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EX-23.3 - CONSENT OF DELOITTE & TOUCHE LLP (INDEPENDENCE HUB LLC) - HELIX ENERGY SOLUTIONS GROUP INCexh23-3.htm
EX-31.1 - RULE 13A-14 (A) CERTIFICATION - CEO - OWEN KRATZ - HELIX ENERGY SOLUTIONS GROUP INCexh31-1.htm
EX-21.1 - LIST OF SUBSIDIARIES - HELIX ENERGY SOLUTIONS GROUP INCexh21-1.htm
EX-23.1 - CONSENT OF ERNST & YOUNG LLP - HELIX ENERGY SOLUTIONS GROUP INCexh23-1.htm
EXCEL - IDEA: XBRL DOCUMENT - HELIX ENERGY SOLUTIONS GROUP INCFinancial_Report.xls
EX-31.2 - RULE 13A-14(A) CERTIFICATION - CFO - ANTHONY TRIPODO - HELIX ENERGY SOLUTIONS GROUP INCexh31-2.htm
EX-32.1 - SECTION 906 CERTIFICATIONS - CEO AND CFO - HELIX ENERGY SOLUTIONS GROUP INCexh32-1.htm
EX-23.2 - CONSENT OF DELOITTE & TOUCHE LLP (DEEPWATER GATEWAY L.L.C.) - HELIX ENERGY SOLUTIONS GROUP INCexh23-2.htm


 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
Form 10-K
 
 
R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the fiscal year ended December 31, 2014
OR
   
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from                                                                           to
 
Commission File Number 001-32936
 
 
HELIX ENERGY SOLUTIONS GROUP, INC.
(Exact name of registrant as specified in its charter)
 
Minnesota
95-3409686
(State or other jurisdiction
of incorporation or organization)
(I.R.S. Employer
Identification No.)
   
3505 West Sam Houston Parkway North Suite 400
77043
Houston, Texas
(Address of principal executive offices)
(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.   R 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  R 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.  R 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). R 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 R
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  R 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, 2014 was approximately $2.6 billion.
 
The number of shares of the registrant’s Common Stock outstanding as of February 13, 2015 was 105,906,969.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive Proxy Statement for the Annual Meeting of Shareholders to be held on May 7, 2015 are incorporated by reference into Part III hereof.
 
 


 
 

 
 
HELIX ENERGY SOLUTIONS GROUP, INC. INDEX — FORM 10-K
 
 
   
Page
PART I
Business                                                                 
Risk Factors                                                               
Unresolved Staff Comments                                    
Properties                                                  
Mine Safety Disclosures                   
Executive Officers of the Company                
PART II
Financial Statements and Supplementary Data                 
 
 
 
 
 
 
 
 
PART III
PART IV
Exhibits, Financial Statement Schedules                      
 
Signatures                                                    
 
 
 
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 is subject to change;
 
 
statements relating to the construction, upgrades or acquisition of vessels or equipment and any anticipated costs related thereto, including the construction of our Q5000 and Q7000 vessels and the construction of two chartered vessels to be used in connection with our contracts to provide well intervention services offshore Brazil (Note 11).  For more information regarding our vessel construction activity, see Item 1. Business “— Our Operations”;
 
 
statements regarding projections of revenues, gross margin, expenses, earnings or losses, working capital or other financial items;
 
 
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 the collectability of our trade receivables;
 
 
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 related to our ability to retain key members of our senior management and key employees;
 
 
statements related to 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 these 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, among other things:
 
 
 
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;
 
 
unexpected delays in the delivery or chartering of new vessels for our well intervention and robotics fleet, including the Q5000, the Q7000, the Grand Canyon II and the Grand Canyon III and the two newbuild chartered vessels to be used to perform contracted well intervention work in 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 results of our continuing efforts to control costs and improve performance;
 
 
the success of our risk management activities;
 
 
the effects of competition;
 
 
the impact of current and future laws and governmental regulations, including tax and accounting developments;
 
 
the effect of adverse weather conditions and/or other risks associated with marine operations;
 
 
the effectiveness of our current and future hedging activities;
 
 
the long-term availability (or lack thereof) of capital (including any financing) to fund our business strategy and/or operations;
 
 
the effects of our indebtedness;
 
 
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 15 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 the state of Minnesota in 1979.  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 developing offshore reservoirs and maximizing production economics.  Our “life of field” services are segregated into four disciplines: well intervention, robotics, production facilities and subsea construction.  We primarily conduct operations in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.  For additional information regarding our strategy and business operations, see sections titled “Our Strategy” and “Our Operations” included elsewhere within Item 1. Business of this Annual Report.
 
Our principal executive offices are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas 77043; our phone number is 281-618-0400.  Our common stock trades on the New York Stock Exchange (“NYSE”) under the ticker symbol “HLX.”  Our Chief Executive Officer submitted the annual CEO certification to the NYSE as required under its Listed Company Manual in May 2014.  Our principal executive officer and our principal financial officer have made the certifications required under Section 302 of the Sarbanes-Oxley Act, which are included as exhibits to this Annual Report.
 
Please refer to the subsection “— Certain Definitions” on page 13 for definitions of additional terms commonly used in this Annual Report.  Unless otherwise indicated any reference to Notes herein refers to Notes to Consolidated Financial Statements in Item 8. Financial Statements and Supplementary Data located elsewhere in this Annual Report.
 
OUR STRATEGY
 
Our focus is on growing our well intervention and robotics businesses.  We believe that focusing on these services will deliver quality long-term financial returns.  We are making strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions.  The size of our well intervention fleet has increased with the addition of the Helix 534, which was placed in service in February 2014.  Our well intervention fleet will further expand following the completion of the two newbuild semi-submersible vessels currently under construction, the Q5000 and the Q7000, and the expected delivery in 2016 of two newbuild monohull vessels which we will charter in connection with the well intervention service agreements that we entered into with Petróleo Brasileiro S.A. (“Petrobras”) in February 2014.  In addition, we are expanding our robotics operations by acquiring additional remotely operated vehicles (“ROVs”) as well as chartering two newbuild ROV support vessels, the Grand Canyon II and the Grand Canyon III, both of which are scheduled for delivery in the first half of 2015.
 
On January 5, 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. (collectively, the “Parties”) 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.
 
 
OUR OPERATIONS
 
We have four reportable business segments: Well Intervention, Robotics, Production Facilities and Subsea Construction.  We provide a full range of services primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.  Our Well Intervention segment includes our vessels and equipment used to perform well intervention services primarily in the Gulf of Mexico and North Sea regions.  Our well intervention vessels include the Q4000, the Helix 534, the Seawell, the Well Enhancer and the Skandi Constructor, which is a chartered vessel.  Our Robotics segment currently operates four chartered vessels, and also includes ROVs, trenchers and ROVDrills designed to complement offshore subsea construction and well intervention services.  Our Production Facilities segment includes the Helix Producer I (the “HP I”), a dynamically positioned floating production vessel (which we now own 100% after acquiring in February 2014 our former minority partner’s noncontrolling interests in the entity that owns the vessel for $20.1 million), our equity investments in Deepwater Gateway, L.L.C. (“Deepwater Gateway”) and Independence Hub, LLC (“Independence Hub”), and the Helix Fast Response System (the “HFRS”).  All of our production facilities activities are located in the Gulf of Mexico.  Our Subsea Construction results have diminished following the sale of essentially all of our assets related to this reportable segment, including the sale in January 2014 of our spoolbase located in Ingleside, Texas.  See Note 12 for financial results associated with our business segments.  Previously, we had an additional business segment, Oil and Gas, which was sold in February 2013 (see “Discontinued Operations” below).  Our current services include:
 
 
 
Production.  Inspection, repair and maintenance of production structures, trees, jumpers, risers, pipelines and subsea equipment; well intervention; life of field support; and intervention engineering.
       
 
 
Reclamation.  Reclamation and remediation services; well plugging and abandonment services; pipeline abandonment services; and site inspections.
       
 
 
Development.  Installation of subsea pipelines, flowlines, control umbilicals, manifold assemblies and risers; 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 services to oil and gas companies, primarily those 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 (Note 5).  In addition to the services provided by our HP I vessel, we maintain equity investments in two production hub facilities in the Gulf of Mexico.
       
 
 
Fast Response System.  Provision of the HFRS as a response resource that can be identified in permit applications to federal and state agencies and called out in the event of a well control incident.
 
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 make capital expenditures for offshore exploration, drilling and production operations.  The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including but not limited to:
 
 
 
worldwide economic activity, including available access to global capital and capital markets;
 
 
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 shale oil and natural gas;
 
 
the cost of offshore exploration for and production and transportation of oil and natural gas;
 
 
the ability of oil and gas companies to generate funds or otherwise obtain external capital for exploration, development 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;
 
 
weather conditions;
 
 
environmental and other governmental regulations; and
 
 
domestic and international tax laws, regulations and policies.
 
Notwithstanding the recent sharp decline in oil and gas prices, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long-term increasing world demand for oil and natural gas emphasizing the need for continual production and the replacement thereof; (2) mature global production rates for offshore and subsea wells; (3) globalization of the natural gas market; (4) an increasing number of mature and small reservoirs; (5) increasing offshore activity, particularly in deepwater; and (6) an increasing number of subsea developments.
 
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 expand 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 vessels serve as work platforms for well intervention services at costs that are typically significantly 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.  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.
 
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 significant component in the Macondo well control and containment efforts.  The Q4000 also serves an important role in the HFRS that was established in 2011.  In August 2012, we acquired a drillship and subsequently performed upgrades and modifications to render it suitable for use as a well intervention vessel.  We renamed the vessel the Helix 534 and it commenced well intervention operations in February 2014.
 
In the North Sea, the Seawell has provided well intervention and abandonment services for hundreds of North Sea subsea wells since 1987.  The vessel is currently undergoing both its normal regulatory dry dock and certain capital upgrades that are intended to extend its useful economic life, and is scheduled to return to service in April 2015.  The Well Enhancer has performed well intervention, abandonment and coil tubing services since it joined our fleet in the North Sea region in 2009.  In April 2013, we chartered the Skandi Constructor for use in our North Sea operations.  The vessel was subsequently configured to perform well intervention operations and it commenced service in that capacity in September 2013.  The initial term of the charter will expire in March 2016.
 
In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semi-submersible well intervention vessel, the Q5000.  This shipyard contract fixed the majority of the construction costs for the Q5000.  The costs incurred under this contract are paid at contractually scheduled intervals, with the last remaining payment coming due when the vessel is delivered, which is expected to occur in the second quarter of 2015. We currently anticipate the Q5000 being available to perform well intervention services in the second half of 2015.  In September 2014, a credit agreement for a term loan in an amount of up to $250 million was entered into to partially finance the construction of the Q5000 and other future capital projects.  The term loan will be funded at or near the time of the delivery of the Q5000.
 
In September 2013, we executed a second contract with the same shipyard in Singapore that is currently constructing the Q5000.  This contract provides for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which will be built to North Sea standards.  This shipyard contract fixed the majority of the expected costs associated with the construction of the Q7000.  Pursuant to the terms of this contract, 20% of the contract price was paid upon the signing of the contract and the remaining 80% will be paid upon the delivery of the vessel, which is expected to occur in 2016.
 
 
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil.  The initial term of the agreements with Petrobras is for four years with options to extend.  In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild monohull vessels, both of which are expected to be in service for Petrobras in 2016.
 
Robotics
 
We have been actively engaged in robotics for approximately 30 years.  We operate ROVs, trenchers and ROVDrills designed for offshore construction, maintenance and well intervention services.  As global marine construction support moves to deeper waters, the use of ROV systems has increased and the scope of ROV services is becoming even more significant.  Our chartered vessels add value by supporting deployment of our ROVs.  We provide our customers with vessel availability and schedule flexibility to meet the technological challenges of their subsea activities worldwide.  Our robotics assets include 50 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 Olympic Canyon, the Rem Installer and the Grand Canyon.  We also have entered into long-term charter agreements for the Grand Canyon II and the Grand Canyon III, which are scheduled for delivery in the first half of 2015.
 
Over the last decade there has been a dramatic increase in offshore activity associated with the growing alternative (renewable) energy industry.  Specifically there has been a large 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 which can occur offshore, especially in northern Europe where offshore wind farming is currently concentrated.  In 2014, revenues derived from offshore renewables contracts accounted for 13% of our global robotics revenues.  Looking ahead to 2015, we believe that 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 dynamically positioning floating production unit capable of processing up to 45,000 barrels of oil and 80 million cubic feet (“MMcf”) of natural gas per day.  The HP I is currently being used to process production from the Phoenix field.  Our existing contract for service to the Phoenix field will not expire until at least December 31, 2016.
 
We own a 50% interest in Deepwater Gateway which owns the Marco Polo TLP located in 4,300 feet of water in the Gulf of Mexico.  We also own a 20% interest in Independence Hub which owns the Independence Hub platform, a 105-foot deep draft, semi-submersible platform located in a water depth of 8,000 feet that serves as a regional hub for up to one billion cubic feet (“Bcf”) of natural gas production per day from multiple ultra-deepwater fields in the eastern Gulf of Mexico.  These two over-sized production facilities allow oil and gas operators to tie back less economically viable discoveries.  Ownership of production facilities enables us to earn a transmission company type return through tariff charges.
 
We developed the HFRS as a culmination of our experience as a responder in the Macondo well control and containment efforts.  The HFRS centers on two 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 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.  These agreements became effective April 1, 2013, and have a four-year term.
 
 
Subsea Construction
 
Our subsea construction operations included the use of umbilical lay and pipelay vessels and ROVs to develop fields in the deepwater.  We sold our remaining pipelay vessels, the Caesar and the Express, in mid-year 2013 and our spoolbase property located in Ingleside, Texas in January 2014.  The offshore construction industry (i.e., Subsea Construction) represents a substantial component of our Robotics segment revenue base as we provide ROV and trencher support and services to complement and directly support the Subsea Construction operations.
 
DISCONTINUED OPERATIONS
 
Our former Oil and Gas segment was engaged in prospect generation, exploration, development and production activities.  We exited our oil and gas business in February 2013 upon the sale of our former domestic oil and gas subsidiary, Energy Resource Technology GOM, Inc. (“ERT”), for $624 million plus additional consideration in the form of overriding royalty interests in ERT’s Wang well and certain exploration prospects.
 
GEOGRAPHIC AREAS
 
We primarily operate in the U.S. Gulf of Mexico, North Sea, Asia Pacific and West Africa regions.  See Note 12 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: 2014 — Anadarko (13%), 2013 — Shell (14%) and 2012 — Shell (12%).  We provided services to over 60 customers in 2014.
 
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 include Oceaneering International, Inc., FTO Services, Fugro N.V., DOF ASA, Aker Solutions ASA, Island Offshore, Edison Chouest Offshore Companies and DeepOcean Group.  Our competitors in the well intervention business also include international drilling contractors.  Our competitors may have significantly more financial, personnel, technological and other resources available to them.
 
TRAINING, SAFETY, ENVIRONMENT AND QUALITY ASSURANCE
 
Our corporate goal, based on the belief that all accidents can be prevented, is to provide an incident-free workplace by focusing on risk management and safe 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” which 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, management believes 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 people.
 
 
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 by management 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).
 
GOVERNMENT REGULATION
 
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 Service, as well as private industry organizations such as the American Bureau of Shipping (the “ABS”).  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 that have various types of governmental laws and regulations to which we are subject.
 
The Coast Guard sets safety standards and is authorized to investigate vessel and diving accidents and to recommend improved safety standards.  The Coast Guard also is 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.  We believe that we have obtained or can obtain all permits, licenses and certificates necessary for the conduct of our business.
 
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.
 
In April 2010, the Deepwater Horizon drilling rig experienced an explosion and fire, and later sank into the Gulf of Mexico.  The complete destruction of the Deepwater Horizon rig also resulted in a significant release of crude oil into the Gulf.  As a result of this explosion and oil spill, a moratorium was placed on offshore deepwater drilling in the United States, which was subsequently lifted in October 2010 and replaced with enhanced safety standards for offshore deepwater drilling.  Operators whose deepwater operations were suspended as a result of the moratorium and who wish to resume deepwater drilling, as well as all operators initiating new deepwater drilling projects, must demonstrate compliance with these enhanced standards.  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.  Inspections will be conducted of each deepwater drilling operation for compliance with BOEM and BSEE regulations, including but not limited to the testing of blowout preventers, before drilling resumes.  Deepwater operators also need to comply with the Safety and Environmental Management System (“SEMS”) Rule within the deadlines specified by the regulation.  Each operator must demonstrate that it has enforceable obligations that ensure that containment resources are available promptly in the event of a deepwater blowout, regardless of the company or operator involved.  During 2011, the Department of the Interior established a mechanism relating to the availability of blowout containment resources, including our HFRS system, and the BOEM and BSSE are now regulating these resources.  It is also expected that the BOEM and BSEE will issue further regulations regarding deepwater offshore drilling.
 
 
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.
 
ENVIRONMENTAL REGULATION
 
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 such laws that are often complex and costly to comply with and that 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 such 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.
 
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 of $854,400 or $1,000 per gross ton for vessels other than tank vessels.  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, if the spill is caused by gross negligence or willful misconduct; if the spill results from violation of a federal safety, construction, or operating regulation; or 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.  Management is currently unaware of any oil spills for which we have been designated as a Responsible Party under OPA that will have a material adverse impact on us or our operations.
 
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 seven vessels over 300 gross tons.  We have provided satisfactory evidence of financial responsibility to the Coast Guard for all of our vessels.
 
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 Federal 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 routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use.  Our vessels transport bulk chemical materials used in drilling activities and also transport liquid mud which contains oil and oil by-products.  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.
 
 
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 BSSE has implemented policy guidelines (IPD No. 12-07) under which the agency will issue incidents of noncompliance directly to contractors for serious violations of BSEE regulations.  As of this date, we believe that we are not the subject of any civil or criminal enforcement actions under OCSLA.
 
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 who transport, dispose of, or arrange for disposal of hazardous substances released at the sites.  Under CERCLA, such 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.  Although we handle hazardous substances in the ordinary course of business, we are not aware of any hazardous substance contamination for which we may be liable.
 
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 which are owned or operated by either our customers or our subcontractors.
 
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.
 
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the Federal Clean Air Act and thus subject to future regulation.  In December 2009, the EPA issued an “endangerment and cause or contribute finding” for greenhouse gases under the Federal Clean Air Act, which allowed the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Since 2009, the EPA has issued regulations that, among other things, require a reduction in emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources.  The EPA has received petitions to regulate greenhouse gas emissions from marine vessels, but we are currently unaware of any rulemaking projects initiated pursuant to the petitions.
 
Additionally, 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.  Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis.
 
 
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.
 
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 for the underlying cost).
 
Our insurance is renewed annually on July 1 and covers a twelve-month period from July 1 to June 30.
 
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 HP I and the Well Enhancer, and $500,000 on the Seawell and the Helix 534.  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 $1.0 million 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 reciprocal 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.  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 management believes are covered by insurance.  We analyze each claim for potential exposure and estimate the ultimate liability of each claim.  At December 31, 2014, we did not have any claims exceeding our deductible limits.  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, 2014, we had approximately 1,800 employees, of which approximately 830 were salaried personnel.  As of December 31, 2014, we also contracted with third parties to utilize 25 non-U.S. citizens to crew our foreign flagged vessels.  Our employees do not belong to a union nor are they employed pursuant to any collective bargaining agreement or any similar arrangement.  We believe that our relationship with our employees and foreign crew members is favorable.
 
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).  Copies of this Annual Report for the year ended December 31, 2014, 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 Conduct and Business 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 450 Fifth Street, N.W., 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 intend to satisfy the requirement under Item 5.05 of Form 8-K to disclose any amendments to our Code of Conduct and Business 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 such 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 dynamic positioning system 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.
 
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.
 
Remotely Operated Vehicle (ROV):  Robotic vehicles 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.  Because the 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 by us to perform specific projects.
 
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.
 
 
Item 1A.  Risk Factors
 
Shareholders should carefully consider the following risk factors in addition to the other information contained herein.  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.
 
Business Risks
 
Our results of operations could be adversely affected if our business assumptions do not prove to be accurate or if adverse changes occur in our business environment, including the following areas:
 
 
 
changes in laws or regulations, including laws relating to the environment or to the oil and gas industry in general, and other factors, many of which are beyond our control;
 
 
general global economic and business conditions, as well as certain potential geopolitical developments, that affect demand for and/or prices of oil and natural gas and, in turn, our business;
 
 
technological advances that increase the efficiency of oil and gas production or result in new means of oil and gas production that affect supplies of oil and natural gas and, in turn, our business;
 
 
our ability to manage risks related to our business and operations;
 
 
our ability to manage shipyard construction, and upgrades and modifications of our vessels;
 
 
our ability to compete against companies that provide more services and products than we do, including “integrated service companies;”
 
 
our ability to attract and retain skilled, trained personnel to provide technical services and support for our business;
 
 
our ability to procure sufficient supplies of materials essential to our business in periods of high demand, and to reduce our commitments for such materials in periods of low demand; and
 
 
consolidation by our customers, which could result in loss of a customer.
 
Economic downturn could negatively impact our business, and in a continued downturn with a negative effect on the price of oil and natural gas, our customers may seek to cancel, renegotiate or defer work under our service contracts.
 
Our operations are affected by local, national and worldwide economic conditions and the condition of the oil and gas industry.  Certain economic data indicates that the global economy faces an uncertain outlook.  The consequences of a prolonged period of little or no economic growth will likely result in a lower level of activity and increased uncertainty regarding the direction of oil and gas prices and capital markets, which will likely contribute to decreased offshore exploration and drilling.  A lower level of offshore exploration and drilling activity could have a material adverse effect on the demand for our services.  In addition, a general decline in economic conditions and demand for energy would also result in lower oil and gas prices, which may also adversely affect demand for and revenues from our services.  Likewise, a lower level of offshore activity by oil and gas operators could lead to a surplus of available vessels and therefore downward pressure on the rates we can charge in the market for our services.  The extent of the impact of these factors on our results of operations and cash flows depends on the length and severity of the decreased demand for our services and lower oil and gas prices.
 
In the short term, our customers could react to negative market conditions, and may seek to renegotiate their contracts with us or 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.  Continued market deterioration could also jeopardize the ability to perform certain counterparty obligations, including those of our insurers, customers and financial institutions.  Although we assess the creditworthiness of our counterparties, prolonged business decline or disruptions as a result of economic slow-down or lower oil and gas prices could lead to changes in a counterparty’s liquidity and increase our exposure to credit risk and bad debts, and in particular, our robotics business unit tends to do business with smaller customers who may not be capitalized to the same extent as larger operators which may lead to more frequent collection issues.  In such events, our financial results could be adversely affected and we could incur losses and our liquidity could be negatively impacted.
 
Our business is adversely affected by low oil and gas prices in a cyclical oil and gas industry.
 
Conditions in the oil and gas industry are subject to factors beyond our control.  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.  The level of capital expenditures generally depends on the prevailing view of future oil and gas prices, which are influenced by numerous factors affecting the supply and demand for oil and natural gas, including, but not limited to:
 
 
 
worldwide economic activity;
 
 
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 shale oil and natural gas;
 
 
the cost of offshore exploration for and production and transportation of oil and natural gas;
 
 
the ability of oil and gas companies to generate funds or otherwise obtain external capital for exploration, development 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;
 
 
weather conditions;
 
 
environmental and other governmental regulations; and
 
 
tax laws, regulations and policies.
 
A sustained period of low drilling and production activity or low oil and gas prices will likely have a material adverse effect on our financial position, cash flows and results of operations.
 
Our current backlog for our services may not be ultimately realized, and our contracts may be terminated early.
 
As of December 31, 2014, backlog for our services supported by written agreements or contracts totaled $2.3 billion, of which $591.6 million is expected to be performed in 2015.  Although historically our service contracts were of relatively short duration, over the last several years we have been entering into longer term contracts, specifically the BP contract in the Gulf of Mexico and more recently, the Petrobras contract for offshore Brazil.  As a consequence, we incur capital costs which we expect to recover over the term of the contracts, we charter vessels over the terms of and for the purpose of performing contracts, and/or we forego other contracting opportunities for the term of these contracts.  We may not be able to perform under these contracts due to events beyond our control.  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 market conditions, some of which contracts provide for a cancellation fee that is substantially less than the expected rates from the contracts.  For example, we had two contracts canceled during the second half of 2014, which reduced our backlog for both 2014 and 2015.  In addition, some of our customers could experience liquidity issues or could otherwise be unable or unwilling to perform under the contract, which could lead a customer to seek to repudiate, cancel or renegotiate a 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.
 
Vessel upgrade, repair and construction projects are subject to risks, including delays, cost overruns, and failure to secure drilling contracts.
 
We are constructing two newbuild semi-submersible well intervention vessels, the Q5000 and the Q7000.  We also construct additional ROVs and trenchers from time to time.  We may also commence the construction of additional vessels for our fleet in the future without first obtaining service contracts covering any such vessels.  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.
 
 
Depending on available opportunities, we may construct additional vessels for our fleet in the future.  In addition, we incur significant upgrade, refurbishment and repair expenditures on our fleet from time to time.  Some of these expenditures are unplanned.  These projects are subject to risks of delay or cost overruns inherent in any large construction project resulting from numerous factors, including the following:
 
 
 
shortages of equipment, materials or skilled labor;
 
 
unscheduled delays in the delivery of ordered materials and equipment;
 
 
unanticipated increases in the cost of equipment, labor and raw materials, particularly steel;
 
 
weather interferences;
 
 
difficulties in obtaining necessary permits or in meeting permit conditions;
 
 
design and engineering problems;
 
 
political, social and economic instability, war and civil disturbances;
 
 
delays in customs clearance of critical parts or equipment;
 
 
financial or other difficulties or failures at shipyards and suppliers;
 
 
disputes with shipyards and suppliers; and
 
 
work stoppages and other labor disputes.
 
Delays in the delivery of vessels being constructed or undergoing upgrades, refurbishment or repair may result in delay in 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 contract, and/or seek delay damages, under applicable late delivery clauses, if any.  For example, the contracts for our chartered vessels in Brazil have significant penalty provisions for late delivery to Petrobras of the vessels which escalate with further delay, and if the vessels are late in delivery to Petrobras beyond a certain date, the contracts also may be terminated.  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.  Moreover, if the contract with Petrobras were to be canceled, we would still be responsible for the charter costs of the two monohull vessels we have contracted to perform this work in Brazil.
 
The estimated capital expenditures for vessels, upgrades, refurbishments and construction projects could materially exceed our planned capital expenditures.  Moreover, our vessels undergoing upgrades, refurbishment and 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 materially affect our results of operations and cash flows.
 
Time chartering of our ROV support vessels requires us to make payments regardless of utilization and revenue generation, which could adversely affect our operations.
 
Most of our ROV support vessels are under long-term time charter contracts.  Should we not have work for those vessels, we are still required to make time charter payments, and making those payments absent revenue generation could have an adverse effect on our financial position, results of operations and cash flows.
 
Our contracting 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 other extreme weather conditions 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 storms, we may experience disruptions in our operations because customers may curtail their development 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.
 
Marine construction involves 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 business.  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 large vessels could have a material adverse effect on us.
 
Our customers may be unable or unwilling to indemnify us.
 
Consistent with standard industry practice, we typically obtain contractual indemnification from our customers whereby they agree to protect and indemnify us for liabilities resulting from various hazards associated with the drilling industry.  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 drilling offshore 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.  In the U.S. Gulf of Mexico, under enhanced safety standards, in order for an operator to conduct deepwater drilling, it is required to comply with existing and newly developed regulations and standards.  The BSEE conducts many inspections of deepwater drilling operations for compliance with its regulations, including but not limited to the testing of blowout preventers, before drilling may commence.  Operators also need to comply with the Safety and Environmental Management System (SEMS Rule) within the deadlines specified by the regulation, and ensure that their contractors have SEMS compliant safety and environmental policies.  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 BSEE will continue to issue further regulations regarding deepwater offshore drilling.  Our contracting services 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 demand for our services is decreased or delayed because 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 and results of operations would be materially 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 including the increase in costs or delays associated with such regulations.  If the United States or other countries where we operate enact stricter restrictions on offshore drilling or further regulate offshore drilling and increase costs for our customers, our business, financial condition and results of operations could be materially affected.
 
Government Regulation, including recent legislative initiatives, may affect our business operations.
 
Numerous federal and state regulations affect our operations.  Current regulations are constantly reviewed by the various agencies at the same time that new regulations are being considered and implemented, and could include regulations pertaining to contracting service operators such as ourselves.  The regulatory burden upon the oil and gas industry increases the cost of doing business and consequently affects our profitability.  Potential legislation and/or regulatory actions could increase our costs and reduce our liquidity, delay our operations or otherwise alter the way we conduct our business.  Exploration and development activities and the production and sale of oil and natural gas are subject to extensive federal, state, local and international regulations.
 
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 domestic and foreign governmental agencies issue rules and regulations to implement and enforce such laws that are often complex and costly to comply with and that 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 such 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.
 
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 emission 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.
 
In 2007, the U.S. Supreme Court held in Massachusetts, et al. v. EPA that greenhouse gases are an “air pollutant” under the federal Clean Air Act and thus subject to future regulation.  In December 2009, the EPA issued an “endangerment and cause or contribute finding” for greenhouse gases under the federal Clean Air Act, which allowed the EPA to proceed with the adoption and implementation of regulations that would restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act.  Since 2009, the EPA has issued regulations that, among other things, require a reduction of emissions of greenhouse gases from motor vehicles and that impose greenhouse gas emission limitations in Clean Air Act permits for certain stationary sources.  The EPA has received petitions to regulate greenhouse gas emissions from marine vessels, but we are currently unaware of any rulemaking projects initiated pursuant to the petitions.
 
Additionally, 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 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.  Under these rules, reporting of greenhouse gas emissions from such facilities is required on an annual basis.
 
 
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.  In addition, changes in environmental laws and regulations, or claims for damages to persons, property, natural resources or the environment, could result in substantial costs and liabilities, and thus there can be no assurance that we will not incur significant environmental compliance costs in the future.  Such environmental liability could substantially reduce our net income and could have a significant impact on our financial ability to carry out our operations.
 
The application of the Jones Act (which regulates the kind of vessels that can carry goods between ports of the US) to offshore oil and gas work in the US is interpreted in large part by letter rulings of the U.S. Customs and Border Protection Agency (“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 US flag vessel.  In early 2010, CBP and its parent agency, the Department of Homeland Security (“DHS”), initiated a proposed rulemaking that would have been subject to public comment following publication in the Federal Register.  The proposed rulemaking would have largely reversed the holdings of years of letter rulings from the CBP regarding the application of the Jones Act to offshore oil and gas work.  The agencies subsequently withdrew the proposed rulemaking before it was published in the Federal Register.  If DHS or CBP re-proposes a change to the application of the Jones Act similar to that originally proposed by CBP, and such proposal is adopted, or if CBP issues one or more letter rulings that interprets the Jones Act as being more restrictive to the operation of foreign flag vessels, such a development could potentially lead to operational delays or increased operating costs in instances where we would be required to hire coastwise qualified vessels that we currently do not own, in order to transport certain merchandise to projects on the OCS.  This could increase our costs of compliance and doing business and make it more difficult to perform our offshore services in the US.
 
Failure to comply with the U.S. Foreign Corrupt Practices Act or foreign anti-bribery legislation could have an 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 the Brazilian 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 and, in certain circumstances, strict compliance with anti-bribery laws may conflict with local customs and practices and impact our business.  Although we have programs in place covering compliance with anti-bribery legislation, any failure to comply with the FCPA or other anti-bribery legislation could subject us to civil and criminal penalties or other sanctions, which could have a material adverse effect on our business, financial position, results of operations and cash flows, and cause certain 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 rigs 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, without limitation:
 
 
 
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 entities;
 
 
changes in laws and policies governing operations of foreign-based companies;
 
 
currency restrictions and exchange rate fluctuations;
 
 
world 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.
 
 
In addition, laws and policies of the United States affecting foreign trade and taxation may also adversely affect our international operations.
 
We may not be able to compete successfully against current and future competitors.
 
The oilfield services business in which we operate is highly competitive.  Several of our competitors are substantially larger and have greater financial and other resources than we have.  If other companies relocate or acquire vessels for operations in the Gulf of Mexico, North Sea, Asia Pacific or West Africa regions, levels of competition may increase and our business could be adversely affected.
 
In addition, in a few countries, the national oil companies have formed subsidiaries to provide oilfield services for them, competing with services provided by us.  To the extent this practice expands, our business could be adversely impacted.
 
Lack of access to the credit market 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 incur increased costs associated with any additional financing we may require for future operations.  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 capital 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 credit markets could also adversely affect our ability to implement our strategic objectives and dispose of non-core business assets.
 
Our forward-looking statements assume that our lenders, insurers and other financial institutions will be able to fulfill their obligations under our various credit agreements, insurance policies and contracts.  If any of our significant financial institutions were unable to perform under such agreements, and if we were unable to find suitable replacements at a reasonable cost, our results of operations, liquidity and cash flows could be adversely impacted.
 
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, 2014, we had $551.4 million of consolidated indebtedness outstanding.  The level of indebtedness may have an adverse effect on our future operations, including:
 
 
 
limiting our ability 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 activity may make it increasingly difficult to comply with our covenants and other restrictions in agreements governing our debt.  Our ability to comply with these covenants and other restrictions may be affected by the economic conditions and other events beyond our control.  If we fail to comply with these covenants and other restrictions, it could lead to 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.
 
Our consolidated financial results are reported in U.S. dollars while certain assets and other reported items are denominated in the currencies of other countries, creating currency translation risk.
 
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.  For instance, we conduct much of our North Sea operations using the British pound, which has recently experienced a sharp decline in its value against the U.S. dollar.  Substantial fluctuations in exchange rates could have a significant impact on our results.
 
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.  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.  Our ability to expand our operations depends in part on our ability to increase the size of our skilled labor force, in particular for our expanded well intervention fleet, including meeting any applicable local content requirements that apply when we work in international waters.  The demand for skilled workers in our industry is high, and the supply is limited.  In addition, although our employees are not covered by a collective bargaining agreement, the marine services industry has in the past been targeted by maritime labor unions in an effort to organize Gulf of Mexico employees.  A significant increase in the wages paid by competing employers or the unionization of our Gulf of Mexico employees could result in a reduction of our labor force, increases in the wage rates that we must pay or both. If either of these events were to occur, our capacity and profitability could be diminished and our growth potential could be impaired.
 
If we fail to effectively manage our growth strategy, our results of operations could be harmed.
 
Our current strategy is to expand our well intervention and robotics businesses.  We must plan and manage our growth effectively to achieve increased revenue and maintain profitability in our evolving market.  If we fail to effectively manage current and future growth, our results of operations could be adversely affected.  In the past, our growth has placed significant demands on our personnel, management and other resources.  We must continue to improve our operational, financial, management and legal compliance information systems to keep pace with the planned expansion of our services.
 
 
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, 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.
 
Our Articles of Incorporation give our Board of Directors the authority, without any action by our shareholders, to fix the rights and preferences on up to 4,994,000 shares of undesignated 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.
 
Other Risks
 
Other risk factors could cause actual results to be different from the results we expect.  The market price for our common stock, as well as other companies in the oil and gas industry, has been historically volatile, which could restrict our access to capital markets in the future.  Other risks and uncertainties may be detailed from time to time in our filings with the SEC.
 
Many of these risks are beyond our control.  In addition, future trends for pricing, margins, revenue and profitability remain difficult to predict in the industries we serve and under current market, economic and political conditions.  Forward-looking statements speak only as of the date they are made and, except as required by applicable law, we do not assume any responsibility to update or revise any of our forward-looking statements.
 
Item 1B.  Unresolved Staff Comments
 
None.
 
Item 2.  Properties
 
OUR VESSELS
 
We own a fleet of five vessels and 50 ROVs, five trenchers, and two ROVDrills.  We also charter five vessels.  Currently all of our vessels, both owned and chartered, have DP capabilities specifically designed to meet the needs of deepwater market participants.  Our Seawell and Well Enhancer vessels have built-in saturation diving systems.
 
 
Listing of Vessels and Robotics Assets Related to Operations (1)
 
 
 
 
 
Flag
State
 
Placed
in
Service (2)
 
 
Length
(Feet)
 
 
 
Berths
 
 
SAT
Diving
 
 
 
DP
 
Crane
Capacity
(tons)
Floating Production Unit —
                         
Helix Producer I (3)
Bahamas
 
4/2009
 
528
 
95
 
 
DP2
 
26 and 26
Well Intervention —
                         
Q4000 (4)
U.S.
 
4/2002
 
312
 
135
 
 
DP3
 
160 and 360; 600 Derrick
Seawell
U.K.
 
7/2002
 
368
 
129
 
Capable
 
DP2
 
65 and 130; 80 Derrick
Well Enhancer
U.K.
 
10/2009
 
432
 
120
 
Capable
 
DP2
 
100; 150 Derrick
Skandi Constructor (6)
Bahamas
 
4/2013
 
395
 
100
 
 
DP3
 
150; 140 Derrick
Helix 534
Bahamas
 
2/2014
 
534
 
156
 
 
DP2
 
600 Derrick
Robotics —
                         
50 ROVs, 5 Trenchers and 2 ROVDrills (3), (5)
 
Various
 
 
 
 
 
Olympic Canyon (6)
Norway
 
4/2006
 
304
 
87
 
 
DP2
 
150
Deep Cygnus (6)
Panama
 
4/2010
 
400
 
92
 
 
DP2
 
150 and 25
Grand Canyon (6)
Panama
 
10/2012
 
419
 
104
 
 
DP3
 
250
Rem Installer (6)
Norway
 
7/2013
 
353
 
110
 
 
DP2
 
250
 
(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 USCG. 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 the vessel in service and not the date of commissioning.
   
(3)
Serve as security for our Credit Agreement described in Note 6.
   
(4)
Subject to vessel mortgage securing our MARAD debt described in Note 6.
   
(5)
Average age of our fleet of ROVs, trenchers and ROVDrills is approximately 6.6 years.
   
(6)
Chartered vessel.
 
We incur routine dry dock, inspection, maintenance and repair costs pursuant to applicable statutory regulations in order to maintain our vessels in class 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.  The Seawell, the Q4000 and the H534 all are scheduled to be in dry dock during 2015.
 
PRODUCTION FACILITIES
 
We own a 50% interest in Deepwater Gateway which owns the Marco Polo TLP located in the Gulf of Mexico.  We also 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.  For more information regarding our production facilities, see Item 1. Business “— Our Operations.”
 
FACILITIES
 
Our corporate headquarters are located at 3505 West Sam Houston Parkway North, Suite 400, Houston, Texas.  We own the Aberdeen (Dyce), Scotland facility and lease our other facilities.  The list of our facilities as of January 31, 2015 is as follows:
 
 
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, Management and Sales Office
   
   
Helix Subsea Construction, Inc.
Corporate Headquarters
   
   
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)
         
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 two years 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 Offshore International 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
 
1,447 square feet
 
Item 3.  Legal Proceedings
 
We are, from time to time, party to litigation arising in the normal course of our business.  We believe that there are currently no legal proceedings, the outcome of which would have a material adverse effect on our financial position, results of operations or cash flows.
 
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
 
60
 
President and Chief Executive Officer and Director
Anthony Tripodo
 
62
 
Executive Vice President and Chief Financial Officer
Clifford V. Chamblee
 
55
 
Executive Vice President and Chief Operating Officer
Alisa B. Johnson
 
57
 
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 his former 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 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 publicly-traded company, which was formerly a subsidiary of Helix.  Mr. Kratz has a Bachelor of Science degree from State University of New York (SUNY).
 
Anthony Tripodo was named 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 a director of Helix from February 2003 until June 2008.  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 prior service as a director of Helix.  He graduated Summa Cum Laude with a Bachelor of Arts degree from St. Thomas University (Miami).
 
Clifford V. Chamblee was named Executive Vice President and Chief Operating Officer of Helix in February 2013.  He served as Executive Vice President-Contracting Services of Helix from May 2011 until February 2013.  He joined Helix’s robotics subsidiary, Canyon Offshore, Inc. (Canyon), in 1997.  Mr. Chamblee served as President of Canyon from 2006 until 2011.  Prior to becoming President of Canyon, Mr. Chamblee held several positions with increasing responsibilities at Canyon managing the operations of the company including as Senior Vice President and Vice President Operations from 1997 until 2006.  Mr. Chamblee has been involved in the robotics industry for over 33 years.  From 1988 to 1997, Mr. Chamblee held various positions with Sonsub International, Inc., including Vice President Remote Systems, Marketing Manager and Operations Manager.  From 1986 until 1988, he was Operations Manager and Superintendent for Helix (then known as Cal Dive).  From 1981 until 1986, Mr. Chamblee held various positions for Oceaneering International/Jered, including ROV Superintendent and ROV Supervisor.  Prior to 1981, he was an ROV Technician for Martech International.
 
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 Secretary of the Company.  Ms. Johnson oversees the legal, human resources and contracts and insurance functions.  Ms. Johnson has been involved with the energy industry for over 24 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 Entergy, 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.
 
 
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
 
2013
           
First Quarter
  $ 25.49     $ 20.59  
Second Quarter
  $ 25.99     $ 20.33  
Third Quarter
  $ 27.58     $ 23.12  
Fourth Quarter
  $ 25.85     $ 21.33  
                 
2014
               
First Quarter
  $ 24.16     $ 19.44  
Second Quarter
  $ 26.41     $ 21.59  
Third Quarter
  $ 28.00     $ 21.91  
Fourth Quarter
  $ 27.70     $ 19.48  
                 
2015
               
First Quarter (1)
  $ 21.99     $ 17.14  
 
(1)  
Through February 13, 2015
 
On February 13, 2015, the closing sale price of our common stock on the NYSE was $19.08 per share.  As of February 13, 2015, there were 327 registered shareholders and approximately 25,500 beneficial shareholders of our common stock.
 
We have never declared or paid cash dividends on our common stock and do not 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, 2009 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., Dril-Quip, Inc., GulfMark Offshore, Inc., Hercules Offshore, Inc., Hornbeck Offshore Services, Inc., McDermott International, Inc., Oceaneering International, Inc., Oil States International, Inc., Rowan Companies plc, Superior Energy Services, Inc., 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, 2014 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, 2009 in our common stock at the closing price on that date price and on December 31, 2009 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 — 84.7%; the Peer Group — (12.3)%; the OSX — 8.2%; and S&P 500 — 105.1%.  These results are not necessarily indicative of future performance.
 
 
 
Comparison of Five Year Cumulative Total Return among Helix, S&P 500,
OSX and Peer Group
 
   
As of December 31,
 
   
2009
     
2010
     
2011
     
2012
     
2013
     
2014
 
Helix
$
100.0
   
$
103.3
   
$
134.5
   
$
175.7
   
$
197.3
   
$
184.7
 
Peer Group Index
$
100.0
   
$
120.1
   
$
112.7
   
$
112.3
   
$
145.6
   
$
87.7
 
Oil Service Index
$
100.0
   
$
125.8
   
$
111.0
   
$
113.0
   
$
144.2
   
$
108.2
 
S&P 500
$
100.0
   
$
115.1
   
$
117.5
   
$
136.3
   
$
180.4
   
$
205.1
 
 
Source: Bloomberg
 
Issuer Purchases of Equity Securities
 
Period
 
(a)
Total number
of shares
purchased
   
(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 (1) (2)
 
October 1 to October 31, 2014
 
 
$
 
 
 
November 1 to November 30, 2014
 
   
 
 
 
December 1 to December 31, 2014
 
   
 
 
55,674
 
   
 
$
 
 
55,674
 
 
(1)  
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 8), increases the number of shares available for repurchase.  For additional information regarding our stock repurchase program, see Note 10.
 
(2)  
In January 2015, we issued approximately 0.3 million shares of restricted stock to our executive officers, selected management employees and certain members of our Board of Directors who have elected to take their quarterly fees in stock in lieu of cash.  We also issued approximately 0.1 million shares of our common stock to our employees under the ESPP.  These issuances will increase the number of shares available for repurchase by a corresponding amount (Note 8).
 
 
Item 6.  Selected Financial Data.
 
The financial data presented below for each of the five years ended December 31, 2014 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 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,
 
   
2014
   
2013
   
2012
   
2011
   
2010
 
   
(in thousands, except per share amounts)
 
                               
Net revenues
  $ 1,107,156     $ 876,561     $ 846,109     $ 702,000     $ 774,469  
Gross profit
    344,036       260,685       49,915       149,683       164,817  
Income (loss) from operations (1)
    261,756       179,034       (68,483 )     63,040       51,079  
Equity in earnings of investments
    879       2,965       8,434       22,215       19,469  
Net income (loss) from continuing operations
    195,550       111,976       (66,840 )     37,816       (17,496 )
Income (loss) from discontinued operations, net of tax (2)
   
      1,073       23,684       95,221       (106,657 )
Net income (loss), including noncontrolling interests
    195,550       113,049       (43,156 )     133,037       (124,153 )
Net income applicable to noncontrolling interests
    (503 )     (3,127 )     (3,178 )     (3,098 )     (2,835 )
Net income (loss) applicable to Helix
    195,047       109,922       (46,334 )     129,939       (126,988 )
Adjusted EBITDA from continuing operations (3)
    378,010       268,311       233,612       178,953       160,250  
                                         
Basic earnings (loss) per share of common stock:
                                       
Continuing operations
  $ 1.85     $ 1.03     $ (0.67 )   $ 0.33     $ (0.19 )
Discontinued operations
   
      0.01       0.23       0.90       (1.03 )
Net income (loss) per common share
  $ 1.85     $ 1.04     $ (0.44 )   $ 1.23     $ (1.22 )
                                         
Diluted earnings (loss) per share of common stock:
                                       
Continuing operations
  $ 1.85     $ 1.03     $ (0.67 )   $ 0.33     $ (0.19 )
Discontinued operations
   
      0.01       0.23       0.90       (1.03 )
Net income (loss) per common share
  $ 1.85     $ 1.04     $ (0.44 )   $ 1.23     $ (1.22 )
                                         
Weighted average common shares outstanding:
                                       
Basic
    105,029       105,032       104,449       104,528       103,857  
Diluted
    105,045       105,184       104,449       104,953       103,857  
 
(1)  
Amount in 2012 includes 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 operations in Australia.  See Note 2 for additional information regarding these impairment charges.
 
(2)  
Oil and gas property impairment charges and asset retirement obligation overruns totaled $144.3 million in 2012, including the $138.6 million charge to reduce the value of ERT’s properties to their estimated fair value in connection with the announcement of the sale of ERT in December 2012, $112.6 million in 2011 and $176.1 million in 2010.  Also includes exploration expenses totaling $3.5 million in 2013, $3.3 million in 2012, $10.9 million in 2011 and $8.3 million in 2010.
 
(3)  
This is a non-GAAP financial measure.  See “Non-GAAP Financial Measures” below for an explanation of the definition and use of such measure as well as a reconciliation of these amounts to each year’s respective reported net income (loss) from continuing operations.
 
 
   
December 31,
 
   
2014
   
2013
   
2012
   
2011
   
2010
 
   
(in thousands)
 
                               
Working capital
  $ 468,660     $ 553,427     $ 351,061     $ 548,066     $ 373,057  
Total assets (1)
    2,700,698       2,544,280       3,386,580       3,582,347       3,592,020  
Long-term debt (including current maturities)
    551,372       566,152       1,019,228       1,155,321       1,357,932  
Convertible preferred stock (2)
   
     
     
      1,000       1,000  
Total controlling interest shareholders' equity
    1,653,474       1,499,051       1,393,385       1,421,403       1,260,604  
Noncontrolling interests
   
      25,059       26,029       28,138       25,040  
Total equity
    1,653,474       1,524,110       1,419,414       1,449,541       1,285,644  
 
(1)  
Amounts at December 31, 2012, 2011 and 2010 included assets of discontinued oil and gas operations.
 
(2)  
In 2012, the holder of our convertible preferred stock converted the remaining $1 million of the convertible preferred stock into 0.4 million shares of our common stock (Note 2).  In 2010, the holder of our convertible preferred stock converted $5 million of the convertible preferred stock into 1.8 million shares of our common stock.
 
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”).  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 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 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 as net income (loss) from continuing operations plus income taxes, depreciation and amortization expense, and net interest expense and other.  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 such impairment charges are material for most of the periods presented, we have reported them as a separate line item in the accompanying consolidated statements of operations.  Non-cash impairment charges related to goodwill are also added back if applicable.  Loss on early extinguishment of long-term debt is considered equivalent to additional interest expense and thus is added back to net income (loss) from continuing operations.
 
In the following reconciliation, we provide amounts as reflected in our accompanying consolidated financial statements unless otherwise footnoted.  This means that these amounts are recorded at 100% even if we do not own 100% of all of our subsidiaries.  Accordingly, to arrive at our measure of Adjusted EBITDA from continuing operations, when applicable, we deduct the noncontrolling interests related to the adjustment components of EBITDA and the gain or loss on disposition of assets from continuing operations.
 
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 is not a financial measure calculated in accordance with GAAP, it should not be considered in isolation or as a substitute for net income (loss) attributable to common shareholders or cash flows from operations, but used as a supplement to these GAAP financial measures.  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,
 
   
2014
   
2013
   
2012
   
2011
   
2010
 
                               
Net income (loss) from continuing operations
  $ 195,550     $ 111,976     $ (66,840 )   $ 37,816     $ (17,496 )
Adjustments:
                                       
Income tax provision (benefit)
    66,971       31,612       (59,158 )     (36,806 )     19,166  
Net interest expense and other
    17,045       32,892       48,822       71,328       66,638  
Loss on early extinguishment of long-term debt
   
      12,100       17,127       2,354      
 
Depreciation and amortization
    109,345       98,535       97,201       91,188       81,878  
Asset impairment charges (1)
   
     
      177,135       17,127       23,060  
EBITDA from continuing operations
    388,911       287,115       214,287       183,007       173,246  
Adjustments:
                                       
Noncontrolling interests
    (661 )     (4,077 )     (4,128 )     (4,060 )     (3,878 )
Unrealized loss on commodity derivative contracts
   
     
      9,977      
     
 
(Gain) loss on disposition of assets, net
    (10,240 )     (14,727 )     13,476       6       (9,118 )
ADJUSTED EBITDA from continuing operations
  $ 378,010     $ 268,311     $ 233,612     $ 178,953     $ 160,250  
 
(1)  
Amount in 2012 includes 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 operations in Australia.  Amount in 2011 includes a $6.6 million impairment charge related to our well intervention equipment in Australia and a $10.6 million other than temporary impairment loss on our former equity investment in an Australian joint venture.  Amount in 2010 includes $16.7 million related to goodwill impairment of our Australian well intervention subsidiary.
 
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.  Our focus is on growing our well intervention and robotics businesses.  We believe that focusing on these services will deliver quality long-term financial returns.  We are making strategic investments that expand our service capabilities or add capacity to existing services in our key operating regions.  The size of our well intervention fleet has increased with the addition of the Helix 534, which was placed in service in February 2014.  Our well intervention fleet will further expand following the completion of the two newbuild semi-submersible vessels currently under construction, the Q5000 and the Q7000, and the expected delivery in 2016 of two newbuild monohull vessels which we will charter in connection with the well intervention service agreements that we entered into with Petrobras in February 2014.  In addition, we are expanding our robotics operations by acquiring additional ROVs as well as chartering two newbuild ROV support vessels, the Grand Canyon II and the Grand Canyon III, both of which are scheduled for delivery in the first half of 2015.
 
 
On January 5, 2015, Helix, OneSubsea LLC, OneSubsea B.V., Schlumberger Technology Corporation, Schlumberger B.V. and Schlumberger Oilfield Holdings Ltd. (collectively, the “Parties”) 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.
 
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 make capital expenditures for offshore exploration, drilling and production operations.  The performance of our business is also largely dependent on the prevailing market prices for oil and natural gas, which are impacted by global economic conditions, hydrocarbon production and capacity, geopolitical issues, weather, and several other factors, including but not limited to:
 
 
 
worldwide economic activity, including available access to global capital and capital markets;
 
 
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 shale oil and natural gas;
 
 
the cost of offshore exploration for and production and transportation of oil and natural gas;
 
 
the ability of oil and gas companies to generate funds or otherwise obtain external capital for exploration, development 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;
 
 
weather conditions;
 
 
environmental and other governmental regulations; and
 
 
domestic and international tax laws, regulations and policies.
 
Global prices for oil and natural gas have declined significantly in the fourth quarter of 2014 and early portion of 2015 based on concerns over excess supply coupled with a slowing global economic outlook.  The trading price for crude oil on the New York Mercantile Exchange dropped substantially since July 2014 and fell below $45 per barrel in January 2015 for the first time since 2009.  Many analysts currently predict that prices for oil and natural gas may decrease further and remain low through 2015.  The decrease in oil and gas prices is attributable to a global supply and demand imbalance which reflects both increased production in certain countries primarily in the United States and a general weakening of the global economy that has primarily affected both Europe and Asia.  In light of the recent sharp decline in oil and gas prices, many oil and gas companies have announced reductions in capital spending for 2015.  Any additional news suggesting weak or declining economic data could affect global equity and the oil and gas markets, which could affect normal business activities.  Weaker global equity and oil and gas markets could potentially reduce investment in offshore oil and gas capital projects, which may affect rates that drilling rig contractors can charge for their services.  We believe that capital would be less likely to be expended on the beginning of offshore projects, for example for exploration drilling projects, than on projects that span the life of an oil and gas field’s production.  However, during periods of sustained low oil and gas prices, no one in the industry is immune to the effect of any near term planned capital spending reductions, including us.  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 continual oil and gas production is the primary driver of demand for our services.
 
In addition, we believe that the long-term industry fundamentals are positive based on the following factors: (1) long-term increasing world demand for oil and natural gas emphasizing the need for continual production and the replacement thereof; (2) mature global production rates for offshore and subsea wells; (3) globalization of the natural gas market; (4)  an increasing number of mature and small reservoirs; (5) increasing offshore activity, particularly in deepwater; and (6) an increasing number of subsea developments.
 
 
At December 31, 2014, we had cash on hand of $476.5 million and $583.6 million available for borrowing under our Revolving Credit Facility.  Our capital expenditures for 2015 are currently anticipated to total approximately $400 million.  If we successfully implement our business plan, we believe that we have sufficient liquidity without incurring additional indebtedness beyond the existing capacity under the Revolving Credit Facility and the Nordea Credit Agreement (Note 6).
 
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 our increased liquidity under our credit agreements, 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 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.
 
In January 2014, we sold our spoolbase property 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 and $7.5 million of principal payments on this note in December 2014 and January 2015, respectively.  Under the terms of the note, the remaining $20 million principal balance is required to be paid with a $10 million payment on each December 31 of 2015 and 2016.  The sale of our Ingleside spoolbase resulted in a $10.5 million gain in 2014.
 
In February 2014, we acquired our former minority partner’s noncontrolling interests in the entity that owns the HP I for $20.1 million.  We now own 100% of the vessel.
 
RESULTS OF OPERATIONS
 
We have four reportable business segments: Well Intervention, Robotics, Production Facilities and Subsea Construction.  Our Subsea Construction results have diminished following the sale of essentially all of our assets related to this reportable segment, including the sale of our Ingleside spoolbase in January 2014.  Previously, we had an additional business segment, Oil and Gas.  In February 2013, we completed the sale of ERT (Notes 1 and 13).  Accordingly, the results of ERT are presented as discontinued operations for all periods presented in this Annual Report.
 
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 developing offshore reservoirs and maximizing production economics.  We operate primarily in deepwater in the Gulf of Mexico, North Sea, Asia Pacific and West Africa regions, with services that cover the lifecycle of an offshore oil or gas field.  In addition, our Robotics operations are often contracted for the development of renewable energy projects (wind farms).  As of December 31, 2014, our consolidated backlog that is supported by written agreements or contracts totaled $2.3 billion, of which $591.6 million is expected to be performed in 2015.  The substantial majority of our backlog is associated with our Well Intervention business segment.  As of December 31, 2014, our well intervention backlog was $2.0 billion, including $418.3 million expected to be performed in 2015.  Representing approximately 67% of our total backlog are a five-year contract with BP to provide well intervention services with our Q5000 semi-submersible vessel and four-year agreements with Petrobras to provide well intervention services offshore Brazil with two chartered newbuild monohull vessels (both expected to be placed in service in 2016).  At December 31, 2013, the total backlog associated with our operations was $2.0 billion.  Backlog contracts are cancelable sometimes without penalties.  For example, we recently had two such backlog contracts canceled and although in these instances we are entitled to some cancellation fees, the amount of those fees is substantially less than the rates we would have generated if our services were performed in accordance with the terms of the contracts.  Accordingly, backlog is not necessarily a reliable indicator of total annual revenues for our services as contracts may be added, deferred, suspended, canceled and in many cases modified while in progress.
 
 
Comparison of Years Ended December 31, 2014 and 2013 
 
The following table details various financial and operational highlights for the periods presented (dollars in thousands): 
 
   
Year Ended December 31,
   
Increase/
 
   
2014
   
2013
   
(Decrease)
 
Net revenues —
                 
Well Intervention
  $ 667,849     $ 452,452     $ 215,397  
Robotics
    420,224       333,246       86,978  
Production Facilities
    93,175       88,149       5,026  
Subsea Construction
    358       71,321       (70,963 )
Intercompany elimination
    (74,450 )     (68,607 )     (5,843 )
    $ 1,107,156     $ 876,561     $ 230,595  
                         
Gross profit —
                       
Well Intervention
  $ 219,554     $ 142,762     $ 76,792  
Robotics
    86,419       57,035       29,384  
Production Facilities
    41,762       50,619       (8,857 )
Subsea Construction
    461       18,302       (17,841 )
Corporate and other
    (3,239 )     (4,673 )     1,434  
Intercompany elimination
    (921 )     (3,360 )     2,439  
    $ 344,036     $ 260,685     $ 83,351  
                         
Gross margin —
                       
Well Intervention
    33 %     32 %        
Robotics
    21 %     17 %        
Production Facilities
    45 %     57 %        
Total company
    31 %     30 %        
                         
Number of vessels or ROV assets (1) / Utilization (2)
                       
Well Intervention vessels
    5/88 %     4/92 %        
ROV assets
    57/78 %     57/63 %        
Robotics vessels
    4/85 %     5/88 %        
 
(1)  
Represents number of vessels or ROV assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. 
 
(2)  
Average vessel utilization rate is calculated by dividing the total number of days the vessels or ROV 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 during the years ended December 31, 2014 and 2013 are as follows (in thousands): 
 
   
Year Ended December 31,
   
Increase/
 
   
2014
   
2013
   
(Decrease)
 
                   
Well Intervention
  $ 29,875     $ 22,448     $ 7,427  
Robotics
    44,575       41,169       3,406  
Production Facilities
   
      4,673       (4,673 )
Subsea Construction
   
      317       (317 )
    $ 74,450     $ 68,607     $ 5,843  
 
 
Intercompany segment profit (loss) during the years ended December 31, 2014 and 2013 is as follows (in thousands): 
 
   
Year Ended December 31,
   
Increase/
 
   
2014
   
2013
   
(Decrease)
 
                   
Well Intervention
  $ (323 )   $ (141 )   $ (182 )
Robotics
    1,419       3,518       (2,099 )
Production Facilities
    (175 )     (175 )    
 
Subsea Construction
   
      158       (158 )
    $ 921     $ 3,360     $ (2,439 )
 
In reviewing the discussion below of our results of operations, please refer to the tables above and Note 12 for supplemental information regarding our business segment results.  This discussion specifically refers to our Well Intervention, Robotics and Production Facilities segments.  We sold our remaining Subsea Construction pipelay vessels in mid-year 2013 (Note 2).
 
Revenues.  Our total net revenues increased by 26% in 2014 as compared to 2013.  Net revenues for our business segments increased year over year, reflecting the addition of vessels in our Well Intervention business (see below), the increased asset utilization within our Robotics segment, and the slightly higher revenues for the HP I reflecting the variable production component of the fee arrangement in the Phoenix field.  Our Subsea Construction revenues decreased reflecting the sale of our pipelay vessels in mid-year 2013 (Note 2).
 
Our Well Intervention revenues increased by 48% in 2014 as compared to 2013 primarily reflecting the addition of two vessels, the chartered Skandi Constructor in April 2013 and the Helix 534 in February 2014, as well as higher demand for our services.  Our vessels had high utilization (88%) during 2014 despite three vessels being in regulatory dry dock in 2014: the Well Enhancer (24 days), the Skandi Constructor (29 days) and the Seawell (25 days).  The Seawell is currently undergoing both its normal regulatory dry dock and certain capital upgrades and is scheduled to return to service in April 2015.  The upgrades to the Seawell are intended to extend the vessel’s useful economic life.  Separately, a supply boat collided into the Q4000 in November 2014, which caused some damage to the vessel.  The Q4000 was on reduced rates for 17 days during collision inspection and repairs.  In addition, the H534 was idle for 53 days during the fourth quarter of 2014, including 14 days for required annual inspections and 39 days following the cancellation of a contract.
 
Our Robotics revenues increased by 26% in 2014 as compared to 2013.  The increase primarily reflects the higher utilization of our ROVs and trenchers, and 259 additional days of spot vessel utilization.  Our trenching activities, primarily conducted in the North Sea region, have significantly increased during 2014 as compared to the unusually weak market that was experienced in 2013.
 
Our Production Facilities revenues increased by 6% in 2014 as compared to 2013, which reflects an increase in our total revenues under our fee arrangement for the HP I, including the variable portion of the fee for throughput processed by the HP I.  The quarterly HFRS retainer fees also increased effective April 1, 2013 as a result of new four-year agreements. 
 
Gross Profit.  Our gross profit increased by 32% in 2014 as compared to 2013.  The gross profit related to our Well Intervention segment increased by 54% in 2014 as compared to 2013 reflecting the addition of two vessels to our fleet since March 31, 2013.
 
The gross profit associated with our Robotics segment increased by 52% in 2014 as compared to 2013 reflecting increased utilization for our ROVs and trenching assets and related support vessels.  Utilization for our trenching assets increased significantly reflecting the resumption of trenching projects in the North Sea region following an unusually weak year for that work in 2013.
 
The gross profit related to our Production Facilities segment decreased by 17% in 2014 as compared to 2013.  The decrease primarily reflects the amortization of the HP I’s initial regulatory dry dock costs that were incurred during the fourth quarter of 2013.
 
 
Loss on Commodity Derivative Contracts.  In December 2012, following the announcement of the sale of ERT, we de-designated our oil and gas commodity derivative contracts and interest rate swap contracts as hedging instruments (Note 15).  The $14.1 million loss on commodity derivative contracts reflects the net loss on our oil and gas commodity derivative contracts during the first quarter of 2013.  In February 2013, we paid approximately $22.5 million to settle our remaining open commodity derivative contracts. 
 
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 2).  The $14.7 million gain on disposition of assets in 2013 primarily reflects a $1.1 million loss on the sale of the Caesar in June 2013 and a $15.6 million gain on the sale of the Express in July 2013. 
 
Selling, General and Administrative Expenses.  Our selling, general and administrative expenses increased by $10.3 million in 2014 as compared to 2013.  The increase primarily reflects $5.3 million of charges associated with the provision for uncertain collection of a portion of our existing trade receivables (Note 14), certain costs associated with start-up activities in Brazil, and costs to support the growth of both our well intervention and robotics businesses.  However, our selling, general and administrative expenses as a percentage of net revenues decreased from 9.4% in 2013 to 8.4% in 2014. 
 
Equity in Earnings of Investments.  Equity in earnings of investments decreased by $2.1 million in 2014 as compared to 2013.  The decrease primarily reflects lower revenues for both Deepwater Gateway and Independence Hub due to lower production at the fields being processed at each facility.  Additionally, Deepwater Gateway’s operations were affected by a fire at the facility in early May 2014 that shut in production at the platform for most of the second quarter.  Production was restored to the facility in July 2014. 
 
Net Interest Expense.  Our net interest expense totaled $17.9 million in 2014 as compared to $32.9 million in 2013.  The decrease consists of both a reduction in interest expense and an increase in interest income.  The decrease in interest expense reflects the substantial reduction in our indebtedness, including the $318.4 million repayment of debt in February 2013 following the sale of ERT and our redemption in July 2013 of the remaining $275 million of our Senior Unsecured Notes then outstanding.  Interest income totaled $4.8 million for 2014 as compared to $1.2 million for 2013.  The amount of interest income for 2014 includes $2.1 million related to a U.S. Internal Revenue Service (“IRS”) income tax refund (Note 7) and $1.8 million on the promissory note held in connection with the sale of our Ingleside spoolbase (Note 2).  Capitalized interest remained consistent year over year. 
 
Loss on Early Extinguishment of Long-term Debt.  The $12.1 million loss in 2013 included the $8.6 million loss in connection with our redemption in July 2013 of the remaining $275 million Senior Unsecured Notes then outstanding and the acceleration of the remaining $3.5 million of deferred financing fees related to the term loan component of our former credit agreement following the repayment of that indebtedness.
 
Other Income, Net.  We reported net other income of $0.8 million for 2014 primarily reflecting foreign exchange fluctuations in our non-U.S. dollar functional currencies.  Included in this amount was $1.7 million of losses related to ineffectiveness associated with our foreign currency hedge with respect to the Grand Canyon II charter payments (Note 15).
 
Other Income – Oil and Gas.  The $16.9 million income for 2014 included a $7.2 million insurance reimbursement related to asset retirement work previously performed.  The majority of the remaining oil and gas income is associated with our overriding royalty interests in ERT’s Wang well, which commenced production in late April 2013.  The $6.6 million income for 2013 primarily represents cash payments related to services we provided to ERT following its sale to a third party and the initial proceeds associated with our overriding royalty interests in ERT’s Wang well.
 
Income Tax Provision.  Income taxes reflected expenses of $67.0 million in 2014 as compared to $31.6 million in 2013.  The variance primarily reflects increased profitability in the current year period.  The effective tax rate of 25.5% for 2014 was higher than the 22.0% effective tax rate for 2013 as a result of increased profitability in certain jurisdictions with higher tax rates.
 
 
Comparison of Years Ended December 31, 2013 and 2012
 
The following table details various financial and operational highlights for the periods presented (dollars in thousands):
 
   
Year Ended December 31,
   
Increase/
 
   
2013
   
2012
   
(Decrease)
 
Net revenues —
                 
Well Intervention
  $ 452,452     $ 378,546     $ 73,906  
Robotics
    333,246       328,726       4,520  
Production Facilities
    88,149       80,091       8,058  
Subsea Construction
    71,321       192,521       (121,200 )
Intercompany elimination
    (68,607 )     (133,775 )     65,168  
    $ 876,561     $ 846,109     $ 30,452  
                         
Gross profit —
                       
Well Intervention
  $ 142,762     $ 100,656     $ 42,106  
Robotics
    57,035       66,005       (8,970 )
Production Facilities
    50,619       40,645       9,974  
Subsea Construction
    18,302       (130,139 )     148,441  
Corporate and other
    (4,673 )     (19,374 )     14,701  
Intercompany elimination
    (3,360 )     (7,878 )     4,518  
    $ 260,685     $ 49,915     $ 210,770  
                         
Gross margin —
                       
Well Intervention
    32 %     27 %        
Robotics
    17 %     20 %        
Production Facilities
    57 %     51 %        
Subsea Construction
    26 %     (68 )%        
Total company
    30 %     6 %        
                         
Number of vessels or ROV assets (1) / Utilization (2)
                       
Well Intervention vessels
    4/92 %     3/82 %        
ROV assets
    57/63 %     55/67 %        
Robotics vessels
    5/88 %     4/92 %        
Subsea Construction vessels
    0/92 %     2/84 %        
 
(1)  
Represents number of vessels or ROV assets as of the end of the period excluding acquired vessels prior to their in-service dates, vessels taken out of service prior to their disposition and vessels jointly owned with a third party. 
 
(2)  
Average vessel utilization rate is calculated by dividing the total number of days the vessels or ROV assets generated revenues by the total number of calendar days in the applicable period. Utilization statistics for construction vessels only include the time each vessel was in service prior to its eventual sale. 
 
Intercompany segment revenues during the years ended December 31, 2013 and 2012 are as follows (in thousands):
 
   
Year Ended December 31,
   
Increase/
 
   
2013
   
2012
   
(Decrease)
 
                   
Well Intervention
  $ 22,448     $ 36,781     $ (14,333 )
Robotics
    41,169       46,465       (5,296 )
Production Facilities
    4,673       46,057       (41,384 )
Subsea Construction
    317       4,472       (4,155 )
    $ 68,607     $ 133,775     $ (65,168 )
 
 
Intercompany segment profit (loss) during the years ended December 31, 2013 and 2012 are as follows (in thousands):
 
   
Year Ended December 31,
   
Increase/
 
   
2013
   
2012
   
(Decrease)
 
                   
Well Intervention
  $ (141 )   $ 6,203     $ (6,344 )
Robotics
    3,518       180       3,338  
Production Facilities
    (175 )     (175 )    
 
Subsea Construction
    158       1,670       (1,512 )
    $ 3,360     $ 7,878     $ (4,518 )
 
In reviewing the discussion below of our results of operations, please refer to the tables above and Note 12 for supplemental information regarding our business segment results.
 
Revenues.  Our total net revenues increased by 4% in 2013 as compared to 2012 reflecting year-over-year revenue increases in each of our Well Intervention, Robotics and Production Facilities segments, offset in part by the substantial decrease in our Subsea Construction revenues as a result of the sale of our two remaining subsea construction pipelay vessels in mid-2013 (Note 2).
 
Our Well Intervention revenues increased by 20% in 2013 as compared to 2012 primarily reflecting the addition of a chartered vessel, the Skandi Constructor, to our North Sea fleet, and increased utilization of our three other well intervention vessels.  The higher utilization rates in 2013 primarily reflected fewer idle days associated with regulatory dry docks in 2013 (the Well Enhancer for 24 days) as compared to 2012 (the Q4000 for 70 days, the Seawell for 52 days and the Well Enhancer for 52 days).  In December 2013, the Well Enhancer commenced an additional regulatory dry dock, which has been completed and the vessel returned to service in late January 2014.
 
Our Robotics revenues increased by 1% in 2013 as compared to 2012 primarily reflecting the greater number of ROVs owned and higher ROVDrill revenues.  However, Robotics revenues were adversely affected by a decrease in the number of spot vessel opportunities in 2013 as compared to those in 2012, a reduction in utilization rates resulting from greater than usual seasonal declines in the North Sea in early 2013 and lower year-over-year trenching activities associated with the deferral of many previously anticipated 2013 trenching projects in the North Sea region to 2014 and beyond.
 
Our Production Facilities revenues increased by 10% in 2013 as compared to 2012, which reflected a substantial increase in our total revenues under the fee arrangement with ERT for the use of the HP I to process production from the Phoenix field, which was revised following our sale of ERT in February 2013.  Revenues generated by the HP I were eliminated in consolidation prior to the sale of ERT.  The quarterly HFRS retainer fee also increased effective April 1, 2013 as a result of a new set of four-year agreements. 
 
Our Subsea Construction revenues decreased by 63% in 2013 as compared to 2012 reflecting the sale of both the Caesar and the Express in mid-2013.
 
Gross Profit.  Our gross profit increased significantly in 2013 as compared to 2012.  In 2012, we recorded asset impairment charges of $177.1 million, including $157.8 million for the Caesar and related mobile pipelay equipment, $14.6 million for the Intrepid, and $4.6 million for well intervention assets associated with our former operations in Australia (Note 2).  Absent the effect of the impairment charges, our gross profit increased by 15% in 2013 as compared to 2012.
 
Our Well Intervention gross profit increased by 42% in 2013 as compared to 2012 primarily reflecting revenue increases as a result of the addition of the Skandi Constructor and improved utilization rates in 2013. 
 
Our Robotics gross profit decreased by 14% in 2013 as compared to 2012 reflecting a high volume of lower gross margin work in 2013 in an effort to reduce the idle time of our robotics assets.  The increased pressure of this business reflected a tight market in the North Sea region in early 2013 and a light trenching market throughout 2013 following a good year of such activity in 2012.
 
 
Our Production Facilities gross profit increased by 25% in 2013 as compared to 2012.  The positive variance reflected both the increased processing fees under the revised contract with ERT following the completion of its sale in February 2013, and the higher retainer fee under the new HFRS agreements that went into effect in April 2013.
 
The increase in Subsea Construction gross profit in 2013 as compared to 2012 primarily reflected the $172.4 million of impairment charges we recorded in 2012, offset in part by our pipelay vessels only being in operation for the first half of 2013 prior to their sale as compared to a full year of operations in 2012.
 
Loss on Commodity Derivative Contracts.  In December 2012, following the announcement of the sale of ERT, we de-designated our oil and gas commodity derivative contracts and interest rate swap contracts as hedging instruments (Note 15).  The $14.1 million loss on commodity derivative contracts in 2013 reflected the net loss on our oil and gas commodity derivative contracts during the first quarter of 2013.  In February 2013, we paid approximately $22.5 million to settle our remaining open commodity derivative contracts.  The $10.5 million loss on commodity derivative contracts in 2012 reflected the amount of mark-to-market loss of unsettled oil and gas commodity derivative contracts associated with de-designation of these contracts as hedging instruments. 
 
Gain (Loss) on Disposition of Assets, Net.  The $14.7 million net gain on disposition of assets for 2013 primarily reflected a $1.1 million loss on the sale of the Caesar in June 2013 and a $15.6 million gain on the sale of the Express in July 2013 (Note 2).  The $13.5 million loss on the disposition of assets in 2012 reflected the sale of the Intrepid in September 2012. 
 
Selling, General and Administrative Expenses.  Our selling, general and administrative expenses decreased by $12.2 million in 2013 as compared to 2012.  The decrease reflected the reduction in the size of our organization following the sales of ERT, the Caesar and the Express, and the related effect of these transactions on the level of our corporate staffing.  This decrease in our selling, general and administrative expenses was partially offset by approximately $1.9 million of severance related costs and $2.2 million associated with the provision for uncertain collection of a portion of our existing trade receivables in 2013 (Note 14).  Additionally, the 2012 amount included approximately $3.5 million of severance and other closure costs associated with our decision to sell our remaining pipelay assets, to cease our Australian well intervention operations and to terminate the remaining lease term and other related closure costs associated with our former office in Rotterdam, The Netherlands.  Lastly, our 2012 amount also included $2.6 million drawn against a letter of credit related to an international well abandonment project that was completed in 2011, of which amount $2.3 million (net of certain costs associated with the recovery) was recovered in 2014. 
 
Equity in Earnings of Investments.  Equity in earnings of investments decreased by $5.5 million in 2013 as compared to 2012.  The decrease was primarily due to Independence Hub receiving lower fees from major customers of the facility following the expiration of a five-year supplemental monthly demand fee in March 2012 and lower throughput at both the Deepwater Gateway and Independence Hub facilities. 
 
Net Interest Expense.  Our net interest expense totaled $32.9 million in 2013 as compared to $48.2 million in 2012.  The decrease consisted of both a reduction in interest expense and increases in capitalized interest and interest income.  The decrease in interest expense reflected the substantial reduction in our indebtedness, including the $318.4 million repayment of debt in February 2013 following the sale of ERT, the early redemption of $200 million of our Senior Unsecured Notes in March 2012 and our redemption in July 2013 of the remaining $275 million of the Senior Unsecured Notes then outstanding.  Capitalized interest totaled $10.4 million for 2013 as compared to $4.9 million for 2012.  Interest income totaled $1.2 million for 2013 as compared to $0.5 million for 2012, reflecting our increased average cash on hand during 2013. 
 
Loss on Early Extinguishment of Long-term Debt.  The $12.1 million loss in 2013 included the $8.6 million loss on our redemption in July 2013 of the remaining $275 million Senior Unsecured Notes outstanding and the acceleration of the remaining deferred financing fees related to the term loan component of our former credit agreement following the repayment of that indebtedness.  The charges of $17.1 million in 2012 were associated with the early extinguishment of portions of our debt, including $11.5 million related to our redemption of $200 million of our Senior Unsecured Notes and $5.6 million related to our repurchase of $142.2 million of our 2025 Notes.  See Note 6 for information regarding our debt repayments.
 
 
Other Income – Oil and Gas.  The $6.6 million income for 2013 reflected the proceeds associated with our overriding royalty interests in ERT’s Wang well, which commenced production in late April 2013, and cash payments related to services we provided to ERT following its sale in February 2013.
 
Income Tax Provision (Benefit).  Income taxes reflected an expense of $31.6 million in 2013 as compared to a benefit of $59.2 million in 2012.  The variance primarily reflected increased profitability in 2013 as compared to 2012.  The effective tax rate for 2013 was a 22.0% expense.  The effective tax rate for 2012 was a 47.0% benefit.  The variance was primarily attributable to increased profitability of operations located within the United States.
 
Oil and Gas
 
All of our oil and gas assets sold in February 2013 were located in the U.S. Gulf of Mexico.  The operating results of our discontinued oil and gas operations during 2012 and 2013 are presented in Note 13.  Our continuing operations include one oil and gas property located offshore of the United Kingdom (“U.K.”).  We completed the reclamation activities of this offshore property in 2013 in accordance with the applicable U.K. regulations (Note 13).  We had no revenues associated with our U.K. oil and gas property during the three-year period ended December 31, 2014.  There were no operating costs associated with this U.K. property in 2013 and 2014.  Operating costs for 2012 totaled $0.7 million.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Overview 
 
The following table presents certain information useful in the analysis of our financial condition and liquidity as of December 31, 2014 and 2013 (in thousands): 
 
   
2014
   
2013
 
             
Net working capital
  $ 468,660     $ 553,427  
Long-term debt (1)
  $ 523,228     $ 545,776  
Liquidity (2)
  $ 1,060,092     $ 1,062,413  
 
(1)  
Long-term debt does not include the current maturities portion of the long-term debt as that amount is included in net working capital.  It is also net of the unamortized debt discount on the 2032 Notes.  See Note 6 for information related 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, 2014 included cash and cash equivalents of $476.5 million and $583.6 million of available borrowing capacity under our Revolving Credit Facility (Note 6).  Our liquidity at December 31, 2013 included cash and cash equivalents of $478.2 million and $584.2 million of available borrowing capacity under our Revolving Credit Facility.
 
The carrying amount of our long-term debt, including current maturities, as of December 31, 2014 and 2013 is as follows (in thousands): 
 
   
2014
   
2013
 
             
Term Loan (matures June 2018)
  $ 277,500     $ 292,500  
2032 Notes (mature March 2032) (1)
    179,080       173,484  
MARAD Debt (matures February 2027)
    94,792       100,168  
Total debt
  $ 551,372     $ 566,152  
 
(1)  
These amounts are net of the unamortized debt discount of $20.9 million and $26.5 million, respectively.  The 2032 Notes will increase to their $200 million 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,
 
   
2014
   
2013
   
2012
 
Cash provided by (used in):
                 
Operating activities
  $ 359,485     $ 104,861     $ 176,068  
Investing activities
  $ (335,512 )   $ (126,077 )   $ (295,712 )
Financing activities
  $ (30,071 )   $ (487,421 )   $ (145,232 )
Discontinued operations (1)
  $
    $ 552,462     $ 156,373  
 
(1)  
Represents total cash flows associated with the operations of ERT.  ERT was sold in February 2013.  Proceeds from the sale of ERT totaled $614.8 million, net of transaction costs.  Other cash flows in the table above reflect our continuing operations. 
 
Our current requirements for cash primarily reflect the need to fund capital expenditures 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 use of project financing along with other debt and equity alternatives. 
 
As a further response to the recent announcements regarding industry-wide reductions in capital spending, 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 internally-generated cash flows, available borrowing capacity under our Revolving Credit Facility and the Nordea Credit Agreement will be sufficient to fund our operations over at least the next twelve months. 
 
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 consolidated leverage ratio, as well as the maintenance of minimum 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 Credit Agreement indebtedness) secured by the underlying asset, provided that such indebtedness is not guaranteed by us.  The 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 of December 31, 2014 and 2013, we were in compliance with all of our debt covenants. 
 
A prolonged period of weak economic 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, our ability to access the full available commitment of $600 million under our revolving credit facility may be impacted.  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, such 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. 
 
In July 2013, we borrowed $300 million under our Term Loan in connection with our early redemption of the remaining $275 million Senior Unsecured Notes then outstanding.  We may borrow and/or obtain letters of credit up to $600 million under our Revolving Credit Facility.  Subject to customary conditions, we may request that aggregate commitments with respect to the Revolving Credit Facility be increased by, or additional term loans be made of, or a combination thereof, up to $200 million.  See Note 6 for additional information relating to our long-term debt, including more information regarding our current and former credit agreements, including covenants and collateral. 
 
 
The 2032 Notes can be converted to our common stock prior to their stated maturity upon certain triggering events specified in the Indenture governing the notes.  Beginning in 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, 2014 and 2013. 
 
Operating Cash Flows 
 
Total cash flows from operating activities increased by $285.1 million in 2014 as compared to 2013 primarily reflecting increases in income from operations, changes in working capital, and a $35.2 million income tax refund we received in September 2014 from the IRS.  Operating cash flows for 2013 also included $30.5 million of net cash used in discontinued operations related to ERT, which we sold in February 2013. 
 
Total cash flows from operating activities decreased by $378.1 million in 2013 as compared to 2012 primarily reflecting the sales of ERT and our remaining pipelay vessels, payment of taxes associated with the sales, and the related settlement of our oil and gas commodity derivatives.
 
Investing Activities 
 
Capital expenditures have consisted principally of the purchase or construction of dynamically positioned vessels, improvements and modifications to existing assets, and investments in our production facilities.  Significant sources (uses) of cash associated with investing activities for the years ended December 31, 2014, 2013 and 2012 are as follows (in thousands): 
 
   
Year Ended December 31,
 
   
2014
   
2013
   
2012
 
Capital expenditures:
                 
Well Intervention
  $ (283,635 )   $ (283,132 )   $ (274,451 )
Robotics
    (51,348 )     (39,655 )     (44,500 )
Production Facilities
    (869 )     (1,252 )     (823 )
Other
    (1,060 )     (387 )     (3,265 )
Distributions from equity investments, net (1)
    7,911       9,295       7,797  
Proceeds from sale of assets (2)
    13,574       189,054       19,530  
Acquisition of noncontrolling interests (3)
    (20,085 )    
     
 
Net cash used in investing activities – continuing operations
    (335,512 )     (126,077 )     (295,712 )
Oil and Gas capital expenditures
   
      (31,855 )     (125,423 )
Proceeds from sale of ERT, net of transaction costs
   
      614,820      
 
Other
   
     
      5,366  
Net cash provided by (used in) investing activities – discontinued operations
   
      582,965       (120,057 )
Net cash provided by (used in) investing activities
  $ (335,512 )   $ 456,888     $ (415,769 )
 
(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, 2014, 2013 and 2012 were $8.8 million, $12.3 million and $16.2 million, respectively (Note 4). 
 
(2)  
Primarily reflects cash received from the sale of our Ingleside spoolbase in early 2014, the sale of both the Caesar and the Express in mid-year 2013, and the sale of the Intrepid and certain equipment associated with our former Australian well intervention operations in 2012.
 
(3)  
Relates to the acquisition in February 2014 of our former minority partner’s noncontrolling interests in Kommandor LLC, the entity that owns the HP I (Notes 2 and 5). 
 
Capital expenditures associated with our business primarily include payments associated with the construction of our Q5000 and Q7000 vessels (see below), payments in connection with the acquisition and subsequent upgrades and modifications of the Helix 534 (see below), the investment in the topside well intervention equipment for the two newbuild monohull vessels that are expected to be used in service for Petrobras (see below) and the costs incurred in the acquisition of additional ROVs and trenchers for our robotics business. 
 
In March 2012, we executed a contract with a shipyard in Singapore for the construction of a newbuild semi-submersible well intervention vessel, the Q5000.  This $386.5 million shipyard contract represents the majority of the expected costs associated with the construction of the Q5000.  Pursuant to the terms of this contract, payments are made in a fixed percentage of the contract price, together with any variations, on contractually scheduled dates.  At December 31, 2014, our total investment in the Q5000 was $342.4 million, including $289.4 million of scheduled payments made to the shipyard.  We plan to incur approximately $155 million on the Q5000 in 2015, including the last remaining shipyard payment of $97.1 million.  We currently anticipate the vessel being available to perform well intervention services in the second half of 2015.  In September 2014, we entered into the Nordea Credit Agreement to partially finance the construction of the Q5000 and other future capital projects (Note 6).  The Nordea Term Loan will be funded at or near the time of the delivery of the Q5000, which is expected to occur in the second quarter of 2015.
 
In September 2013, we executed a second contract with the same shipyard in Singapore that is currently constructing the Q5000.  This contract provides for the construction of a newbuild semi-submersible well intervention vessel, the Q7000, which will be built to North Sea standards.  This $346.0 million shipyard contract represents the majority of the expected costs associated with the construction of the Q7000.  Pursuant to the terms of this contract, 20% of the contract price was paid upon the signing of the contract and the remaining 80% will be paid upon the delivery of the vessel, which is expected to occur in 2016.  At December 31, 2014, our total investment in the Q7000 was $91.8 million, including $69.2 million paid to the shipyard upon signing the contract.  In 2015, we plan to incur approximately $40 million of costs related to the construction of the Q7000
 
In February 2014, we entered into agreements with Petrobras to provide well intervention services offshore Brazil.  The initial term of the agreements with Petrobras is for four years with options to extend.  In connection with the Petrobras agreements, we entered into charter agreements with Siem Offshore AS for two newbuild monohull vessels, both of which are expected to be in service for Petrobras in 2016.  Our total investment in the topside equipment for both vessels is expected to be approximately $260 million.  We have invested $52.0 million as of December 31, 2014 and plan to invest approximately $65 million in the topside equipment in 2015.
 
Net cash used in discontinued operations relates to capital expenditures associated with ERT.  Oil and Gas capital expenditures for the first quarter of 2013 included costs associated with the exploration and development activities primarily related to the Wang well within the Phoenix field at Green Canyon Block 237.
 
Outlook 
 
We anticipate that our capital expenditures in 2015 will total approximately $400 million.  This estimate may increase or decrease based on various economic factors and/or the existence of additional investment opportunities.  However, we may reduce the level of our planned future capital expenditures given any prolonged economic downturn.  We believe that our cash on hand, internally-generated cash flows, and availability under our current credit facility will provide the capital necessary to continue funding our 2015 initiatives.
 
Contractual Obligations and Commercial Commitments 
 
The following table summarizes our contractual cash obligations as of December 31, 2014 and the scheduled years in which the obligations are contractually due (in thousands): 
 
 
         
Less Than
               
More Than
 
   
Total (1)
   
1 Year
   
1-3 Years
   
3-5 Years
   
5 Years
 
                               
2032 Notes (2)
  $ 200,000     $
    $
    $
    $ 200,000  
Term Loan (3)
    277,500       22,500       60,000       195,000      
 
MARAD debt
    94,792       5,644       12,148       13,390       63,610  
Interest related to debt (4)
    184,031       24,475       42,743       24,380       92,433  
Property and equipment (5)
    505,393       199,646       305,747      
     
 
Operating leases (6)
    1,030,094       139,983       328,728       257,790       303,593  
Total cash obligations
  $ 2,291,810     $ 392,248