant Date Fair Value (1) |  | Shares |  | Grant Date Fair Value (1)
Awards outstanding at beginning of year | 661,124 |  |  | $ | 16.28 |  |  | 554,960 |  |  | $ | 17.54 |  |  | 771,942 |  |  | $ | 13.62 |
Granted | 1,298,121 |  |  | 5.70 |  |  | 501,076 |  |  | 15.57 |  |  | 139,455 |  |  | 23.22 |
Vested (2) (3) | (305,588 | ) |  | 16.94 |  |  | (332,223 | ) |  | 16.44 |  |  | (356,437 | ) |  | 11.27 |
Forfeited | (75,684 | ) |  | 7.76 |  |  | (62,689 | ) |  | 20.93 |  |  | — |  |  | — |
Awards outstanding at end of year (3) | 1,577,973 |  |  | $ | 7.86 |  |  | 661,124 |  |  | $ | 16.28 |  |  | 554,960 |  |  | $ | 17.54 |

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(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 and RSUs that vested during the years ended December 31, 2016, 2015 and 2014 was $2.2 million, $5.1 million and $8.2 million, respectively.

(3) | The vested and year-end amounts in 2014 each included 33,760 shares of RSUs with the grant date fair value of 15.80 per share. We paid $0.7 million in cash upon vesting of these RSUs in January 2015.

For the years ended December 31, 2016, 2015 and 2014, $5.8 million, $5.5 million and $5.0 million, respectively, were recognized as share-based compensation related to restricted stock and RSUs. Forfeitures on restricted stock totaled approximately 5% based on our most recent five-year average of historical forfeiture rates. Future compensation cost associated with unvested restricted stock at December 31, 2016 totaled approximately $7.5 million. The weighted average vesting period related to unvested restricted stock at December 31, 2016 was approximately 1.9 years.
Performance Share Units
We grant PSUs to our executive officers and select management employees. The PSUs provide for an award 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 of Directors, with the maximum amount of the award being 200% of the original awarded PSUs and the minimum amount being zero. The vested PSUs may be settled in either cash or shares of our common stock at the discretion of the Compensation Committee of our Board of Directors with the exception of the PSUs granted in January 2017, which are to be settled solely in shares of our common stock.
We issued 1,161,672 PSUs in 2016 with a grant date fair value of $7.13 per unit, 295,693 PSUs in 2015 with a grant date fair value of $25.06 per unit and 73,609 PSUs in 2014 with a grant date fair value of $26.79 per unit. In January 2015, in connection with the vesting of the 2012 PSU awards, the decision was made by the Compensation Committee of our Board of Directors to settle these PSUs with a cash payment of $4.5 million (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. For the years ended December 31, 2016, 2015 and 2014, $6.8 million, $0.2 million and $5.4 million, respectively, were recognized as share-based compensation related to PSUs. For the years ended December 31, 2016 and 2015, $0.2 million and $2.9 million, respectively, were recorded in equity reflecting the cumulative compensation cost recognized in excess of the estimated fair value of the modified liability PSU awards. At December 31, 2016 and 2015, the liability balance for unvested PSUs was $7.1 million and $0.7 million, respectively. We paid $0.2 million to cash settle the 2013 grant of PSUs when they vested in January 2016. We paid $0.6 million to cash settle the 2014 grant of PSUs when they vested in January 2017.
Long-Term Incentive Cash Plans
We previously granted awards under certain long-term incentive cash plans (the “LTI Cash Plans”) that provide long-term cash-based compensation to eligible employees. 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. Payout under these awards was calculated based on the ratio of the average stock price during the applicable measurement period over the original base price determined by the Compensation Committee of our Board of Directors at the time of the award. These cash awards vested equally each year over a three-year period and payments under these awards were made on each anniversary date of the award. The LTI Cash Plans are considered liability plans and as such are re-measured to fair value each reporting period with corresponding changes in the liability amount being reflected in our results of operations.
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The cash awards granted under the LTI Cash Plans to our executive officers and select management employees totaled $8.9 million in 2014. No long-term incentive cash awards were granted subsequent to 2014. For the year ended December 31, 2014, total compensation cost associated with the cash awards issued pursuant to the LTI Cash Plans was $7.2 million ($3.6 million related to our executive officers). For the year ended December 31, 2015, we recorded reductions of $3.7 million ($2.1 million related to our executive officers) of previously recognized compensation cost associated with the cash awards issued pursuant to the LTI Cash Plans, 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 under the LTI Cash Plans was less than $0.1 million at December 31, 2015. We reduced this liability balance down to zero at December 31, 2016 as these cash awards did not meet the performance requirements for any payout in January 2017. During 2014 and 2015, we paid $9.2 million and $8.9 million, respectively, of the liability associated with the LTI Cash Plans. No long-term incentive cash awards were paid in 2016.
Note 13 — Business Segment Information
We have three reportable business segments: Well Intervention, Robotics and Production Facilities. Our U.S., U.K. and Brazil well intervention operating segments are aggregated into the Well Intervention business segment for financial reporting purposes. Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the U.S. Gulf of Mexico, North Sea and Brazil. Our well intervention vessels include the Q4000, the Q5000, the Seawell, the Well Enhancer, and the chartered Skandi Constructor, Siem Helix 1 and Siem Helix 2 vessels. We previously owned the Helix 534, which we sold in December 2016 (Note 4). Our Well Intervention segment also includes IRSs, some of which we rent out on a stand-alone basis, and SILs. Our Robotics segment includes ROVs, trenchers and ROVDrills designed to complement offshore construction and well intervention services, and currently operates three chartered ROV support vessels. Our Production Facilities segment includes the HP I, the HFRS and our investment in Independence Hub that is accounted for under the equity method, and previously included our former ownership interest in Deepwater Gateway that we sold in February 2016 (Note 5). 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,
| 2016 |  | 2015 |  | 2014
Net revenues — |  |  |  |  |
Well Intervention | $ | 294,000 |  |  | $ | 373,301 |  |  | $ | 667,849 |
Robotics | 160,580 |  |  | 301,026 |  |  | 420,224 |
Production Facilities | 72,358 |  |  | 75,948 |  |  | 93,175 |
Other | — |  |  | — |  |  | 358 |
Intercompany elimination | (39,356 | ) |  | (54,473 | ) |  | (74,450 | )
Total | $ | 487,582 |  |  | $ | 695,802 |  |  | $ | 1,107,156 |

Income (loss) from operations — |  |  |  |  |
Well Intervention (1) | $ | 14,910 |  |  | $ | (194,381 | ) |  | $ | 204,810 |
Robotics (2) | (72,250 | ) |  | 27,832 |  |  | 68,329 |
Production Facilities (3) | 33,861 |  |  | (106,847 | ) |  | 41,138 |
Corporate and other (4) | (39,384 | ) |  | (33,866 | ) |  | (51,600 | )
Intercompany elimination | (372 | ) |  | (98 | ) |  | (921 | )
Total | $ | (63,235 | ) |  | $ | (307,360 | ) |  | $ | 261,756 |

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| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Net interest expense — |  |  |  |  |
Well Intervention | $ | (109 | ) |  | $ | (102 | ) |  | $ | (252 | )
Robotics | (25 | ) |  | 29 |  |  | (5 | )
Production Facilities | — |  |  | 385 |  |  | 384 |
Corporate and elimination | 31,373 |  |  | 26,602 |  |  | 17,732 |
Total | $ | 31,239 |  |  | $ | 26,914 |  |  | $ | 17,859 |

Equity in earnings (losses) of investments | $ | (2,166 | ) |  | $ | (124,345 | ) |  | $ | 879 |

Income (loss) before income taxes — |  |  |  |  |
Well Intervention (1) | $ | 18,813 |  |  | $ | (193,572 | ) |  | $ | 211,725 |
Robotics (2) (5) | (73,533 | ) |  | 2,454 |  |  | 61,025 |
Production Facilities (3) | 31,695 |  |  | (231,577 | ) |  | 41,633 |
Corporate and other and eliminations (4) (6) | (70,890 | ) |  | (55,475 | ) |  | (51,862 | )
Total | $ | (93,915 | ) |  | $ | (478,170 | ) |  | $ | 262,521 |

Income tax provision (benefit) — |  |  |  |  |
Well Intervention | $ | 12,531 |  |  | $ | (1,230 | ) |  | $ | 50,102 |
Robotics | (9,948 | ) |  | 515 |  |  | 21,612 |
Production Facilities | 11,093 |  |  | (81,052 | ) |  | 14,395 |
Corporate and other and eliminations | (26,146 | ) |  | (19,423 | ) |  | (19,138 | )
Total | $ | (12,470 | ) |  | $ | (101,190 | ) |  | $ | 66,971 |

Capital expenditures — |  |  |  |  |
Well Intervention | $ | 185,892 |  |  | $ | 307,879 |  |  | $ | 283,635 |
Robotics | 720 |  |  | 10,700 |  |  | 51,348 |
Production Facilities | 74 |  |  | 1,867 |  |  | 869 |
Corporate and other | (199 | ) |  | (135 | ) |  | 1,060 |
Total | $ | 186,487 |  |  | $ | 320,311 |  |  | $ | 336,912 |

Depreciation and amortization — |  |  |  |  |
Well Intervention | $ | 68,392 |  |  | $ | 66,095 |  |  | $ | 57,570 |
Robotics | 25,848 |  |  | 26,724 |  |  | 24,478 |
Production Facilities | 13,952 |  |  | 21,340 |  |  | 21,278 |
Corporate and eliminations | 5,995 |  |  | 6,242 |  |  | 6,019 |
Total | $ | 114,187 |  |  | $ | 120,401 |  |  | $ | 109,345 |

(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.

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(4) | Amount in 2014 included a $10.5 million gain on the sale of our Ingleside spoolbase in January 2014.

(5) | 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.

(6) | Amount in 2014 included $16.9 million of income with $7.2 million from an insurance reimbursement related to asset retirement work previously performed and the remaining from our overriding royalty income.

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,
| 2016 |  | 2015 |  | 2014
Well Intervention | $ | 8,442 |  |  | $ | 22,855 |  |  | $ | 29,875 |
Robotics | 30,914 |  |  | 31,618 |  |  | 44,575 |
Total | $ | 39,356 |  |  | $ | 54,473 |  |  | $ | 74,450 |

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

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
United States | $ | 298,279 |  |  | $ | 298,391 |  |  | $ | 403,994 |
North Sea (1) | 137,313 |  |  | 263,438 |  |  | 504,016 |
Other | 51,990 |  |  | 133,973 |  |  | 199,146 |
Total | $ | 487,582 |  |  | $ | 695,802 |  |  | $ | 1,107,156 |

(1) | Includes revenues of $123.6 million, $187.7 million and $362.7 million, respectively, which were from the U.K.

Our assets related to operations, primarily our vessels, operate throughout the year in various regions around the world such as the U.S. Gulf of Mexico, North Sea, 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,
| 2016 |  | 2015
United States | $ | 956,458 |  |  | $ | 1,024,691 |
United Kingdom | 299,699 |  |  | 352,740 |
Singapore (1) | 194,649 |  |  | 112,313 |
Other | 200,804 |  |  | 113,265 |
Total | $ | 1,651,610 |  |  | $ | 1,603,009 |

(1) | Primarily includes the Q7000 vessel under construction.

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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,
| 2016 |  | 2015
Well Intervention | $ | 1,596,517 |  |  | $ | 1,484,109 |
Robotics | 186,901 |  |  | 274,926 |
Production Facilities | 158,192 |  |  | 182,007 |
Corporate and other | 305,331 |  |  | 458,917 |
Total | $ | 2,246,941 |  |  | $ | 2,399,959 |

Note 14 — 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. We amended the charter agreements in February 2016 to reduce the charter rates and, in connection with such reductions, to extend the terms to October 2019 for the Grand Canyon, April 2021 for the Grand Canyon II and May 2023 for the Grand Canyon III. We also have a charter agreement for the Deep Cygnus which expires in March 2018.
In September 2013, we executed a contract with the same shipyard in Singapore that constructed the Q5000. This contract is for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which is being built to North Sea standards. This $346 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000. Pursuant to the original terms of this contract, 20% of the contract price was paid upon the signing of the contract. Pursuant to a contract amendment we entered into in June 2015, we agreed to pay the shipyard incremental costs of up to $14.5 million to extend the scheduled delivery of the Q7000 from mid-2016 to July 30, 2017 and to defer certain payment obligations. We paid $7.3 million of these costs in July 2015 and the remaining costs were to be paid upon the delivery of the vessel. Pursuant to a second contract amendment we entered into in December 2015, the remaining 80% is to be paid in three installments, with 20% in June 2016 (payment was made in October 2016 as agreed between the parties), 20% upon issuance of the Completion Certificate, which is to be issued on or before December 31, 2017, and 40% upon the delivery of the vessel, which at our option can be deferred until December 30, 2018. Also pursuant to this second amendment, we agreed to reimburse the shipyard for incremental costs in connection with the further deferment of the Q7000’s delivery. Incremental costs are capitalized as they are incurred during the construction of the vessel. At December 31, 2016, our total investment in the Q7000 was $194.6 million, including $69.2 million paid to the shipyard upon signing the contract and the $69.2 million installment payment in October 2016.
In February 2014, we entered into agreements with Petróleo Brasileiro S.A. (“Petrobras”) to provide well intervention services offshore Brazil, and in connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS (“Siem”) for two newbuild monohull vessels, the Siem Helix 1 and the Siem Helix 2. 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 term of the agreements with Petrobras is for four years with Petrobras’s options to extend. As part of Petrobras’s efforts to reduce its costs structure with many of its suppliers, we and Petrobras began discussions in mid-2015 with respect to potentially amending our contracts in a manner that addressed Petrobras’s objectives and was acceptable to us as well. Those negotiations were finalized in early June 2016 such that the contracts for the Siem Helix 1, originally scheduled to begin no later than July 22, 2016, were amended to commence between July 22, 2016 and October 21, 2016, with the day rate reduced to a mutually acceptable level, and the contracts for the Siem Helix 2, originally scheduled to begin no later than January 21, 2017, were amended to commence between October 1, 2017 and December 31, 2017, with no change in the day rate.
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The Siem Helix 1 vessel was delivered to us and the charter term began on June 14, 2016. The vessel has transited to Brazil after integration and commissioning of our topside equipment onboard. The Siem Helix 1 is continuing to work through Petrobras’s inspection and acceptance process, including the completion of modifications as agreed between us and Petrobras. Our current expectation is that the vessel will commence operations before the end of the first quarter of 2017. The Siem Helix 2 was delivered to us and the charter term began on February 10, 2017. We are currently integrating and commissioning our topside equipment onboard the vessel, and we anticipate that the vessel will be available for work in the second quarter of 2017 prior to commencing services for Petrobras in the fourth quarter of 2017. At December 31, 2016, our total investment in the topside equipment for the two vessels was $200.7 million. In November 2014, we paid a charter fee deposit of $12.5 million, which will be used to reduce our final charter payments for the Siem Helix 2.
Lease Commitments
We lease facilities and charter vessels under non-cancelable operating leases and vessel charters expiring at various dates through 2031. Future minimum rentals at December 31, 2016 are as follows (in thousands):

| Vessels |  | Facilities and Other |  | Total
2017 | $ | 156,446 |  |  | $ | 5,788 |  |  | $ | 162,234 |
2018 | 142,407 |  |  | 5,163 |  |  | 147,570 |
2019 | 131,665 |  |  | 5,123 |  |  | 136,788 |
2020 | 111,650 |  |  | 4,753 |  |  | 116,403 |
2021 | 99,563 |  |  | 4,667 |  |  | 104,230 |
Thereafter | 149,861 |  |  | 19,566 |  |  | 169,427 |
Total lease commitments | $ | 791,592 |  |  | $ | 45,060 |  |  | $ | 836,652 |

For the years ended December 31, 2016, 2015 and 2014, total rental expense was approximately $87.8 million, $134.3 million and $147.2 million, respectively.
We sublease some of our facilities under non-cancelable sublease agreements. For the years ended December 31, 2016, 2015 and 2014, total rental income was $1.6 million, $1.4 million and $0.8 million, respectively. As of December 31, 2016, the minimum rentals to be received in the future totaled $2.0 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.
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
On July 31, 2015, a purported stockholder, Parviz Izadjoo, filed a class action lawsuit styled Parviz Izadjoo v. Owen Kratz and Helix Energy Solutions Group, Inc. against the Company and Mr. Kratz, our President and Chief Executive Officer, in the United States District Court for the Southern District of Texas on behalf of a putative class of all purchasers of shares of our common stock between October 21, 2014, and July 21, 2015, inclusive (the “Class Period”). The lawsuit asserted violations of Section 10(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”) and SEC Rule 10b-5 as to both us and Mr. Kratz, and Section 20(a) of the Exchange Act against Mr. Kratz, based on alleged misrepresentations and omissions in SEC filings and other public disclosures regarding projections for 2015 dry docks of two of our vessels working in the Gulf of Mexico that allegedly caused the price at which putative class members bought stock during the proposed class period to be artificially inflated. On January 28, 2016, the judge in the case approved a motion for the appointment of lead plaintiff and lead counsel. On March 14, 2016, the plaintiffs filed an amended class action complaint, adding Mr. Tripodo (our Executive Vice President and Chief Financial Officer) and Mr. Chamblee (our former Executive Vice
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President and Chief Operating Officer) as individual defendants, alleging the same types of claims made in the original complaint (alleged violations during the Class Period of Section 10(b) of the Exchange Act and SEC Rule 10b-5 with respect to all defendants, and Section 20(a) of the Exchange Act against the individual defendants), but asserting that the alleged misrepresentations and omissions in SEC filings and other public disclosures are related to the condition of and repairs to certain equipment aboard the Q4000 vessel. The defendants filed a motion to dismiss on April 28, 2016, and on February 14, 2017, the defendants’ motion to dismiss the complaint was granted. The dismissal was without prejudice, with leave for plaintiff to amend the complaint by no later than March 17, 2017.
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. In addition, from time to time we incur other claims, such as contract disputes, in the normal course of business.
Note 15 — Statement of Cash Flow Information
The following table provides supplemental cash flow information (in thousands):

| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Interest paid, net of interest capitalized | $ | 18,749 |  |  | $ | 14,555 |  |  | $ | 11,628 |
Income taxes paid | 5,635 |  |  | 16,905 |  |  | 70,509 |

Our non-cash investing activities include property and equipment capital expenditures that are incurred but not yet paid. As of December 31, 2016 and 2015, these non-cash capital expenditures totaled $10.1 million and $18.7 million, respectively. Additionally, our non-cash investing activities for the year ended December 31, 2014 included a $27.5 million non-cash transaction related to the promissory note we received in connection with the sale of our Ingleside spoolbase in January 2014 (Note 4).
Note 16 — 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, 2016 (in thousands):

| Allowance for Uncollectible Accounts |  | Deferred Tax Asset Valuation Allowance
Balance at December 31, 2013 | $ | 2,234 |  |  | $ | 22,860 |
Additions (1) | 5,331 |  |  | — |
Deductions (2) | (2,830 | ) |  | — |
Adjustments | — |  |  | 216 |
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 |

(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.

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(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 for which insufficient future taxable income exists to offset the losses.

Our allowance accounts as of December 31, 2016 also included $4.2 million related to a non-current note receivable (Note 3). See Note 2 for a detailed discussion regarding our accounting policy on accounts and notes receivable and allowance for uncollectible accounts and Note 8 for a detailed discussion of the valuation allowance related to our deferred tax assets.
Note 17 — Fair Value Measurements
Assets and liabilities measured at fair value are based on one or more of three valuation approaches as follows:

(a) | Market Approach. Prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

(b) | Cost Approach. Amount that would be required to replace the service capacity of an asset (replacement cost).

(c) | Income Approach. Techniques to convert expected future cash flows to a single present amount based on market expectations (including present value techniques, option-pricing and excess earnings models).

Our financial instruments include cash and cash equivalents, receivables, accounts payable, long-term debt and 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 net carrying amount of our long-term note receivable also approximates its fair value. The following tables provide additional information relating to other financial instruments measured at fair value on a recurring basis (in thousands):

| Fair Value Measurements at December 31, 2016 Using |  |  |  | Valuation Approach
| Level 1 |  | Level 2 (1) |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |
Interest rate swaps | $ | — |  |  | $ | 451 |  |  | $ | — |  |  | $ | 451 |  |  | (c)
Liabilities: |  |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | 38,170 |  |  | — |  |  | 38,170 |  |  | (c)
Interest rate swaps | — |  |  | 751 |  |  | — |  |  | 751 |  |  | (c)
Total net liability | $ | — |  |  | $ | 38,470 |  |  | $ | — |  |  | $ | 38,470 |  |  |

| Fair Value Measurements at December 31, 2015 Using |  |  |  | Valuation Approach
| Level 1 |  | Level 2 (1) |  | Level 3 |  | Total |
Assets: |  |  |  |  |  |  |  |  |
Interest rate swaps | $ | — |  |  | $ | 413 |  |  | $ | — |  |  | $ | 413 |  |  | (c)
Liabilities: |  |  |  |  |  |  |  |  |
Foreign exchange contracts | — |  |  | 61,427 |  |  | — |  |  | 61,427 |  |  | (c)
Interest rate swaps | — |  |  | 1,473 |  |  | — |  |  | 1,473 |  |  | (c)
Total net liability | $ | — |  |  | $ | 62,487 |  |  | $ | — |  |  | $ | 62,487 |  |  |

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(1) | Unless otherwise indicated, the fair value of our Level 2 derivative instruments 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. These modeling techniques require us to make estimations of future prices, price correlation and market volatility and liquidity based on market data. Our actual results may differ from our estimates, and these differences could be positive or negative. See Note 18 for further discussion on fair value of our derivative instruments.

The carrying values and estimated fair values of our long-term debt are as follows (in thousands):

| December 31,
| 2016 |  | 2015
| Carrying Value (1) |  | Fair Value (2) |  | Carrying Value (1) |  | Fair Value (2)
Term Loan (matures June 2018) | $ | 192,258 |  |  | $ | 192,258 |  |  | $ | 255,000 |  |  | $ | 248,467 |
Nordea Q5000 Loan (matures April 2020) | 196,429 |  |  | 192,746 |  |  | 232,143 |  |  | 221,553 |
MARAD Debt (matures February 2027) | 83,222 |  |  | 92,049 |  |  | 89,148 |  |  | 104,897 |
2022 Notes (mature May 2022) | 125,000 |  |  | 130,156 |  |  | — |  |  | — |
2032 Notes (mature March 2032) | 60,115 |  |  | 59,965 |  |  | 200,000 |  |  | 150,250 |
Total debt | $ | 657,024 |  |  | $ | 667,174 |  |  | $ | 776,291 |  |  | $ | 725,167 |

(1) | Carrying value includes current maturities and excludes the related unamortized debt discount and debt issuance costs. See Note 7 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 Term Loan, the Nordea Q5000 Loan and the MARAD Debt was estimated using Level 2 fair value inputs under the market approach. The fair value of the Term Loan, the Nordea Q5000 Loan and the MARAD Debt 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 18 — Derivative Instruments and Hedging Activities
The following table presents the balance sheet location and fair value of our derivative instruments that were designated as hedging instruments (in thousands):

| December 31,
| 2016 |  | 2015
| Balance Sheet Location |  | Fair Value |  | Balance Sheet Location |  | Fair Value
Asset Derivative Instruments: |  |  |  |  |  |  |
Interest rate swaps | Other assets, net |  | $ | 451 |  |  | Other assets, net |  | $ | 413 |
|  |  | $ | 451 |  |  |  |  | $ | 413 |
Liability Derivative Instruments: |  |  |  |  |  |
Foreign exchange contracts | Accrued liabilities |  | $ | 14,056 |  |  | Accrued liabilities |  | $ | 14,955 |
Interest rate swaps | Accrued liabilities |  | 751 |  |  | Accrued liabilities |  | 1,473 |
Foreign exchange contracts | Other non-current liabilities |  | 13,383 |  |  | Other non-current liabilities |  | 28,458 |
|  |  | $ | 28,190 |  |  |  |  | $ | 44,886 |

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

| December 31,
| 2016 |  | 2015
| Balance Sheet Location |  | Fair Value |  | Balance Sheet Location |  | Fair Value
Liability Derivative Instruments: |  |  |  |  |  |
Foreign exchange contracts | Accrued liabilities |  | $ | 3,923 |  |  | Accrued liabilities |  | $ | 6,763 |
Foreign exchange contracts | Other non-current liabilities |  | 6,808 |  |  | Other non-current liabilities |  | 11,251 |
|  |  | $ | 10,731 |  |  |  |  | $ | 18,014 |

In January 2013, we entered into foreign currency exchange contracts to hedge through September 2017 the foreign currency exposure associated with the Grand Canyon charter payments ($104.6 million) denominated in Norwegian kroner (NOK 591.3 million). 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 Grand Canyon III charter payments ($100.4 million and $98.8 million, respectively) denominated in Norwegian kroner (NOK 594.7 million and NOK 595.0 million, respectively), through July 2019 and February 2020, respectively.
During discussions with the owner of the Grand Canyon, Grand Canyon II and Grand Canyon III vessels with respect to amending the charter agreements, it became apparent in December 2015 that a portion of previously forecasted charter payments in NOK would no longer be made. We concluded that the foreign currency exchange contracts associated with the charter payments for the Grand Canyon still qualified for cash flow hedge accounting treatment. However, the foreign currency exchange contracts associated with the charter payments for the Grand Canyon II and Grand Canyon III vessels no longer qualified as cash flow hedges. As a result, we de-designated these hedges and re-designated the hedging relationship between a portion of our foreign currency exchange contracts and our forecasted Grand Canyon II and Grand Canyon III charter payments of NOK 434.1 million and NOK 185.2 million, respectively, that were expected to remain highly probable of occurring. Our Accumulated OCI (net of tax) as of December 31, 2015 included unrealized losses of $19.8 million associated with the re-designated foreign currency exchange contracts that qualify for hedge accounting treatment. 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 statement of operations are these unrealized losses, as well as subsequent changes in unrealized losses associated with the foreign currency exchange contracts that are no longer designated as cash flow hedges.
Hedge ineffectiveness also is reflected in “Other income (expense), net” in the accompanying consolidated statement of operations. For the year ended December 31, 2016, we recorded realized gains of $0.1 million related to the Grand Canyon hedge ineffectiveness. There were no unrealized gains or losses associated with hedge ineffectiveness. For the year ended December 31, 2015, we recorded realized losses of $3.6 million related to the Grand Canyon II and Grand Canyon III hedge ineffectiveness and unrealized losses of $1.5 million related to the Grand Canyon hedge ineffectiveness. For the year ended December 31, 2014, we recorded realized losses of $0.5 million and unrealized losses of $1.2 million related to the Grand Canyon II hedge ineffectiveness.
In September 2013, we entered into various interest rate swap contracts to fix the interest rate on $148.1 million of our Term Loan borrowings (Note 7). The term 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 7). 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.
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The following tables present the impact that derivative instruments designated as hedging instruments had on our Accumulated OCI (net of tax) and our consolidated statements of operations (in thousands). We estimate that as of December 31, 2016, $9.6 million of 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)
| Year Ended December 31,
| 2016 |  | 2015 |  | 2014
Foreign exchange contracts | $ | 9,397 |  |  | $ | 4,734 |  |  | $ | (22,170 | )
Interest rate swaps | 473 |  |  | (534 | ) |  | 70 |
| $ | 9,870 |  |  | $ | 4,200 |  |  | $ | (22,100 | )

| Location of Loss Reclassified from Accumulated OCI into Earnings |  | Loss Reclassified from Accumulated OCI into Earnings (Effective Portion)
|  | Year Ended December 31,
|  | 2016 |  | 2015 |  | 2014
Foreign exchange contracts | Cost of sales |  | $ | (10,827 | ) |  | $ | (11,516 | ) |  | $ | (2,507 | )
Interest rate swaps | Net interest expense |  | (2,024 | ) |  | (2,143 | ) |  | (858 | )
|  |  | $ | (12,851 | ) |  | $ | (13,659 | ) |  | $ | (3,365 | )

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

| Location of Gain (Loss) Recognized in Earnings on Derivative Instruments |  | Gain (Loss) Recognized in Earnings on Derivative Instruments
|  | Year Ended December 31,
|  | 2016 |  | 2015 |  | 2014
Foreign exchange contracts | Other income (expense), net |  | $ | 1,198 |  |  | $ | (18,014 | ) |  | $ | 7 |
|  |  | $ | 1,198 |  |  | $ | (18,014 | ) |  | $ | 7 |

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Note 19 — Quarterly Financial Information (Unaudited)
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. 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. 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,
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) applicable to common shareholders (1) | (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 | )

| Quarter Ended
| March 31, |  | June 30, |  | September 30, |  | December 31,
2015 |  |  |  |  |  |  |
Net revenues | $ | 189,641 |  |  | $ | 166,016 |  |  | $ | 182,462 |  |  | $ | 157,683 |
Gross profit (loss) (2) | 34,947 |  |  | 24,208 |  |  | 31,969 |  |  | (324,898 | )
Net income (loss) applicable to common shareholders (3) | 19,642 |  |  | (2,635 | ) |  | 9,880 |  |  | (403,867 | )
Basic earnings (loss) per common share | $ | 0.19 |  |  | $ | (0.03 | ) |  | $ | 0.09 |  |  | $ | (3.83 | )
Diluted earnings (loss) per common share | $ | 0.19 |  |  | $ | (0.03 | ) |  | $ | 0.09 |  |  | $ | (3.83 | )

(1) | Amount in the fourth quarter of 2016 included a $45.1 million goodwill impairment charge related to our robotics reporting unit (Notes 2 and 6).

(2) | Amount in the fourth quarter of 2015 included impairment charges of $205.2 million for the Helix 534 and $133.4 million for the HP I and $6.3 million for certain capitalized vessel project costs (Note 4).

(3) | Amount in the fourth quarter of 2015 included a $16.4 million goodwill impairment charge related to our U.K. well intervention reporting unit (Notes 2 and 6), losses totaling $123.8 million related to our equity investments in Deepwater Gateway and Independence Hub (Note 5), and unrealized losses totaling $19.0 million on our foreign currency exchange contracts associated with the Grand Canyon, Grand Canyon II and Grand Canyon III chartered vessels (Note 18).

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
On May 24, 2016, we dismissed Ernst & Young LLP as our independent registered public accounting firm. There was no dispute or disagreement with the firm on any issue. On May 26, 2016, we appointed KPMG LLP as our new independent registered public accounting firm to perform independent audit services for the fiscal year ended December 31, 2016.
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”). 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, 2016 to provide reasonable assurance that 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’s rules and forms; and (ii) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.
(b) Management’s Report on Internal Control over Financial Reporting. Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Securities Exchange Act of 1934, as amended. 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. This process includes policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. 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 (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 risk 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, 2016. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management concluded that, as of December 31, 2016, our internal control over financial reporting was effective based on those criteria.
The effectiveness of our internal control over financial reporting as of December 31, 2016 has been audited by KPMG LLP, our independent registered public accounting firm, as stated in its report which appears in Item 8 of this Annual Report on Form 10-K.
(c) Changes in Internal Control over Financial Reporting. There were no changes in our internal control over financial reporting during the fourth quarter of fiscal 2016 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
None.
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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 2017 Annual Meeting of Shareholders to be held on May 11, 2017. See also “Executive Officers of the Company” appearing in Part I of this Annual Report.
Code of Ethics
We have adopted a Code of Business Conduct and Ethics for all directors, officers and employees as well as a Code of Ethics for Chief Executive Officer and Senior Financial Officers specific to those officers. Copies of these documents are available at our Website www.helixesg.com under Corporate Governance. Interested parties may also request a free copy of these documents from:
Helix Energy Solutions Group, Inc.
ATTN: Corporate Secretary
3505 W. Sam Houston Parkway N., Suite 400
Houston, Texas 77043
Item 11. Executive Compensation
The information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 in connection with our 2017 Annual Meeting of Shareholders to be held on May 11, 2017.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
The information required by this Item is incorporated by reference to our definitive Proxy Statement to be filed pursuant to Regulation 14A under the Securities Exchange Act of 1934 in connection with our 2017 Annual Meeting of Shareholders to be held on May 11, 2017.
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 2017 Annual Meeting of Shareholders to be held on May 11, 2017.
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 2017 Annual Meeting of Shareholders to be held on May 11, 2017.
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PART IV
Item 15. Exhibits and Financial Statement Schedules
(1) Financial Statements
The following financial statements included on pages 49 through 94 in this Annual Report are for the fiscal year ended December 31, 2016.

• | 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, 2016 and 2015

• | Consolidated Statements of Operations for the Years Ended December 31, 2016, 2015 and 2014

• | Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2016, 2015 and 2014

• | Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014

• | Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014

• | 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.
Item 16. Form 10-K Summary
None.
(2) Exhibits
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. Reference is made to Exhibit listing beginning on page 99 hereof.
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SIGNATURES
Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

| HELIX ENERGY SOLUTIONS GROUP, INC. |
| By: | /s/ ANTHONY TRIPODO |
|  | Anthony Tripodo |
|  | Executive Vice President and |
|  | Chief Financial Officer |

February 24, 2017
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 24, 2017
Owen Kratz |  |  |
/s/ ANTHONY TRIPODO |  | Executive Vice President, Chief Financial Officer and Director (principal financial officer) |  | February 24, 2017
Anthony Tripodo |  |  |
/s/ ERIK STAFFELDT |  | Vice President — Finance and Accounting (principal accounting officer) |  | February 24, 2017
Erik Staffeldt |  |  |
/s/ JOHN V. LOVOI |  | Director |  | February 24, 2017
John V. Lovoi |  |  |
/s/ T. WILLIAM PORTER |  | Director |  | February 24, 2017
T. William Porter |  |  |
/s/ NANCY K. QUINN |  | Director |  | February 24, 2017
Nancy K. Quinn |  |  |
/s/ JAN A. RASK |  | Director |  | February 24, 2017
Jan A. Rask |  |  |
/s/ WILLIAM L. TRANSIER |  | Director |  | February 24, 2017
William L. Transier |  |  |
/s/ JAMES A. WATT |  | Director |  | February 24, 2017
James A. Watt |  |  |

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INDEX TO EXHIBITS

Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
3.1 |  | 2005 Amended and Restated Articles of Incorporation, as amended, of registrant. |  | Exhibit 3.1 to the Current Report on Form 8-K filed on March 1, 2006 (000-22739)
3.2 |  | Second Amended and Restated By-Laws of Helix, as amended. |  | Exhibit 3.1 to the Current Report on Form 8-K filed on September 28, 2006 (001-32936)
4.1 |  | Form of Common Stock certificate. |  | Exhibit 4.7 to the Form 8-A filed on June 30, 2006 (001-32936)
4.2 |  | Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of August 16, 2000. |  | Exhibit 4.4 to the 2001 Form 10-K filed on March 28, 2002 (000-22739)
4.3 |  | Amendment No. 1 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of January 25, 2002. |  | Exhibit 4.9 to the 2002 Form 10-K/A filed on April 8, 2003 (000-22739)
4.4 |  | Amendment No. 2 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of November 15, 2002. |  | Exhibit 4.4 to the Form S-3 filed on February 26, 2003 (333-103451)
4.5 |  | Amendment No. 3 Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of July 31, 2003. |  | Exhibit 4.12 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.6 |  | Amendment No. 4 to Credit Agreement among Cal Dive I-Title XI, Inc., GOVCO Incorporated, Citibank N.A. and Citibank International LLC dated as of December 15, 2004. |  | Exhibit 4.13 to the 2004 Form 10-K filed on March 16, 2005 (000-22739)
4.7 |  | Registration Rights Agreement dated as of March 30, 2005, between Cal Dive International, Inc. and Banc of America Securities LLC, as representative of the initial purchasers. |  | Exhibit 4.3 to the Current Report on Form 8-K filed on April 4, 2005 (000-22739)
4.8 |  | Trust Indenture, dated as of August 16, 2000, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.9 |  | Supplement No. 1 to Trust Indenture, dated as of January 25, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.2 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.10 |  | Supplement No. 2 to Trust Indenture, dated as of November 15, 2002, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.3 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.11 |  | Supplement No. 3 to Trust Indenture, dated as of December 14, 2004, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.4 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.12 |  | Supplement No. 4 to Trust Indenture, dated September 30, 2005, between Cal Dive I-Title XI, Inc. and Wilmington Trust, as Indenture Trustee. |  | Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.13 |  | Form of United States Government Guaranteed Ship Financing Bonds, Q4000 Series 4.93% Sinking Fund Bonds Due February 1, 2027. |  | Exhibit A to Exhibit 4.5 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.14 |  | Form of Third Amended and Restated Promissory Note to United States of America. |  | Exhibit 4.6 to the Current Report on Form 8-K filed on October 6, 2005 (000-22739)
4.15 |  | Indenture dated as of March 12, 2012 between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as Trustee. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on March 12, 2012 (001-32936)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
4.16 |  | Credit Agreement dated June 19, 2013 by and among Helix Energy Solutions Group, Inc., as borrower, Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, and other lender parties named thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on June 19, 2013 (001-32936)
4.17 |  | Amendment No. 1 to the Credit Agreement, dated as of May 13, 2015, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on May 14, 2015 (001-32936)
4.18 |  | Amendment No. 2 to the Credit Agreement, dated as of January 19, 2016, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on January 25, 2016 (001-32936)
4.19 |  | Amendment No. 3 to the Credit Agreement, dated as of February 9, 2016, by and among Helix Energy Solutions Group, Inc. and Bank of America, N.A., as administrative agent, swing line lender and letters of credit issuer, together with the other lenders party thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on February 11, 2016 (001-32936)
4.20 |  | Credit Agreement dated September 26, 2014, by and among Helix Q5000 Holdings S.à r.l., Helix Vessel Finance S.à r.l. and Nordea Bank Finland PLC, London Branch as administrative agent and collateral agent, together with the other lenders party thereto. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on September 30, 2014 (001-32936)
4.21 |  | Senior Debt Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee. |  | Exhibit 4.1 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
4.22 |  | First Supplemental Indenture, dated as of November 1, 2016, by and between Helix Energy Solutions Group, Inc. and The Bank of New York Mellon Trust Company, N.A., as trustee. |  | Exhibit 4.2 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
10.1 * |  | 1995 Long Term Incentive Plan, as amended. |  | Exhibit 10.3 to the Form S-1 filed on September 4, 1996 (333-11399)
10.2 * |  | Amendment to 1995 Long Term Incentive Plan of Helix Energy Solutions Group, Inc. |  | Exhibit 10.2 to the 2008 Form 10-K filed on March 2, 2009 (001-32936)
10.3 * |  | 2009 Long-Term Incentive Cash Plan of Helix Energy Solutions Group, Inc. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2009 (001-32936)
10.4 * |  | Form of Award Letter related to the 2009 Long-Term Incentive Cash Plan. |  | Exhibit 10.2 to the Current Report on Form 8-K filed on January 6, 2009 (001-32936)
10.5 * |  | Helix 2005 Long Term Incentive Plan, including the Form of Restricted Stock Award Agreement. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on May 12, 2005 (000-22739)
10.6 * |  | Amendment to 2005 Long Term Incentive Plan of Helix Energy Solutions Group, Inc. |  | Exhibit 10.10 to the 2008 Form 10-K filed on March 2, 2009 (001-32936)
10.7 * |  | Amended and Restated 2005 Long-Term Incentive Plan of Helix Energy Solutions Group, Inc. dated May 9, 2012. |  | Exhibit 10.3 to the Quarterly Report on Form 10-Q filed on July 25, 2012 (001-32936)
10.8 * |  | 2005 Long-Term Incentive Plan, as Amended and Restated Effective January 1, 2017. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on December 5, 2016 (001-32936)
10.9 * |  | Form of Cash Award Agreement. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on December 15, 2011 (001-32936)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.10 * |  | Form of Performance Share Unit Award Agreement. |  | Exhibit 10.2 to the Current Report on Form 8-K filed on December 5, 2016 (001-32936)
10.11 * |  | Form of Restricted Stock Award Agreement. |  | Exhibit 10.3 to the Current Report on Form 8-K filed on December 15, 2011 (001-32936)
10.12 * |  | Employee Stock Purchase Plan of Helix Energy Solutions Group, Inc. dated May 9, 2012. |  | Exhibit 10.4 to the Quarterly Report on Form 10-Q filed on July 25, 2012 (001-32936)
10.13 * |  | Amendment to the Helix Energy Solutions Group, Inc. Employee Stock Purchase Plan. |  | Exhibit 10.12 to the 2015 Form 10-K filed on February 29, 2016 (001-32936)
10.14 * |  | Employment Agreement between Owen Kratz and the Company dated February 28, 1999. |  | Exhibit 10.5 to the 1998 Form 10-K filed on March 31, 1999 (000-22739)
10.15 * |  | Employment Agreement between Owen Kratz and the Company dated November 17, 2008. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on November 19, 2008 (001-32936)
10.16 * |  | Employment Agreement between Alisa B. Johnson and the Company dated November 17, 2008. |  | Exhibit 10.3 to the Current Report on Form 8-K filed on November 19, 2008 (001-32936)
10.17 * |  | Employment Agreement between Anthony Tripodo and the Company dated June 25, 2008. |  | Exhibit 10.2 to the Current Report on Form 8-K filed on June 30, 2008 (001-32936)
10.18 * |  | First Amendment to Employment Agreement between Anthony Tripodo and the Company dated November 17, 2008. |  | Exhibit 10.5 to the Current Report on Form 8-K filed on November 19, 2008 (001-32936)
10.19 * |  | Employment Agreement by and between Helix Energy Solutions Group, Inc. and Clifford Chamblee dated May 11, 2011. |  | Exhibit 10.3 to the Quarterly Report on Form 10-Q filed on July 27, 2011 (001-32936)
10.20 * |  | Employment Agreement by and between Helix Energy Solutions Group, Inc. and Scotty Sparks dated May 11, 2015. |  | Exhibit 10.1 to the Current Report on Form 8-K/A filed on May 12, 2015 (001-32936)
10.21 * |  | Deferred Compensation Agreement by and between Helix Energy Solutions Group, Inc. and Scotty Sparks dated January 1, 2012. |  | Exhibit 10.2 to the Current Report on Form 8-K/A filed on May 12, 2015 (001-32936)
10.22 |  | Equity Distribution Agreement dated April 25, 2016 between Helix Energy Solutions Group, Inc. and Wells Fargo Securities LLC. |  | Exhibit 1.1 to the Current Report on Form 8-K filed on April 25, 2016 (001-32936)
10.23 |  | Equity Distribution Agreement dated August 11, 2016 between Helix Energy Solutions Group, Inc. and Wells Fargo Securities LLC. |  | Exhibit 1.1 to the Current Report on Form 8-K filed on August 11, 2016 (001-32936)
10.24 |  | Underwriting Agreement dated as of October 26, 2016, between Helix Energy Solutions Group, Inc. and Raymond James & Associates, Inc. |  | Exhibit 1.1 to the Current Report on Form 8-K filed on November 1, 2016 (001-32936)
10.25 |  | Underwriting Agreement dated as of January 4, 2017, between Helix Energy Solutions Group, Inc. and Credit Suisse Securities (USA) LLC and Wells Fargo Securities, LLC, as representatives of the several underwriters named therein. |  | Exhibit 1.1 to the Current Report on Form 8-K filed on January 6, 2017 (001-32936)
10.26 |  | Equity Purchase Agreement dated December 12, 2012, between Helix Energy Solutions Group, Inc. and Talos Production LLC. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on December 13, 2012 (001-32936)
10.27 |  | Form of Indemnification Agreement, by and among Talos Production LLC, Energy Resource Technology GOM, LLC, CKB Petroleum, LLC, and Helix Energy Solutions Group, Inc. |  | Exhibit 10.3 to the Current Report on Form 8-K filed on December 13, 2012 (001-32936)
10.28 |  | Amendment No. 1 to Equity Purchase Agreement dated January 27, 2013, between Helix Energy Solutions Group, Inc. and Talos Production LLC. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on January 28, 2013 (001-32936)

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Exhibits |  | Description |  | Filed or Furnished Herewith or Incorporated by Reference from the Following Documents (Registration or File Number)
10.29 |  | Amendment No. 2 to Equity Purchase Agreement dated February 6, 2013, between Helix Energy Solutions Group, Inc. and Talos Production LLC. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on February 12, 2013 (001-32936)
10.30 |  | Construction contract dated as of March 12, 2012 between Helix Energy Solution Group, Inc. and Jurong Shipyard Pte Ltd. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on March 16, 2012 (001-32936)
10.31 |  | Construction Contract dated as of September 11, 2013 between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on September 13, 2013 (001-32936)
10.32 |  | Amendment No. 1, dated as of June 8, 2015, to Construction Contract between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on June 11, 2015 (001-32936)
10.33 |  | Amendment No. 2, dated December 2, 2015, to Construction Contract between Helix Q7000 Vessel Holdings S.à r.l. and Jurong Shipyard Pte Ltd. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on December 7, 2015 (001-32936)
10.34 |  | Strategic Alliance Agreement dated January 5, 2015 among Helix Energy Solutions Group, Inc., OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V., and Schlumberger Oilfield Holdings Ltd. |  | Exhibit 10.1 to the Current Report on Form 8-K filed on January 6, 2015 (001-32936)
14.1 |  | Code of Ethics for Chief Executive Officer and Senior Financial Officers. |  | Exhibit 14.1 to the Registrant’s Current Report on Form 8-K filed on December 8, 2009 (001-32936)
16.1 |  | Letter from Ernst & Young LLP to the Securities and Exchange Commission dated May 26, 2016. |  | Exhibit 16.1 to the Current Report on Form 8-K filed on May 26, 2016 (001-32936)
21.1 |  | List of Subsidiaries of the Company. |  | Filed herewith
23.1 |  | Consent of KPMG LLP. |  | Filed herewith
23.2 |  | Consent of Ernst & Young LLP. |  | Filed herewith
23.3 |  | Consent of Deloitte & Touche LLP (Deepwater Gateway L.L.C.). |  | Filed herewith
23.4 |  | Consent of Deloitte & Touche LLP (Independence Hub LLC). |  | Filed herewith
31.1 |  | Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Owen Kratz, Chief Executive Officer. |  | Filed herewith
31.2 |  | Certification Pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934 by Anthony Tripodo, Chief Financial Officer. |  | Filed herewith
32.1 |  | Certification of Helix’s Chief Executive Officer and Chief Financial Officer pursuant to Section 906 of the Sarbanes — Oxley Act of 2002. |  | Furnished herewith
101.INS |  | XBRL Instance Document. |  | Furnished herewith
101.SCH |  | XBRL Schema Document. |  | Furnished herewith
101.CAL |  | XBRL Calculation Linkbase Document. |  | Furnished herewith
101.PRE |  | XBRL Presentation Linkbase Document. |  | Furnished herewith
101.DEF |  | XBRL Definition Linkbase Document. |  | Furnished herewith
101.LAB |  | XBRL Label Linkbase Document. |  | Furnished herewith

* | Management contracts or compensatory plans or arrangements

102