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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

 

WASHINGTON, D.C. 20549

 

FORM 10-K

 

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

For the fiscal year ended December 31, 2015

OR

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

 

Commission file number 001-33607

 

GulfMark Offshore, Inc.

(Exact name of registrant as specified in its charter)

Delaware

76-0526032

(State or other jurisdiction of incorporation or organization)

(I.R.S. Employer Identification No.)

 

 

842 West Sam Houston Parkway North, Suite 400

 

Houston, Texas

77024

(Address of principal executive offices)

(Zip Code)

 

Registrant’s telephone number, including area code: (713) 963-9522

 

Securities registered pursuant to Section 12(b) of the Act:

 

Class A Common Stock, $0.01 par value New York Stock Exchange

 

(Title of each class) (Name of each exchange on which registered)

 

Securities registered pursuant to Section 12(g) of the Act: None

 

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filings requirements for the past 90 days. Yes No

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, 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). Yes No

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation in S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of the 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 definition of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Large accelerated filer ☐ Accelerated filer

Non-accelerated filer (Do not check if a smaller reporting company) Smaller reporting company

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No

 

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2015, the last business day of the registrant’s most recently completed second fiscal quarter was $278,976,894 calculated by reference to the closing price of $11.60 for the registrant’s common stock on the New York Stock Exchange on that date.

 

Number of shares of Class A common stock outstanding as of February 26, 2016: 25,809,612

 

DOCUMENTS INCORPORATED BY REFERENCE

 

The information called for by Part III, Items 10, 11, 12, 13 and 14 of this Form 10-K, will be included in a

definitive proxy statement to be filed pursuant to Regulation 14A within 120 days after the end of

the fiscal year covered by this Form 10-K, and is incorporated herein by reference.

 

 
 

 

 

TABLE OF CONTENTS

 

   

Page

     

PART I

   

Item 1.

Business 

5

 

General Business

5

 

Worldwide Fleet

6

 

Operating Segments

11

 

Other

14

Item 1A.

Risk Factors

18

Item 1B.

Unresolved Staff Comments

30

Item 2.

Properties

  30

Item 3.

Legal Proceedings

30

Item 4.

Mine Safety Disclosures

30

     

PART II

   

Item 5.

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

31

Item 6.

Selected Financial Data

33

Item 7.

Management’s Discussion and Analysis of Financial Condition and Results of Operations

35

Item 7A.

Quantitative and Qualitative Disclosures about Market Risk

53

Item 8.

Financial Statements and Supplementary Data

55

Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

86

Item 9A.

Controls and Procedures

86

Item 9B.

Other Information

86

     

PART III

   

Item 10.

Directors, Executive Officers and Corporate Governance

86

Item 11.

Executive Compensation

86

Item 12.

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

86

Item 13.

Certain Relationships and Related Transactions, and Director Independence

86

Item 14.

Principal Accountant Fees and Services

86

     

PART IV

   

Item 15.

Exhibits and Financial Statement Schedules

87

 

 
2

 

 

Forward-Looking Statements

 

This Annual Report on Form 10-K, particularly in Part I, Item 1 “Business” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” may contain certain forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, or the Securities Act, and Section 21E of the Securities Exchange Act of 1934, as amended, or the Exchange Act. All statements other than statements of historical fact are, or may be deemed to be, forward-looking statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements, and may contain or be identified by the words “expect,” “intend,” “plan,” “predict,” “anticipate,” “estimate,” “believe,” “should,” “could,” “may,” “might,” “will,” “project,” “forecast,” “budget” and similar expressions. In addition, any statement concerning future financial performance (including, without limitation, future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by or against us, which may be provided by management, are also forward-looking statements as so defined. Statements made by us in this report that contain forward-looking statements may include, but are not limited to, information concerning our possible or assumed future results of operations and statements about the following subjects:

 

 

market conditions and the effect of such conditions on our future results of operations;

 

demand for marine supply and transportation services;

 

supply of vessels and companies providing services;

 

future capital expenditures and budgets for capital and other expenditures;

 

sources and uses of and requirements for financial resources;

 

market outlook;

 

operations outside the United States;

 

contractual obligations;

 

cash flows and contract backlog;

 

timing and cost of completion of vessel upgrades, construction projects and other capital projects;

 

asset impairments and impairment evaluations;

 

assets held for sale;

 

business strategy;

 

growth opportunities;

 

competitive position;

 

expected financial position;

 

interest rate and foreign exchange risk;

 

financing plans;

 

tax planning;

 

debt levels and the impact of changes in the credit markets and credit ratings for our debt;

 

timing and duration of required regulatory inspections for our vessels;

 

plans and objectives of management;

 

effective date and performance of contracts;

 

outcomes of legal proceedings;

 

compliance with applicable laws;

 

declaration and payment of dividends; and

 

availability, limits and adequacy of insurance or indemnification.

 

These types of statements are based on current expectations about future events and inherently are subject to certain risks, uncertainties and assumptions, many of which are beyond our control, which could cause actual results to differ materially from those expected, projected or expressed in forward-looking statements. It should be understood that it is not possible to predict or identify all risks, uncertainties and assumptions. These risks, uncertainties and assumptions include, among others, the following:

 

 

the risk factors discussed in Part I, Item 1A “Risk Factors”;

 

operational risk;

 

significant and sustained additional declines in oil and natural gas prices;

 

sustained weakening of demand for our services;

 

general economic and business conditions;

 

the business opportunities that may be presented to and pursued by us;

 

changes in law or regulations including, without limitation, changes in tax laws;

 

fewer than anticipated deepwater and ultra-deepwater drilling units operating in the Gulf of Mexico or other regions in which we operate;

 

unanticipated difficulty in effectively competing in or operating in international markets;

 

the level of fleet additions by us and our competitors that could result in overcapacity in the markets in which we compete;

 

 
3

 

 

 

advances in exploration and development technology;

 

dependence on the oil and natural gas industry;

 

drydocking delays or cost overruns on construction projects or insolvency of shipbuilders;

 

inability to accurately predict vessel utilization levels and day rates;

 

lack of shipyard or equipment availability;

 

our inability to successfully complete the remainder of our current vessel new build programs on-time and on-budget;

 

unplanned customer suspensions, cancellations, rate reductions or non-renewals;

 

further reductions in capital expenditure budgets by customers;

 

ongoing capital expenditure requirements;

 

uncertainties surrounding deepwater permitting and exploration and development activities;

 

risks relating to compliance with the Jones Act, including the repeal or administrative weakening of the Jones Act or changes in the interpretation of the Jones Act related to the U.S. citizenship qualification;

 

uncertainties surrounding environmental and government regulations that could result in reduced exploration and production activities or that could increase our operations costs and operating requirements;

 

catastrophic or adverse sea or weather conditions;

 

risks of foreign operations, risk of war, sabotage, piracy, cyber-attack or terrorism;

 

public health threats;

 

disagreements with our joint venture partners;

 

assumptions concerning competition;

 

risks relating to leverage;

 

risks of currency fluctuations; and

 

the shortage of or the inability to attract and retain qualified personnel.

 

These statements are based on certain assumptions and analyses made by us in light of our experience and perception of historical trends, current conditions, expected future developments and other factors we believe are appropriate under the circumstances. There can be no assurance that we have accurately identified and properly weighed all of the factors that affect market conditions and demand for our vessels, that the information upon which we have relied is accurate or complete, that our analysis of the market and demand for our vessels is correct or that the strategy based on such analysis will be successful.

 

The risks and uncertainties included here are not exhaustive. Other sections of this report and our other filings with the Securities and Exchange Commission, or SEC, include additional factors that could adversely affect our business, results of operations and financial performance. Given these risks and uncertainties, investors should not place undue reliance on forward-looking statements. Forward-looking statements included in this report are based only on information currently available to us and speak only as of the date of this report. We expressly disclaim any obligation or undertaking to release publicly any updates or revisions to any forward-looking statement to reflect any change in our expectations or beliefs with regard to the statement or any change in events, conditions or circumstances on which any forward-looking statement is based. In addition, in certain places in this report, we may refer to reports published by third parties that purport to describe trends or developments in energy production and drilling and exploration activity. We do so for the convenience of our investors and potential investors and in an effort to provide information available in the market intended to lead to a better understanding of the market environment in which we operate. We specifically disclaim any responsibility for the accuracy and completeness of such information and undertake no obligation to update such information.

 

 
4

 

  

PART I

 

ITEM 1. Business

GENERAL BUSINESS

Our Company

 

GulfMark Offshore, Inc., a Delaware corporation, was incorporated in 1996. We provide offshore marine support and transportation services primarily to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport materials, supplies and personnel to offshore facilities, and also move and position drilling and production facilities. The majority of our operations are conducted in the North Sea, offshore Southeast Asia and offshore the Americas. We currently operate a fleet of 73 owned or managed offshore supply vessels, or OSVs, in the following regions: 30 vessels in the North Sea, 13 vessels offshore Southeast Asia, and 30 vessels offshore the Americas. Our fleet is one of the world’s youngest, largest and most geographically balanced, high specification OSV fleets. Our owned vessels have an average age of approximately nine years.

 

We have three operating segments: the North Sea, Southeast Asia and the Americas. Our chief operating decision maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate our performance. Our operations within each of these geographic regions have similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under Financial Accounting Standards Board, or FASB, Accounting Standards Codification No. 280, “Segment Reporting,” or ASC 280. For financial information about our operating segments and geographic areas, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Segment Results” included in Part II, Item 7, and Note 12 to our Consolidated Financial Statements included in Part II, Item 8.

 

Unless otherwise indicated, references to “we”, “us”, “our” and the “Company” refer to GulfMark Offshore, Inc., its subsidiaries and its predecessors.

 

Our principal executive offices are located at 842 West Sam Houston Parkway North, Suite 400, Houston, Texas 77024, and our telephone number at that address is (713) 963-9522. We file annual, quarterly, and current reports, proxy statements and other information with the Securities and Exchange Commission, or SEC. Our SEC filings are available free of charge to the public over the internet on our website at http://www.gulfmark.com and at the SEC’s website at http://www.sec.gov. The information provided on our website is not part of this report and is not incorporated by reference in this report. Filings are available on our website as soon as reasonably practicable after we electronically file them with or furnish them to the SEC. You may also read and copy any document we file at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330.

 

Offshore Marine Services Industry Overview

 

We utilize our vessels to provide services to our customers supporting the construction, positioning and ongoing operation of offshore oil and natural gas drilling rigs and platforms and related infrastructure, and substantially all of our revenue is derived from providing these services. The offshore marine services industry employs various types of OSVs that are used to transport materials, supplies and personnel, and to move and position drilling and production facilities. Offshore marine service providers are employed by companies that are engaged in the offshore exploration and production of oil and natural gas and related services. Services provided by companies in this industry are performed in numerous locations worldwide. The major markets that employ a large number of vessels include the North Sea, offshore Southeast Asia, offshore West Africa, offshore the Middle East, offshore Brazil and the U.S. Gulf of Mexico. Vessel usage is also significant in other international markets, including offshore India, offshore Australia, offshore Trinidad, the Persian Gulf, the Mediterranean Sea, offshore Russia and offshore East Africa. The industry is fragmented with many multi-national and regional competitors.

 

Our business is directly impacted by the level of activity in worldwide offshore oil and natural gas exploration, development and production, which in turn is influenced by trends in oil and natural gas prices. In addition, oil and natural gas prices are affected by a host of geopolitical and economic forces, including the fundamental principles of supply and demand. Beginning in late 2014, the oil and gas industry experienced a significant decline in the price of oil causing an industry-wide downturn which continued through 2015 and into 2016. During that time, the price of oil declined significantly from over $100 per barrel in July 2014 to below $30 per barrel in February 2016. This downturn has impacted the operational plans for oil companies, resulting in reduced spending for exploration and production activities, and consequently has adversely affected the drilling and support service sector. These changes in industry dynamics decreased demand for OSV services and led to an excess number of vessels in all of our operating regions. We experienced a significant negative impact on day rates and utilization in 2015 that is continuing into 2016. In many regions, day rates for OSV services have fallen below levels needed to sustain our business.

 

The characteristics and current marketing environment in each operating segment are discussed below in greater detail. Each of the major geographic offshore oil and natural gas production regions has unique characteristics that influence the economics of exploration and production and, consequently, the market demand for vessels in support of these activities. While there is some vessel interchangeability between geographic regions, barriers such as mobilization costs, vessel suitability and cabotage restrict migration of some vessels between regions. This is most notable in the North Sea, where vessel design requirements dictated by the harsh operating environment may restrict relocation of vessels into that market and in the U.S. Gulf of Mexico, where entry into the market is subject to the Jones Act restrictions. Conversely, these same design characteristics make North Sea capable vessels unsuitable for other areas where draft restrictions and, to a lesser degree, higher operating costs, restrict migration.

 

 
5

 

 

WORLDWIDE FLEET

 

In addition to the vessels we own, we manage vessels for third-party owners, providing support services ranging from chartering assistance to full operational management. Although these managed vessels provide limited direct financial contribution, the added market presence can provide a competitive advantage for the manager. In addition, as a result of the industry downturn, we have removed some vessels from active service (also called stacking) to preserve cash flow. The following table summarizes our overall owned, managed and total fleet changes since December 31, 2014 and our stacked vessels as of February 29, 2016:

    

   

Owned

Vessels

   

Managed

Vessels

   

Total

Fleet

 

December 31, 2014

    72       4       76  

New-Build Program

    1       -       1  

Vessel Additions

    -       -       -  

Vessel Dispositions

    (3 )     (1 )     (4 )

December 31, 2015

    70       3       73  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

February 29, 2016

    70       3       73  
                         

Stacked vessels

    37       3       40  

 

Vessel Classifications

 

OSVs generally fall into one or more of seven functional classifications derived from their primary or predominant operating characteristics or capabilities. These classifications are not rigid, however, and it is not unusual for a vessel to fit into more than one of the categories. These functional classifications are:

 

 

Anchor Handling, Towing and Support Vessels, or AHTSs, are used to set anchors for drilling rigs and to tow mobile drilling rigs and equipment from one location to another. In addition, these vessels typically can be used in supply roles when they are not performing anchor handling and towing services. They are characterized by shorter after decks and special equipment such as towing winches. Vessels of this type with less than 10,000 brake horsepower, or BHP, are referred to as small AHTSs, or SmAHTSs, while AHTSs in excess of 10,000 BHP are referred to as large AHTSs, or LgAHTSs. The most powerful North Sea class AHTSs have up to 25,000 BHP. All of our AHTSs can also function as platform supply vessels.

 

 

Platform Supply Vessels, or PSVs, serve drilling and production facilities and support offshore construction and maintenance work. They are differentiated from other OSVs by their cargo handling capabilities, particularly their large capacity and versatility. PSVs utilize space on deck and below deck and are used to transport supplies such as fuel, water, drilling fluids, equipment and provisions. PSVs typically range in size from 150 to 300 feet. Large PSVs, or LgPSVs, generally range from 210 to 300 feet in length, with a few vessels somewhat larger, and are particularly suited for supporting large concentrations of offshore production locations because of their large, clear after deck and below deck capacities. The majority of the LgPSVs we operate function primarily in this classification but are also capable of servicing construction support.

 

 

Fast Supply or Crew Vessels, or FSVs or crewboats, transport personnel and cargo to and from production platforms and rigs. Older crewboats (early 1980s build or earlier) are typically 100 to 120 feet in length, and are designed for speed and to transport personnel. Newer crewboat designs are generally larger, 130 to 185 feet in length, and can be longer with greater cargo carrying capacities. Vessels in the larger category are also called fast supply vessels. They are used primarily to transport cargo on a time-sensitive basis.

 

 

Specialty Vessels, or SpVs, generally have special features to meet the requirements of specific jobs. The special features can include large deck spaces, high electrical generating capacities, slow controlled speed and varied propulsion thruster configurations, extra berthing facilities and long-range capabilities. These vessels are primarily used to support floating production storing and offloading; diving operations; remotely operated vehicles; survey operations and seismic data gathering; as well as oil recovery, oil spill response and well stimulation. Some of our owned vessels frequently provide specialty functions.

  

 
6

 

 

 

Standby Rescue Vessels, perform a safety patrol function for a particular area and are required for all manned locations in the North Sea and in some other locations where oil and natural gas exploitation occurs. These vessels typically remain on station to provide a safety backup to offshore rigs and production facilities and carry special equipment to rescue personnel. They are equipped to provide first aid, shelter and, in some cases, function as support vessels.

 

 

Construction Support Vessels are vessels such as pipe-laying barges, diving support vessels or specially designed vessels, such as pipe carriers, used to transport the large cargos of material and supplies required to support the construction and installation of offshore platforms and pipelines. A large number of our LgPSVs also function as pipe carriers.

 

 

Utility Vessels are typically 90 to 150 feet in length and are used to provide limited crew transportation, some transportation of oilfield support equipment and, in some locations, standby functions.

 

The following table summarizes our owned vessel fleet by classification and by region as of February 29, 2016:

 

Owned Vessels by Classification

 
   

AHTS

   

PSV

                         

Region

 

LgAHTS

   

SmAHTS

   

LgPSV

   

PSV

   

FSV

   

SpV

   

Total

 
                                                         

North Sea

    3       -       23       -       -       1       27  

Southeast Asia

    8       4       1       -       -       -       13  

Americas

    -       2       20       4       3       1       30  
      11       6       44       4       3       2       70  

  

Vessel Construction, Acquisitions and Divestitures

 

During 2015, we sold three older vessels from our North Sea region fleet for combined proceeds of $8.9 million. The sales of these vessels generated a combined loss on sales of assets of $1.2 million.

 

We are currently in the latter stages of a 12 vessel new-build program that began in 2011. We began the program in the North Sea region where we contracted with three shipyards to build a total of seven PSVs for an original estimated cost of $288.0 million. The first four of these vessels were delivered in the third quarter of 2013, the fifth vessel in the fourth quarter of 2013 and the sixth and seventh vessels in the first quarter of 2014.

 

In 2012, we entered into separate agreements with two U.S. shipyards (Thoma-Sea and BAE Systems) contracting in each case to build two U.S. flagged PSVs for the U.S. Gulf of Mexico region. The original estimated total cost of these four PSVs was approximately $168.0 million. The Thoma-Sea vessels were delivered in the second quarter of 2014 and January 2015. We expect delivery of the BAE Systems vessels in the third and fourth quarters of 2016 and expect to make final payments in 2016 to BAE Systems totaling $30.8 million.

 

In April 2014, we approved the construction of an additional North Sea PSV by Simek, one of the three shipyards in the original program discussed above, with an estimated total cost of 359.0 million NOK (or approximately $40.9 million at December 31, 2015, but which was equivalent to approximately $60.0 million based on exchange rates in effect at the contract date) and an initial expected delivery date in the first quarter of 2016. In the fourth quarter of 2015, we amended our contract with Simek to delay delivery of the vessel until January 2017. Concurrently, we agreed to pay installments in the aggregate of 92.2 million NOK (or approximately $10.4 million at December 31, 2015) through May 2016 and a final installment of 195.0 million NOK (or approximately $22.1 million at December 31, 2015) in January 2017.

 

 
7

 

 

The following tables illustrate the details of the vessels under construction, the vessels added or acquired and vessels disposed of:

  

Vessels Under Construction as of February 29, 2016

 

Construction Yard

Region

Type(1)

Expected

Delivery

 

Length

(feet)

   

BHP(2)

   

DWT(3)

   

Expected Cost

 
                                 

(millions)

 

BAE Systems

Americas

LgPSV

Q3 2016

    286       10,960       5,300     $ 48.0  

BAE Systems

Americas

LgPSV

Q4 2016

    286       10,960       5,300     $ 48.0  

Simek

N. Sea

LgPSV

Q1 2017

    304       11,935       4,700     $ 60.0  

 

Note: Final cost may differ due to foreign currency fluctuations.                   

   

Vessel Additions Since December 31, 2014

Vessel

Region

Type(1)

Year

Built

 

Length

(feet)

   

BHP(2)

   

DWT(3)

 

Month

Delivered

                                 

Regulus

Americas

LgPSV

2015

    272       9,849       3,580  

Jan-15

  

Vessels Disposed of Since December 31, 2014

Vessel

Region

Type(1)

Year

Built

 

Length

(feet)

   

BHP(2)

   

DWT(3)

 

Month

Disposed

                                 

North Truck

N. Sea

LgPSV

1983

    265       6,120       3,370  

Jan-15

Highland Trader

N. Sea

LgPSV

1996

    220       5,450       3,115  

Jul-15

Highland Star

N. Sea

LgPSV

1991

    268       6,600       3,075  

Nov-15

 

(1) LgPSV - Large Platform Supply Vessel                

(2)BHP - Brake Horsepower                

(3)DWT - Deadweight Tons                

 

In addition to the vessel activity presented in the tables above, in our Americas segment, in 2015 we completed our 15 vessel program to lengthen certain vessels to increase their marketing value in the U.S. Gulf of Mexico market.

 

Maintenance of Our Vessels and Drydocking Obligations

 

In addition to repairs, we are required to make expenditures for the certification and maintenance of our actively marketed vessels, and those expenditures typically increase with the age of the vessels. We have determined that we will not maintain stacked vessels in class until they are likely to achieve profitable return to market. The demands of the market, management judgment as to which vessels to market and which vessels to stack, the expiration of existing contracts, the start of new contracts, and customer preferences influence the timing of drydocks. Our drydocking expenditures for 14 drydocks in 2015 totaled $15.4 million. Future drydock costs will be dependent on vessel activity and vessel class requirements.

 

 
8

 

 

Vessel Listing

 

Currently, we operate a fleet of 73 vessels. The 70 vessels that we own are listed in the table below (which excludes the three vessels we manage for other owners):

 

Owned Vessel Fleet

Vessel

Region

Type (1)

Year

Built

Length

(feet)

BHP(2)

DWT (3)

Flag
               

Highland Challenger

N. Sea

LgPSV

1997

220

5,450

3,115

UK

Highland Rover(4)

N. Sea

LgPSV

1998

236

5,450

3,200

Malta

North Stream

N. Sea

LgPSV

1998

276

9,600

4,585

Norway

Highland Spirit

N. Sea

SpV

1998

202

6,000

1,620

UK

Highland Fortress

N. Sea

LgPSV

2001

236

5,450

3,200

Malta

Highland Bugler

N. Sea

LgPSV

2002

220

5,450

2,986

UK

Highland Navigator

N. Sea

LgPSV

2002

276

9,600

4,510

Malta

North Mariner

N. Sea

LgPSV

2002

276

9,600

4,400

Norway

Highland Courage

N. Sea

LgAHTS

2002

262

16,320

2,750

Malta

Highland Citadel

N. Sea

LgPSV

2003

236

5,450

3,280

UK

Highland Eagle

N. Sea

LgPSV

2003

236

5,450

3,200

UK

Highland Monarch

N. Sea

LgPSV

2003

220

5,450

3,000

UK

Highland Valour

N. Sea

LgAHTS

2003

262

16,320

2,750

Malta

Highland Endurance

N. Sea

LgAHTS

2003

262

16,320

2,750

UK

Highland Laird

N. Sea

LgPSV

2006

236

7,482

3,102

UK

Highland Prestige

N. Sea

LgPSV

2007

284

10,767

4,993

UK

North Promise

N. Sea

LgPSV

2007

284

10,767

4,993

Norway

Highland Prince

N. Sea

LgPSV

2009

284

10,738

4,826

UK

North Purpose

N. Sea

LgPSV

2010

284

10,738

4,836

Norway

Highland Duke

N. Sea

LgPSV

2012

246

7,482

3,121

UK

North Pomor

N. Sea

LgPSV

2013

304

11,465

5,000

Norway

Highland Defender

N. Sea

LgPSV

2013

286

9,598

5,100

UK

Highland Chieftain

N. Sea

LgPSV

2013

260

9,598

4,000

UK

Highland Guardian

N. Sea

LgPSV

2013

286

9,598

5,100

UK

Highland Knight

N. Sea

LgPSV

2013

246

7,482

3,116

UK

North Cruys

N. Sea

LgPSV

2014

304

11,465

5,000

Norway

Highland Princess

N. Sea

LgPSV

2014

246

7,482

3,081

UK

               

Highland Drummer

SEA

LgPSV

1997

220

5,450

3,122

Panama

Sea Intrepid

SEA

SmAHTS

2005

193

5,150

1,500

Panama

Sea Guardian

SEA

SmAHTS

2006

193

5,150

1,500

Panama

Sea Sovereign

SEA

SmAHTS

2006

230

5,500

1,875

Panama

Sea Cheyenne

SEA

LgAHTS

2007

250

10,760

2,700

Malaysia

Sea Supporter

SEA

SmAHTS

2007

230

7,954

2,605

Panama

Sea Apache

SEA

LgAHTS

2008

250

10,760

2,700

Panama

Sea Choctaw

SEA

LgAHTS

2008

250

10,760

2,700

Malaysia

Sea Kiowa

SEA

LgAHTS

2008

250

10,760

2,700

Panama

Sea Cherokee

SEA

LgAHTS

2009

250

10,700

2,700

Panama

Sea Comanche

SEA

LgAHTS

2009

250

10,760

2,700

Panama

Sea Valiant

SEA

LgAHTS

2010

230

10,000

2,058

Malaysia

Sea Victor

SEA

LgAHTS

2010

230

10,000

2,058

Malaysia

  

 
9

 

 

Owned Vessel Fleet

Vessel

Region

Type (1)

Year

Built

Length

(feet)

BHP (2)

DWT (3)

Flag
               

Highland Scout

Americas

LgPSV

1999

218

4,640

2,800

Panama

Austral Abrolhos

Americas

SpV

2004

215

7,100

2,000

Brazil

Orleans

Americas

LgPSV

2004

252

6,342

2,929

USA

Bourbon

Americas

LgPSV

2004

252

6,342

2,929

USA

Royal

Americas

LgPSV

2004

252

6,342

2,929

USA

Chartres

Americas

LgPSV

2004

252

6,342

2,929

USA

Iberville

Americas

LgPSV

2005

252

6,342

2,929

USA

Coloso

Americas

SmAHTS

2005

199

5,916

1,645

Mexico

Titan

Americas

SmAHTS

2005

199

5,916

1,645

Mexico

Bienville

Americas

LgPSV

2005

210

6,342

2,374

USA

Conti

Americas

LgPSV

2005

210

6,342

2,374

USA

St. Louis

Americas

LgPSV

2005

252

6,342

2,929

USA

Toulouse

Americas

LgPSV

2004

252

6,342

2,929

USA

Esplanade

Americas

LgPSV

2005

252

6,342

2,929

USA

First and Ten

Americas

PSV

2007

190

3,894

1,686

USA

Double Eagle

Americas

PSV

2007

190

3,894

1,686

USA

Triple Play

Americas

PSV

2007

190

3,894

1,686

USA

Grand Slam

Americas

LgPSV

2008

224

3,894

2,129

USA

Mako

Americas

FSV

2008

181

7,200

552

USA

Slam Dunk

Americas

LgPSV

2008

224

3,894

2,129

USA

Touchdown

Americas

LgPSV

2008

224

3,894

2,129

USA

Hat Trick

Americas

PSV

2008

190

3,894

1,686

USA

Jermaine Gibson

Americas

LgPSV

2008

224

3,894

2,129

USA

Homerun

Americas

LgPSV

2008

224

3,894

2,129

USA

Knockout

Americas

LgPSV

2008

224

3,894

2,129

USA

Hammerhead

Americas

FSV

2008

181

7,200

552

USA

Tiger

Americas

FSV

2009

181

7,200

552

USA

Thomas Wainwright

Americas

LgPSV

2010

242

4,200

2,448

USA

Polaris

Americas

LgPSV

2014

272

9,849

3,523

USA

Regulus

Americas

LgPSV

2015

272

9,849

3,523

USA

  

(1)

Legend:  LgPSV — Large platform supply vessel

PSV — Platform supply vessel

LgAHTS — Large anchor handling, towing and supply vessel

SmAHTS — Small anchor handling, towing and supply vessel

SpV — Specialty vessel, including towing and oil spill response

FSV – Fast Supply Vessel

(2)

Brake horsepower

(3)

Deadweight tons

(4)

The Highland Rover is subject to a purchase option on the part of the charterer, pursuant to terms of an amendment to the original charter which was executed in late 2007 and amended in 2008. The charterer may purchase the vessel based on a stipulated formula on October 1, 2016 provided 120 days’ notice has been given by the charterer.

 

 
10

 

 

OPERATING SEGMENTS

 

The North Sea Operating Segment

 

   

Owned

Vessels

   

Managed

Vessels

   

Total

Fleet

 

December 31, 2014

    30       4       34  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    (3 )     (1 )     (4 )

December 31, 2015

    27       3       30  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

February 29, 2016

    27       3       30  
                         

Stacked Vessels

    8       3       11  

 

Market and Segment Overview

 

We define the North Sea market as offshore Norway, Great Britain, the Netherlands, Denmark, Germany, Ireland, the Faeroe Islands, Greenland and the Barents Sea. Historically, this has been the most demanding of all exploration frontiers due to harsh weather, erratic sea conditions, significant water depth and some long sailing distances. Exploration and production operators in the North Sea market have typically been large and well-capitalized entities (major and state-owned oil and natural gas companies and large independents) in large part because of the significant financial commitment required. Projects in the North Sea tend to be large in scope with long planning horizons. As a result, vessel demand in the North Sea has historically been more stable and less susceptible to abrupt swings than in other regions.

 

The North Sea market can be broadly divided into three service segments: exploration support; production platform support; and field development and construction (which includes subsea services). The exploration support services market represents the primary demand for AHTSs and has historically been the most volatile segment of the North Sea market. While PSVs support the exploration segment, they also support the production platform and field development and construction segments, which generally are not affected significantly by the volatility in demand for the AHTSs. Our North Sea-based fleet is oriented toward supply vessels that work production platform support and field development and construction, the more stable segments of the market.

 

Unless deployed to one of our other operating segments under long-term contract, vessels based in the North Sea but operating temporarily out of the region are included in our North Sea operating segment statistics, and all vessels based out of the region are supported through our onshore bases in Aberdeen, Scotland and Sandnes, Norway. The region typically has weaker periods of demand for vessels in the winter months of December through February primarily due to lower construction activity and harsh weather conditions affecting the movement of drilling rigs.

 

Market Development

 

Vessel demand in the North Sea is directly related to drilling and development activities in the region and construction work required in support of these activities. Geopolitical events, the demand for oil and natural gas in both mature and emerging countries, commodity prices and a host of other factors influence the expenditures of both independent and major oil and gas companies.

 

Exploration and development spending in the North Sea decreased in 2015, as operators attempted to adjust to the decline in commodity prices. Depressed commodity pricing in early 2016 and future commodity price uncertainty have put long-term planning and significant commitments to future spending on hold as operators focus on cost savings and efficiencies. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Markets – North Sea” included in Part II, Item 7.  

 

 
11

 

 

The Southeast Asia Operating Segment

  

   

Owned

Vessels

   

Managed

Vessels

   

Total

Fleet

 

December 31, 2014

    13       -       13  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

December 31, 2015

    13       -       13  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

February 29, 2016

    13       -       13  
                         

Stacked Vessels

    7       -        7  

 

Market and Segment Overview

 

The Southeast Asia market is defined as offshore Asia bounded roughly on the west by the Indian subcontinent and on the north by China, then south to Australia and east to the Pacific Islands. This market includes offshore Brunei, Indonesia, Malaysia, Myanmar, the Philippines, Thailand, Australia, New Zealand, Bangladesh, Timor-Leste, Papua New Guinea and Vietnam. Traditionally, the design requirements for vessels in this market were generally similar to the requirements of the shallow water U.S. Gulf of Mexico. However, advanced exploration technology and rapid growth in energy demand among many Pacific Rim countries have led to more remote drilling locations, which has increased both the overall demand and the technical requirements for vessels. All vessels based out of the region are supported through our primary onshore base in Singapore.

 

Southeast Asia’s customer environment is broadly characterized by a large number of mid-sized companies, in contrast to many of the other major offshore exploration and production areas of the world, where a few large operators dominate the market. Affiliations with local companies are generally necessary to maintain a viable marketing presence. Our management has been involved in the region for many years and we currently maintain long-standing business relationships with a number of local companies.

 

Market Development

 

Vessels in this market are often smaller than those operating in areas such as the North Sea. However, the varying weather conditions, annual monsoons, severe typhoons and long distances between supply centers in Southeast Asia have allowed for a variety of vessel designs to compete, each suited for a particular set of operating parameters. Vessels designed for the U.S. Gulf of Mexico and other areas, where moderate weather conditions prevail, historically made up the bulk of the vessels in the Southeast Asia market. However, over the last several years Southeast Asian and Chinese shipyards have been focusing on larger, newer and higher specification vessels for deepwater projects and inclusion in oil and natural gas companies’ larger fleets of vessels.

 

Changes in supply and demand dynamics have led to an excess number of vessels. It is possible that vessels currently located in the Arabian/Persian Gulf area, offshore Africa or the U.S. Gulf of Mexico could relocate to the Southeast Asia market; however, not all vessels currently located in those regions would be able to operate in Southeast Asia and oil and natural gas operators in this region are continuing to demand newer, higher specification vessels. In addition, speculative building at Southeast Asian and Chinese yards as described above has led to a significant overhang of new build vessels, particularly in the mid-size PSV class and smaller AHTSs. Southeast Asia is a dynamic market and from time to time certain types of vessels may be subject to more intense competition. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Markets – Southeast Asia” included in Part II, Item 7.  

 

 
12

 

 

The Americas Operating Segment

 

   

Owned

Vessels

   

Managed

Vessels

   

Total

Fleet

 

December 31, 2014

    29       -       29  

New-Build Program

    1       -       1  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

December 31, 2015

    30       -       30  

New-Build Program

    -       -       -  

Vessel Additions

    -       -       -  

Vessel Dispositions

    -       -       -  

February 29, 2016

    30       -       30  
                         

Stacked Vessels

    22       -       22  

  

Market and Segment Overview

 

We define the Americas market as offshore North, Central and South America, specifically including the United States, Mexico, Trinidad and Brazil. All vessels based in the Americas are supported from our onshore bases in the United States, Mexico, Trinidad, and/or Brazil. During 2015, due to the decline in the commodities market and the resulting negative impact on demand for OSVs, we experienced significant downward pressure on our utilization and day rates in all areas in which we operate. In response, we have taken a number of our vessels out of active service (and stacked them) to reduce operating expenses, preserve cash through deferred drydockings and improve the supply/demand balance in the market. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Markets – Americas” included in Part II, Item 7.  

 

U.S. Gulf of Mexico

 

Drilling in the U.S. Gulf of Mexico can be divided into three sectors: the shallow waters of the continental shelf, the deepwater and ultra-deepwater areas. The continental shelf has been explored since the late 1940s and the existing infrastructure and knowledge of this sector allows for incremental drilling costs to be on the lower end of the range of worldwide offshore drilling costs. A surge of deepwater drilling in this sector began in the 1990s as advances in technology made this type of drilling economically feasible. Deepwater drilling is on the higher end of the cost range, and the substantial costs and long lead times required in this type of drilling historically have made it less susceptible to short-term fluctuations in the price of crude oil and natural gas although all offshore drilling sectors have been dramatically impacted by the current market downturn. Most of our active vessels operate in the deepwater and ultra-deepwater areas of the U.S. Gulf of Mexico where we have a significant presence. Historically two to three OSVs per rig were required in the U.S. Gulf of Mexico, but at the end of 2015 only one to two OSVs per drilling rig were required as a result of streamlined operations by our customers through the market downturn.

 

At the end of 2015, industry reports indicate that there were 50 “floater” rigs (semi-submersibles and drillships) supporting deepwater drilling in the U.S. Gulf of Mexico, with 45 of the 50 units under contract or committed for work. According to the U.S. Energy Information Administration, Gulf of Mexico federal offshore oil production accounts for 17% of total U.S. crude oil production.

 

In general, the U.S. Gulf of Mexico remains a protected market. United States law requires that all vessels engaged in Coastwise Trade in the U.S. (which includes vessels servicing rigs and platforms in U.S. waters within the Exclusive Economic Zone), must be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. “Coastwise Trade”, as defined under the U.S. maritime and vessel documentation laws commonly referred to as the Jones Act, allows only those vessels that are owned and managed by U.S. citizens (as determined by those laws) and built in and registered under the laws of the United States to transport merchandise and passengers for hire between points in U.S. territorial waters.

 

We are currently actively marketing eight DP-2 class OSVs in the U.S. Gulf of Mexico under contracts of various lengths. These vessels support the shelf, deepwater and ultra-deepwater activities of the oil and gas industry including, but not limited to, seismic operations, oil and gas exploration, field development, production, offshore pipeline inspection and survey, subsea installation and oil recovery activities. We believe that drilling operators in the Gulf of Mexico generally prefer DP-2 class vessels. All 23 of our U.S. flagged OSVs are DP-2 class vessels.

 

Mexico 

 

Since 2005, we have operated Small AHTSs and OSV’s in Mexico. During the past several years, we have from time to time moved various vessels into and out of the area from the U.S. Gulf of Mexico. In December 2013, Mexico’s Congress approved a constitutional reform to allow private investment in Mexico’s energy sector.

 

 
13

 

 

Trinidad          

 

Over the past four years we mobilized several vessels between Trinidad and the U.S. Gulf of Mexico and the North Sea. Given recent licensing and exploration activity in nearby locations, including Suriname and Guyana, we anticipate OSVs operating in Trinidad for the foreseeable future.

 

Brazil

 

Brazil, which was once considered a key market for stable, long term PSV charters, continues to feel the effects of the corruption scandals at Petróleo Brasileiro S.A., or Petrobras, a Brazilian multinational energy company that is majority owned by the Brazilian government. During 2015, several PSV tenders for vessels in our size range were postponed, suspended or cancelled. The combination of the effect of the scandals and low oil prices has resulted in the cancellation or renegotiation of numerous PSV charters as Petrobras defers capital expenditures.  Also, many Brazilian PSV owners have asserted their rights to challenge foreign flagged vessels on their charters.   We were operating six vessels in Brazil in 2015, however, during the first quarter of 2016 we began to wind down our operations in Brazil, mobilizing all but one vessel out of the region. We have mobilized five vessels (non-Brazilian flagged) to the U.S. Gulf of Mexico.  Our Brazilian flagged vessel is currently warm stacked in Brazil.

 

Refer to Note 12 to our Consolidated Financial Statements in Part II, Item 8 for segment and geographical revenue data during our last three fiscal years.

 

OTHER

 

Seasonality

 

Operations in the North Sea are generally at their highest levels from April through August and at their lowest levels from December through February primarily due to lower construction activity and harsh weather conditions during the winter months affecting the movement of drilling rigs and deliveries to offshore platforms. Vessels operating offshore Southeast Asia are generally at their lowest utilization rates during the monsoon season, which moves across the Asian continent between September and early March. The monsoon season for a specific Southeast Asian location is generally about two months. Activity in the U.S. Gulf of Mexico is often lower during the North Atlantic hurricane season of June through November. Operations in any market may, however, be affected by seasonality often related to unusually long or short construction seasons due to, among other things, abnormal weather conditions, as well as market demand associated with increased or decreased drilling and development activities.

 

Other Markets

 

From time to time, we have contracted our vessels outside of our operating segment regions principally on short-term charters offshore Africa and in the Mediterranean region. We look to our core markets for the bulk of our term contracts; however, when the economics of a contract are attractive, or we believe it is strategically advantageous, we may operate our vessels in markets outside of our core regions. The operations of vessels in those markets are generally managed through our offices in the North Sea region.

 

Customers, Contract Terms and Competition

 

Our principal customers are major integrated oil and natural gas companies, large independent oil and natural gas exploration and production companies working in international markets, and foreign government-owned or controlled oil and natural gas companies. Additionally, our customers also include companies that provide logistic, construction and other services to such oil and natural gas companies and foreign government organizations. Generally, our contracts are industry standard time charters for periods ranging from a few days or months up to ten years. Contract terms vary and often are similar within geographic regions with certain contracts containing cancellation provisions and others containing non-cancellable provisions except for unsatisfactory performance by the vessel. For the year ended December 31, 2015, we had revenue from BG Group and Anadarko Petroleum Corporation in our North Sea and Americas regions totaling $32.4 million and $31.9 million, respectively, each accounting for 10% or more of our total consolidated revenue.   For the year ended December 31, 2014, we had revenue from Anadarko Petroleum Corporation and British Petroleum, or BP, in our Americas and North Sea regions totaling $88.7 million and $50.8 million, respectively, each accounting for 10% or more of our total consolidated revenue. For the year ended December 31, 2013 we had revenue from Anadarko Petroleum Corporation and BP in our Americas and North Sea regions totaling $64.6 million and $60.7 million, respectively, each accounting for 10% or more of our total consolidated revenue.

 

Contract or charter durations vary from single-day to multi-year in length, based upon many different factors that vary by market. Additionally, there are “evergreen” charters (also known as “life of field” or “forever” charters), and at the other end of the spectrum, there are “spot” charters and “short duration” charters, which can vary from a single voyage to charters of less than six months. Longer duration charters are more common where equipment is not as readily available or specific equipment is required. In the North Sea region, multi-year charters have been more common and constitute a significant portion of that market. Term charters in the Southeast Asia region have historically been less common than in the North Sea and generally have terms of less than two years. In addition, charters for vessels in support of floating production are typically life of field or “full production horizon” charters. In the Americas, particularly in the U.S. Gulf of Mexico, charters vary in length from short-term to multi-year periods, many with thirty day cancellation clauses. In Brazil, Mexico and Trinidad contracts are generally multi-year term contracts. As a result of options and frequent renewals, the stated duration of charters may have little correlation with the length of time the vessel is actually contracted to provide services to a particular customer. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Fleet Commitments and Backlog” included in Part II, Item 7.

 

 
14

 

 

Managed vessels add to the market presence of the manager but provide limited direct financial contribution. Management fees consist of a fixed annual management fee plus a monthly percentage of the charterhire day rate. The manager is typically responsible for disbursement of funds for operating the vessel on behalf of the owner. Currently, we have three vessels under management, all of which are stacked.

 

Substantially all of our charters are fixed in British Pounds, or GBP; Norwegian Kroner, or NOK; Euros; or U.S. Dollars. We attempt to reduce currency risk by matching each vessel’s contract revenue to the currency in which its operating expenses are incurred.

 

We have numerous mid-size and large competitors in the North Sea, Southeast Asia and Americas markets, some of which have significantly greater financial resources than we have. We compete principally on the basis of suitability of equipment, price and service. In the Americas region, we benefit from the provisions of the Jones Act which limits vessels that can operate in the U.S. Gulf of Mexico to those with U.S. ownership. Also, in certain foreign countries, preferences given to vessels owned by local companies may be mandated by local law or by national oil companies. We have attempted to mitigate some of the impact of such preferences through affiliations with local companies.

 

Government and Environmental Regulation

 

We must comply with extensive government regulation in the form of international conventions, federal, state and local laws and regulations in jurisdictions where our vessels operate and/or are registered. These conventions, laws and regulations govern matters of environmental protection, worker health and safety, vessel and port security, and the manning, construction, ownership and operation of vessels. Our operations are subject to extensive governmental regulation by the United States Coast Guard, the National Transportation Safety Board and the United States Custom and Border Protection, or CBP, and their foreign equivalents, and to regulation by private industry organizations such as the American Bureau of Shipping and Det Norske Veritas. The Coast Guard and the National Transportation Safety Board set safety standards and are authorized to investigate vessel accidents and recommend improved safety standards, while the CBP is authorized to inspect vessels at will. We believe that we are in compliance, in all material respects, with all applicable laws and regulations.

 

Maritime Regulations

 

We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of the United States of a national emergency or a threat to the security of the national defense, the Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (which includes United States corporations), including vessels under construction in the United States. If one of the vessels in our fleet were purchased or requisitioned by the federal government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our vessels.

 

Under the Jones Act, the privilege of transporting merchandise or passengers for hire in Coastwise Trade in U.S. territorial waters is restricted to only those Jones Act qualified vessels that are owned and managed by U.S. citizens and are built in and registered under the laws of the United States. A corporation is not considered a U.S. citizen unless:

 

 

the corporation is organized under the laws of the U.S. or of a state, territory or possession thereof;

 

the chief executive officer, by whatever title, and the chairman of the board of directors are U.S. citizens;

 

directors representing not more than a minority of the number of directors of such corporation necessary to constitute a quorum for the transaction of business are non-U.S. citizens; and

 

at least a majority, or in the case of an endorsement for operating in Coastwise Trade, 75 percent of the ownership and voting power of the shares of the capital stock is owned by, voted by and controlled by U.S. citizens, free from any trust or fiduciary obligations in favor of, or any contract or understanding under which voting power or control may be exercised directly or indirectly on behalf of non-U.S. citizens.

 

We are currently a U.S. citizen under these requirements, eligible to engage in Coastwise Trade. If we fail to comply with these U.S. citizen requirements, however, we would likely no longer be considered a U.S. citizen under the applicable laws. Such an event could result in our ineligibility to engage in Coastwise Trade, the imposition of substantial penalties against us, including seizure and forfeiture of our vessels, and the inability to register our vessels in the United States, each of which could have a material adverse effect on our financial condition and results of operations.

 

 
15

 

 

Environmental Regulations

 

Our operations are subject to a variety of federal, state, local and international laws and regulations regarding the emission or discharge of materials into the environment or otherwise relating to environmental protection. As some environmental laws impose strict liability for remediation of spills and releases of oil and hazardous substances, we could be subject to liability even if we were not negligent or at fault. These laws and regulations may expose us to liability for the conduct of or conditions caused by others, including charterers.

 

Numerous governmental authorities, such as the U.S. Environmental Protection Agency, or the EPA, analogous state agencies, and, in certain instances, citizens’ groups, have the power to enforce compliance with these laws and regulations and the permits issued under them. Failure to comply with applicable environmental laws and regulations may result in the imposition of administrative, civil and criminal penalties, revocation of permits, issuance of corrective action orders and suspension or termination of our operations. Environmental laws and regulations may change in ways that substantially increase costs, or impose additional requirements or restrictions which could adversely affect our financial condition and results of operations. We believe that we are in substantial compliance with currently applicable environmental laws and regulations, but failure to comply could have material adverse consequences. Environmental laws and regulations have been subject to frequent changes over the years, and the imposition of more stringent requirements could have a material adverse effect upon our capital expenditures, earnings or competitive position, including the suspension or cessation of operations in affected areas. As such, there can be no assurance that material costs and liabilities related to compliance with environmental laws and regulations will not be incurred in the future.

 

International Safety Management Code

 

The International Maritime Organization, or IMO, has made the regulations of the International Safety Management Code, or ISM Code, mandatory. The ISM Code provides an international standard for the safe management and operation of ships, pollution prevention and certain crew and vessel certifications. IMO has also adopted the International Ship & Port Facility Security Code, or ISPS Code. The ISPS Code provides that owners or operators of certain vessels and facilities must provide security and security plans for their vessels and facilities and obtain appropriate certification of compliance. We believe all of our vessels presently are certificated in accordance with ISPS Code. The risks of incurring substantial compliance costs, liabilities and penalties for non-compliance are inherent in offshore marine operations.

 

MARPOL

 

The International Convention for the Prevention of Pollution from Ships, 1973, as modified by the Protocol of 1978, or MARPOL, is the main international convention covering prevention of pollution of the marine environment by vessels from operational or accidental causes. It has been updated by amendments through the years and is implemented in the United States by the Act to Prevent Pollution from Ships. MARPOL has six specific annexes; Annex I governs oil pollution, Annex V governs garbage pollution, and Annex VI governs air pollution.

 

MARPOL Annex VI, which addresses air emissions from vessels, requires the use of low sulfur fuel worldwide in both auxiliary and main propulsion diesel engines on ships. Annex VI also specifies requirements for Emission Control Areas, or ECAs, with stricter limitations on sulfur emissions in these areas. Ships operating in the Baltic Sea ECA, the North Sea/English Channel ECA and the North American ECA are required to use fuel with a sulfur content of no more than 1% or use alternative emission reduction methods rather than the current 3.5% global limit. Beginning in January 2015, the fuel sulfur content limit in ECAs was reduced to 0.1%. The MARPOL global limit on fuel sulfur content outside of ECAs will be reduced to 0.5% on and after January 2020. We may incur additional compliance costs as part of our efforts to comply with Annex VI and other provisions of MARPOL. In addition, we could face fines and penalties for failure to meet requirements imposed by MARPOL and similar laws related to the operation of our vessels.

 

The Clean Water Act

 

The Federal Water Pollution Control Act, or the Clean Water Act, or CWA, imposes strict controls on the discharge of pollutants into the navigable waters of the United States. The CWA also provides for civil, criminal and administrative penalties for any unauthorized discharge of oil or other hazardous substances in reportable quantities and imposes liability for the costs of removal and remediation of an unauthorized discharge. Many states have laws that are analogous to the CWA and also require remediation of accidental releases of petroleum in reportable quantities. Our vessels routinely transport diesel fuel to offshore rigs and platforms and also carry diesel fuel for their own use. We maintain response plans as required by the Clean Water Act to address potential oil and fuel spills from either our vessels or our shore-based facilities.

 

 
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In addition, the CWA established the National Pollutant Discharge Elimination System, or NPDES permitting program, which governs discharges of pollutants into navigable waters of the United States from point sources, such as vessels operating in the navigable waters. Pursuant to the NPDES permitting program, the EPA issued a Vessel General Permit, or VGP. The EPA implemented the Phase II VGP Regime, or 2013 VGP, beginning in December 2013, which covers 27 types of discharges. The 2013 VGP applies to U.S. and foreign-flag commercial vessels that are at least 79 feet in length, and therefore applies to our vessels. The 2013 VGP requires vessel owners and operators to adhere to “best management practices” to manage the covered discharges, including ballast water, which occur normally in the operation of a vessel. In addition, the 2013 VGP requires vessel owners and operators to implement various training, inspection, monitoring, recordkeeping, and reporting requirements, as well as corrective actions upon identification of each deficiency. The purpose of these limitations is to reduce the number of living organisms discharged via ballast water into waters regulated by the 2013 VGP. The 2013 VGP also contains requirements for oil-to-sea interfaces, which seeks to improve environmental protection of U.S. waters, by requiring all vessels to use an Environmentally Acceptable Lubricant in all oil-to-sea interfaces, unless not technically feasible. These regulations may increase the costs of compliance for our operations. In addition, failure to comply with the requirements of the 2013 VGP and other provisions of the CWA could result in the imposition of substantial fines and penalties.

 

The Oil Pollution Act

 

The Oil Pollution Act of 1990, or OPA, establishes a comprehensive regulatory and liability regime designed to increase pollution prevention, ensure better spill response capability, increase liability for oil spills, and facilitate prompt compensation for cleanup and damages. OPA is applicable to owners and operators whose vessels trade with the United States or its territories or possessions, or whose vessels operate in the navigable waters of the United States (generally three nautical miles from the coastline) and the 200 nautical mile exclusive economic zone of the United States. Under OPA, vessel owners, operators and bareboat charterers are “responsible parties” and are jointly, severally and strictly liable (unless it is subsequently determined by the Coast Guard or a court of competent jurisdiction that the spill results solely from the act or omission of a third party, an act of God or an act of war) for removal costs and damages arising from discharges or threatened discharges of oil from their vessels up to their limits of liability, unless the limits are broken as described below. “Damages” are defined broadly under OPA to include:

 

 

natural resources damages and the costs of assessment thereof;

 

damages for injury to, or economic losses resulting from the destruction of, real or personal property;

 

the net loss of taxes, royalties, rents, fees and profits by the United States government, and any state or political subdivision thereof;

 

lost profits or impairment of earning capacity due to property or natural resources damage;

 

the net costs of providing increased or additional public services necessitated by a spill response, such as protection from fire, safety or other hazards; and

 

the loss of subsistence use of natural resources.

 

OPA limits the liability of responsible parties for discharges from non-tank vessels to $1,000 per gross ton or $854,400, whichever is greater. In August 2014, the U.S. Coast Guard proposed to raise this limit to $1,100 per gross ton or $924,500, whichever is greater. OPA’s liability limits do not apply: (1) if an incident was proximately caused by violation of applicable federal safety, construction or operating regulations or by a responsible party’s gross negligence or willful misconduct; or (2) if the responsible party fails or refuses to report the incident, fails to provide reasonable cooperation and assistance requested by a responsible official in connection with oil removal activities, or without sufficient cause fails to comply with an order issued under OPA. If an oil discharge or substantial threat of discharge were to occur, we may be liable for costs and damages, which costs and liabilities could be material to our results of operations and financial position.

 

Hazardous Wastes and Substances

 

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, also known as CERCLA or Superfund, and similar laws, impose liability for releases of hazardous substances into the environment. CERCLA currently exempts crude oil from the definition of hazardous substances for purposes of the statute, but our operations may involve the use or handling of other materials that may be classified as hazardous substances. CERCLA assigns strict liability to each responsible party for all response costs, as well as natural resource damages. CERCLA also imposes liability similar to OPA and provides compensation for cleanup, removal and natural resource damages. Liability per vessel under CERCLA is limited to the greater of $300 per gross ton or $5 million, unless the incident is caused by gross negligence, willful misconduct, or a violation of certain regulations, in which case liability is unlimited. We could be held liable for releases of hazardous substances that resulted from operations by third parties not under our control or for releases associated with practices performed by us or others that were standard in the industry at the time. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances released into the environment.

 

The Resource Conservation and Recovery Act, or RCRA, regulates the generation, transportation, storage, treatment and disposal of onshore hazardous and non-hazardous wastes and requires states to develop programs to ensure the safe disposal of wastes. We generate non-hazardous wastes and small quantities of hazardous wastes in connection with routine operations. We believe that all of the wastes that we generate are handled in all material respects in compliance with the RCRA and analogous state statutes.

 

 
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Insurance

 

We review our insurance coverages annually.  In particular, we assess our coverage levels and limits for possible marine liabilities, including pollution, personal injury or death, and property damage.  Our most recent review did not result in any substantial adjustments to our coverages or limits.

 

Litigation

 

We are not a party to any material pending regulatory litigation or other proceeding and we are unaware of any threatened litigation or proceeding, which, if adversely determined, would have a material adverse effect on our financial condition or results of operations.

 

Employees

 

We have approximately 1,100 employees located principally in the United States, the United Kingdom, Norway, Southeast Asia, and Brazil. Through our contract with a crewing agency, we participate in the negotiation of collective bargaining agreements for approximately 600 contract crew members, approximately 53% of our labor force, who are members of two North Sea unions and six Brazil unions under evergreen employment agreements. Wages are renegotiated annually in the second half of each year for the North Sea unions. We have no other collective bargaining agreements; however, we do employ crew members who are members of national unions but we do not participate in the negotiation of those collective bargaining agreements. Relations with our employees are considered satisfactory. To date, our operations have not been interrupted by strikes or work stoppages.

 

ITEM 1A. Risk Factors

 

We operate globally in challenging and highly competitive markets, and our business is subject to a variety of risks, including the risks described below, which could cause our actual results to differ materially from those anticipated, projected or assumed in forward-looking statements. You should carefully consider these risks when evaluating us and our securities. The risks and uncertainties described below are not the only ones facing our company. We are also subject to a variety of risks that affect many other companies generally, as well as additional risks and uncertainties not known to us or that, as of the date of this report, we believe are not as significant as the risks described below. If any of the following risks actually occur, the accuracy of any forward-looking statements made in this report, and our business, financial condition, results of operations and cash flows, and the trading prices of our securities, may be materially and adversely affected.

 

The current downturn in the oil and gas industry has had a significant negative effect on our results of operations and revenues, our customers’ ability to pay and our profitability.

 

Demand for our vessels and services, and therefore our results of operations, are highly dependent on the level of spending and investment in offshore exploration, development and production by the companies that operate in the energy industry. The energy industry’s level of capital spending is directly related to current and expected future demand for hydrocarbons and the prevailing commodity prices of crude oil and, to a lesser extent, natural gas. Hydrocarbon supply has increased at a faster pace than hydrocarbon demand, despite a significant decrease in exploration and development spending. This has resulted in significant declines in crude oil prices. When our customers experience low commodity prices or come to believe that they will be low in the future, they generally reduce their capital spending for offshore drilling, exploration and field development. The precipitous decline in crude oil prices that began in late 2014 and has reached a 12-year low of less than $30/barrel has resulted in a decrease in the energy industry’s level of capital spending and, if prices continue to decline or remain depressed for an extended period of time, capital spending and demand for our services may remain similarly depressed. There are indications that certain major oil producing nations do not intend to reduce crude oil output. As a result, the current over-supply environment may continue for the foreseeable future unless there is a significant increase in worldwide demand, which may not occur or may occur very slowly. These market conditions negatively affected our 2015 results and are expected to continue to significantly affect future results, particularly if exploration and production activity levels and, therefore, demand for our products and services, as well as our customers’ ability to pay, continue to decline. The decrease in demand for offshore services could cause the industry to cycle into a prolonged downturn. These conditions could have a material adverse effect on our business, financial condition and results of operations.

 

We rely on the oil and natural gas industry, and volatile oil and natural gas prices impact demand for our services.

 

Demand for our services depends on activity in offshore oil and natural gas exploration, development and production. The level of exploration, development and production activity is affected by factors such as:

 

 

prevailing oil and natural gas prices;

 

expectations about future prices and price volatility;

 

worldwide supply and demand for oil and gas;

 

the level of economic activity in energy-consuming markets;

 

 
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the worldwide economic environment or economic trends, such as recessions;

 

the ability of the Organization of Petroleum Exporting Countries (OPEC) to set and maintain production levels and pricing;

 

the level of production in non-OPEC countries;

 

international sanctions on oil producing countries and the lifting of certain sanctions against Iran;

 

civil unrest and the worldwide political and military environment, including uncertainty or instability resulting from an escalation or additional outbreak of armed hostilities involving the Middle East, Russia, other oil-producing regions or other geographic areas or further acts of terrorism in the United States or elsewhere;

 

cost of exploring for, producing and delivering oil and natural gas;

 

sale and expiration dates of available offshore leases;

 

demand for petroleum products;

 

current availability of oil and natural gas resources;

 

rate of discovery of new oil and natural gas reserves in offshore areas;

 

local and international political, environmental and economic conditions;

 

changes in laws and regulations;

 

technological advances; and

 

ability of oil and natural gas companies to obtain leases and permits, or obtain funds for capital.

 

An increase in commodity demand and prices will not necessarily result in an immediate increase in offshore drilling activity since our customers’ project development times, reserve replacement needs, expectations of future commodity demand, prices and supply of available competing vessels all combine to affect demand for our vessels. The level of offshore exploration, development and production activity has historically been characterized by volatility, and that volatility is likely to continue. The decline in exploration and development of offshore areas has resulted in a decline in the demand for our offshore marine services and may continue to do so or may worsen. Any such decrease in activity is likely to reduce our day rates and our utilization rates and, therefore, could have a material adverse effect on our financial condition and results of operations.

 

If we are unable to generate enough cash flow from operations to service our indebtedness or are unable to use future borrowings to fund other capital needs, we may have to undertake alternative financing plans, which may have onerous terms or may be unavailable.

 

If our business does not generate cash flow from operations in the future that is sufficient to service our outstanding indebtedness and other capital needs, we cannot assure you that future borrowings will be available to us in an amount sufficient to enable us to pay our indebtedness or to fund our other capital needs. If operational performance does not improve significantly and oil companies do not increase spending for exploration and production activities, we may need additional sources of liquidity in the future as a result of an inability to generate sufficient cash flow from operations to service our long-term capital needs. If we do not generate sufficient cash flow from operations in the future to satisfy our debt obligations and other capital needs, we may have to undertake alternative financing plans, such as:

 

 

refinancing or restructuring all or a portion of our debt;

 

obtaining alternative financing;

 

selling assets;

 

reducing or delaying capital investments;

 

seeking to raise additional capital; or

 

revising or delaying our strategic plans.

 

We cannot assure you, however, that we would be able to implement alternative financing plans, if necessary, on commercially reasonable terms or at all, or that undertaking alternative financing plans, if necessary, would allow us to meet our debt obligations and capital requirements or that these actions would be permitted under the terms of our various debt instruments.

 

Our inability to generate sufficient cash flow in the future to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our business, financial condition, results of operations and prospects. Any failure to make required or scheduled payments of interest and principal on our outstanding indebtedness could harm our ability to incur additional indebtedness on acceptable terms. Further, if for any reason we are unable to satisfy our covenants, debt service or repayment obligations, we would be in default under the terms of the agreements governing such debt, which would allow our creditors at that time to declare all such outstanding indebtedness to be due and payable (which could in turn trigger cross-acceleration or cross-default rights between the relevant agreements), the lenders under our Multicurrency Facility Agreement and Norwegian Facility Agreement, (as defined in Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt,”) as applicable, could terminate their commitments to loan money, and such lenders could foreclose against our assets securing their borrowings which would have a material adverse effect on our business, financial condition and results of operations.

 

 
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We expect to be dependent on our Multicurrency Facility Agreement and Norwegian Facility Agreement for liquidity beginning in 2016. Any further reduction of the commitments under or the value of the collateral securing our Multicurrency Facility Agreement or Norwegian Facility Agreement could reduce or eliminate our ability to borrow under the facility and may require us to repay indebtedness under the facility earlier than anticipated, which would adversely impact our liquidity.

 

As a result of our decline in operating revenues and market outlook, we expect to become dependent on our Multicurrency Facility Agreement and Norwegian Facility Agreement for liquidity beginning in 2016. Due to low commodity prices and other factors, the capital markets have been constrained and if market conditions do not improve and these constraints continue, we will continue to be primarily reliant on our Multicurrency Facility Agreement and Norwegian Facility Agreement, and to the extent available, the cash provided by operating activities, for liquidity.

 

At December 31, 2015, there was approximately $98.2 million of available borrowing capacity under the Multicurrency Facility Agreement and approximately $67.9 million of available borrowing capacity under the Norwegian Facility Agreement, in each case subject to the terms and conditions of the applicable facility. See “– If we are unable to comply with the financial covenants in our revolving credit facilities, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed at that time” and Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt.”

 

If we are unable to comply with the financial covenants in our revolving credit facilities, there could be a default, which could result in an acceleration of repayment of funds that we have borrowed at that time.

 

Our Multicurrency Facility Agreement and Norwegian Facility Agreement include numerous financial covenants that are tested quarterly. Our ability to comply with these financial covenants can be affected by events beyond our control. Reduced activity levels in the oil and natural gas industry, such as we are currently experiencing, or the absence of substantial improvements in such activity levels could adversely impact our ability to comply with such covenants in the future. Our failure to comply with any such covenant would result in an event of default under the applicable facility, and may result in a cross-default to other indebtedness. An event of default could prevent us from borrowing under our revolving credit facilities, which could in turn have a material adverse effect on our available liquidity. In addition, an event of default could result in our having to immediately repay all amounts outstanding under the Multicurrency Facility Agreement, Norwegian Facility Agreement and our Senior Notes and in foreclosure of liens on our assets. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt.”

 

In addition, if the OSV industry conditions do not improve, we may in the future cease to be in compliance with the covenants in our Multicurrency Facility Agreement and our Norwegian Facility Agreement that require us to maintain minimum Consolidated Adjusted EBITDA. See “Management's Discussion and Analysis of Financial Condition and Results of Operations” “– Long-Term Debt – Multicurrency Facility Agreement” and “– Long-Term Debt – Norwegian Facility Agreement.” If necessary, we plan to work with the respective lenders to attempt to negotiate any amendments or waivers that may be required in the future. There can be no assurance, however, that we would be able to negotiate acceptable terms with the lenders in these circumstances. In addition, any such amendment or waiver would probably be accompanied by the imposition of additional restrictions and potentially a reduction in amounts available for borrowing under the respective facilities.

 

We have high levels of fixed costs that will be incurred regardless of our level of business activity.

 

Our business has high fixed costs. Downtime or low productivity due to reduced demand, weather interruptions or other causes can have a significant negative effect on our operating results and financial condition. Some of our fixed costs will not decline during periods of reduced revenue or activity, and we may incur additional operating costs for which we are generally reimbursed by the customer when a vessel is under contract. During times of reduced utilization, reductions in costs may not be immediate as we may incur additional costs associated with the stacking of a vessel, or we may not be able to fully reduce the cost of our support operations in a particular geographic region due to the need to support the remaining vessels in that region. A decline in revenue due to lower day rates and/or utilization may not be offset by a corresponding decrease in our fixed costs and could have a material adverse effect on our financial condition, results of operations and cash flows.

 

We may not be able to renew or replace expiring contracts for our vessels.

 

We have a number of charters that will expire in 2016 and 2017. Our ability to renew or replace expiring contracts or obtain new contracts, and the terms of any such contracts, will depend on various factors, including market conditions and the specific needs of our customers. Given the highly competitive and historically cyclical nature of our industry, we may not be able to renew or replace the contracts or we may be required to renew or replace expiring contracts or obtain new contracts at rates that are below, and potentially substantially below, existing day rates, or that have terms that are less favorable to us than our existing contracts, or we may be unable to secure contracts for these vessels. This could have a material adverse effect on our financial condition, results of operations and cash flows.

 

 
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An increase in the supply of offshore supply vessels would likely have a negative effect on charter rates for our vessels, which could reduce our earnings.

 

Our industry is highly competitive, with oversupply and intense price competition. Charter rates for marine supply vessels depend in part on the supply of the vessels. We could experience an increased reduction in demand as a result of the current oversupply of vessels. Excess vessel capacity has resulted from:

 

 

constructing new vessels;

 

moving vessels from one offshore market area to another;

 

converting vessels formerly dedicated to services other than offshore marine services; and

 

declining offshore oil and gas drilling production activities.

 

In the past decade, construction of vessels of the types we operate has increased. Significant new OSV construction and upgrades of existing OSVs has intensified price competition. The resulting increases in OSV supply has depressed OSV utilization and intensified price competition from both existing competitors, as well as new entrants into the offshore vessel supply market. As of the date of this report, not all of the vessels currently under construction have been contracted for future work, which may further intensify price competition as scheduled delivery dates occur. Such price competition could further reduce day rates, utilization rates and operating margins, which would adversely affect our financial condition and results of operations.

 

We may incur additional asset impairments as a result of reduced demand for certain vessels.

 

The current oversupply of vessels in offshore oil and gas exploration and production markets has resulted in numerous vessels being idled or stacked and in some cases retired or scrapped. We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Impairment write-offs could result if, for example, any of our vessels become obsolete or commercially less desirable or their carrying values become excessive due to the condition of the vessel, stacking the vessel, the expectation of stacking the vessel in the near future, a decision to retire or scrap the vessel, changes in technology, market demand or market expectations, or excess spending over budget on a new-build vessel. Asset impairment evaluations are, by their nature, highly subjective. The use of different estimates and assumptions could result in materially different carrying values of our assets, which could impact the need to record an impairment charge and the amount of any charge taken. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates Long-Lived Assets, Goodwill and Intangibles” in Part II, Item 7 and Note 2 to our Consolidated Financial Statements included in Part II, Item 8.

 

We can provide no assurance that our assumptions and estimates used in our asset impairment evaluations will ultimately be realized or that the current carrying value of our property and equipment, including vessels designated as held for sale, will ultimately be realized.

 

As the markets recover or we change our marketing strategies or for other reasons, we may be required to incur higher than expected costs to return previously stacked vessels to class.

 

Stacked vessels are not maintained with the same diligence as our marketed fleet. As a result, and depending on the length of time the vessels are stacked, we may incur costs beyond normal drydock costs to return these vessels to active service. These costs are difficult to estimate and may be substantial.

 

Government regulation and environmental risks can reduce our business opportunities, increase our costs, and adversely affect the manner or feasibility of doing business.

 

We and our customers are subject to extensive governmental regulation in the form of international conventions, federal, state and local laws and laws and regulations in jurisdictions where our vessels operate and are registered. The risks of incurring substantial compliance costs, liabilities and penalties for noncompliance are inherent in offshore marine services operations. Compliance with the Jones Act, as well as with environmental, occupational, health and safety, and vessel and port security laws can reduce our business opportunities and increase our costs of doing business. Additionally, these laws change frequently. Therefore, we are unable to predict with certainty the future costs or other future impact of these laws on our operations and our customers. We could also incur substantial costs, including cleanup costs, fines, civil or criminal sanctions and third party claims for property damage or personal injury as a result of violations of, or liabilities under, environmental laws and regulations. In addition, there can be no assurance that we can avoid significant costs, liabilities and penalties imposed on us as a result of government regulation in the future.

 

 
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We have been adversely affected by a decrease in offshore oil and gas drilling as a result of unconventional crude oil and unconventional natural gas production and the improved economics of producing natural gas and oil from shale.

 

The rise in production of unconventional crude oil and gas resources in North America and the commissioning of a number of new large liquefied natural gas export facilities around the world are, at least to date, primarily contributing to an over-supplied natural gas market. While production of crude oil and natural gas from unconventional sources is still a relatively small portion of the worldwide crude oil and natural gas production, production from unconventional resources is increasing because improved drilling efficiencies are lowering the costs of extraction. There is an oversupply of natural gas inventories in the United States in part due to the increased development of unconventional crude oil and natural gas resources. Prolonged increases in the worldwide supply of crude oil and natural gas, whether from conventional or unconventional sources, will likely continue to depress crude oil and natural gas prices. Prolonged periods of low natural gas prices have a negative impact on development plans of exploration and production companies, which in turn, results in a decrease in demand for offshore support vessel services. The rise in production of natural gas and oil, particularly from onshore shale, as a result of improved drilling efficiencies that are lowering the costs of extraction, has resulted in a reduction of capital invested in offshore oil and gas exploration. Because we provide vessels servicing offshore oil and gas exploration, the significant reduction in investments in offshore exploration and development has had a material adverse effect on our operations and financial position.

 

Failure to comply with the Foreign Corrupt Practices Act and similar worldwide anti-bribery laws may have an adverse effect on us.

 

Our international operations require us to comply with a number of U.S. and international laws and regulations, including those involving anti-bribery and anti-corruption. We do business and may do additional business in the future in countries and regions where strict compliance with anti-bribery laws may not be customary. In order to effectively operate in certain foreign jurisdictions, circumstances may require that we establish joint ventures with local operators or find strategic partners. As a U.S. corporation, we are subject to the regulations imposed by the Foreign Corrupt Practices Act, or FCPA, which generally prohibits U.S. companies and their intermediaries from making improper payments to foreign officials for the purpose of obtaining or keeping business or obtaining an improper business benefit. We have an ongoing program of proactive procedures to promote compliance with the FCPA and other similar anti-bribery and anti-corruption laws, but we may be held liable for actions taken by our strategic or local partners or agents even though these partners or agents may not themselves be subjected to the FCPA or other similar laws.  Our personnel and intermediaries, including our local operators and strategic partners, may face, directly or indirectly, corrupt demands by government officials, political parties and officials, tribal or insurgent organizations, or private entities in the countries in which we operate or may operate in the future.  As a result, we face the risk that an unauthorized payment or offer of payment could be made by one of our employees or intermediaries, even if such parties are not always subject to our control or are not themselves subject to the FCPA or other similar laws to which we may be subject. Any allegation that we have violated the FCPA or other similar laws or any determination that we have violated the FCPA or other similar laws could have a material adverse effect on our business, results of operations, and cash flows.

 

We are subject to hazards customary for the operation of vessels that could adversely affect our financial performance if we are not adequately insured or indemnified.

 

Our operations are subject to various operating hazards and risks, including:

 

 

catastrophic marine disaster;

 

adverse sea and weather conditions;

 

mechanical failure;

 

navigation errors;

 

collision;

 

oil and hazardous substance spills, containment and clean up;

 

labor shortages and strikes;

 

damage to and loss of drilling rigs and production facilities;

 

war, sabotage, piracy, cyber-attack and terrorism risks; and

 

outbreak of contagious disease.

 

These risks present a threat to the safety of our personnel and to our vessels, cargo, equipment under tow and other property, as well as the environment. We could be required to suspend our operations or request that others suspend their operations as a result of these hazards. In such event, we would experience loss of revenue and possibly property damage, and additionally, third parties may make significant claims against us for damages due to personal injury, death, property damage, pollution and loss of business.

 

We maintain insurance coverage against many of the casualty and liability risks listed above, subject to deductibles and certain exclusions. We have renewed our primary insurance program for the insurance year 2015-2016. We can provide no assurance, however, that our insurance coverage will be available beyond the renewal periods, or that it will be adequate to cover future claims that may arise. Claims covered by insurance are subject to deductibles, the aggregate amount of which could be material. Insurance policies are also subject to compliance with certain conditions, the failure of which could lead to a denial of coverage as to a particular claim or the voiding of a particular insurance policy. There also can be no assurance that existing insurance coverage can be renewed at commercially reasonable rates or that available coverage will be adequate to cover future claims. If a loss occurs that is partially or completely uninsured, we could be exposed to substantial liability.

 

 
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We may not be fully indemnified by our customers for damage to their property or the property of their other contractors. Our contracts are individually negotiated, and the levels of indemnity and allocation of liabilities in them can vary from contract to contract depending on market conditions, particular customer requirements and other factors existing at the time a contract is negotiated. Additionally, the enforceability of indemnification provisions in our contracts may be limited or prohibited by applicable law or may not be enforced by courts having jurisdiction, and we could be held liable for substantial losses or damages and for fines and penalties imposed by regulatory authorities. The indemnification provisions of our contracts may be subject to differing interpretations, and the laws or courts of certain jurisdictions may enforce such provisions while other laws or courts may find them to be unenforceable, void or limited by public policy considerations, including when the cause of the underlying loss or damage is our gross negligence or willful misconduct, when punitive damages are attributable to us or when fines or penalties are imposed directly against us. The law with respect to the enforceability of indemnities varies from jurisdiction to jurisdiction. Current or future litigation in particular jurisdictions, whether or not we are a party, may impact the interpretation and enforceability of indemnification provisions in our contracts. There can be no assurance that our contracts with our customers, suppliers and subcontractors will fully protect us against all hazards and risks inherent in our operations. There can also be no assurance that those parties with contractual obligations to indemnify us will be financially able to do so or will otherwise honor their contractual obligations.

 

We have a substantial amount of indebtedness. We may not be able to generate sufficient cash to service all of our indebtedness, including our senior notes, and may be forced to take other actions to satisfy our obligations under our indebtedness, which may not be successful.

 

We have a substantial amount of indebtedness which could:

 

 

increase our vulnerability to general adverse economic and industry conditions;

 

limit our ability to fund future working capital, capital expenditures and other general corporate financing needs;

 

require us to dedicate a substantial portion of our cash flow from operations to payments on our indebtedness, thereby reducing the availability of our cash flow to fund working capital, capital expenditures and other general corporate purposes;

 

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

 

place us at a competitive disadvantage compared to our competitors that have less debt; and

 

limit, along with the financial and other restrictive covenants in our indebtedness, among other things, our ability to borrow additional funds or dispose of assets.

 

We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.  If our capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness.  Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations.  In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. Our facilities agreements and the indenture governing our 6.375% senior notes due 2022 restrict our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds that we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations.

 

We may not be able to sell vessels to improve our cash flow and liquidity because we may be unable to locate buyers with access to financing or to complete any sales on acceptable terms or within a reasonable timeframe.

 

We may seek to sell some of our vessels to provide liquidity and cash flow. However, given the current downturn in the oil and gas industry, there may not be sufficient activity in the market to sell our vessels and we may not be able to identify buyers with access to financing or to complete any such sales. Even if we are able to locate appropriate buyers for our vessels, any sales may occur on less favorable terms than the terms that might be available in a more liquid market or at other times in the business cycle.

 

The early termination of contracts on our vessels could have an adverse effect on our operations and our backlog may not be converted to actual operating results for any future period.

 

Some of the long-term contracts for our vessels and all contracts with governmental entities and national oil companies contain early termination options in favor of the customer, although some have early termination remedies or other provisions designed to discourage the customers from exercising such options. We cannot assure you that our customers would not choose to exercise their termination rights in spite of such remedies or the threat of litigation with us. Until replacement of such business with other customers, any termination could temporarily disrupt our business or otherwise adversely affect our financial condition and results of operations. We might not be able to replace such business on economically equivalent terms. In those circumstances, the amount of backlog could be reduced and the conversion of backlog into revenue could be impaired. Additionally, because of depressed commodity prices, restricted credit markets, economic downturns, changes in priorities or strategy or other factors beyond our control, a customer may no longer want or need a vessel that is currently under contract or may be able to obtain a comparable vessel at a lower rate. For these reasons, customers may seek to renegotiate the terms of our existing contracts, terminate our contracts without justification or repudiate or otherwise fail to perform their obligations under our contracts. In any case, an early termination of a contract may result in our vessel being idle for an extended period of time. Each of these results could have a material adverse effect on our financial condition, results of operations and cash flows. See Management’s Discussion and Analysis of Financial Condition and Results of Operations – Fleet Commitments and Backlog” included in Part II, Item 7.

 

 
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We may be unable to collect amounts owed to us by our customers.

 

We typically grant our customers credit on a short-term basis. Related credit risks are inherent as we do not typically collateralize receivables due from customers. We provide estimates for uncollectible accounts based primarily on our judgment using historical losses, current economic conditions and individual evaluations of each customer as evidence supporting the receivables valuations stated on our financial statements. However, our receivables valuation estimates may not be accurate and receivables due from customers reflected in our financial statements may not be collectible. Our inability to perform under our contractual obligations, or our customers’ inability or unwillingness to fulfill their contractual commitments to us, may have a material adverse effect on our financial condition, results of operations and cash flows.

 

A substantial portion of our revenue is derived from our international operations which are subject to foreign government regulation and operating risks.

 

We derive a substantial portion of our revenue from foreign sources. We therefore face risks inherent in conducting business internationally, such as:

 

 

foreign currency exchange fluctuations;

 

legal and governmental regulatory requirements;

 

difficulties and costs of staffing and managing international operations;

 

language and cultural differences;

 

potential vessel seizure or nationalization of assets;

 

import-export quotas or other trade barriers;

 

difficulties in collecting accounts receivable and longer collection periods;

 

political and economic instability;

 

changes to shipping tax regimes;

 

risk arising from counterparty conduct;

 

imposition of currency exchange controls; and

 

potentially adverse tax consequences.

 

We cannot predict whether any such conditions or events might develop in the future or whether they might have a material effect on our operations. Our ability to compete in international markets may be adversely affected by foreign government regulations, such as regulations that favor or require the awarding of contracts to local competitors, or that require foreign persons to employ citizens of, or purchase supplies from, a particular jurisdiction.

 

Our subsidiary structure and our operations are in part based on certain assumptions about various foreign and domestic tax laws, currency exchange requirements and capital repatriation laws. While we believe our assumptions are correct, there can be no assurance that taxing or other authorities will reach the same conclusions. If our assumptions are incorrect or if the relevant countries change or modify such laws or the current interpretation of such laws, we may suffer adverse tax and financial consequences, including the reduction of cash flow available to meet required debt service and other obligations.

 

Due to the continuous evolution of laws and regulations in the various markets in which we operate, we may be restricted or even lose the right to operate in certain international markets where we currently have a presence.

 

Many of the countries in which we operate have laws, regulations and enforcement systems that are largely undeveloped, and the requirements of these systems are not always readily discernible even to experienced operators. Further, these laws, regulations and enforcement systems can be subject to frequent change or reinterpretation, sometimes with retroactive effect, and taxes, fees, fines or penalties may be sought from us based on that reinterpretation or retroactive effect. While we endeavor to comply with applicable laws and regulations, our compliance efforts might not always be wholly successful, and failure to comply may result in administrative and civil penalties, criminal sanctions, imposition of remedial obligations or the suspension or termination of our operations in the jurisdiction. In addition, laws and regulations could be changed or be interpreted in new, unexpected ways that substantially increase our costs, which we may not be able to pass through to our customers. Any changes in laws, regulations or standards that would impose additional requirements or restrictions could adversely affect our financial condition, results of operations or cash flows.

 

 
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Our tax expense and effective tax rate on our worldwide earnings could be higher if there are changes in tax legislation in countries where we operate, if we lose our tonnage tax qualifications or tax exemptions, if we increase our operations in high tax jurisdictions where we operate, if there are changes in the mix of income and losses we recognize in tax jurisdictions and/or if we elect to repatriate cash from our foreign operations in amounts higher than recent years.

 

Our worldwide operations are conducted through our various domestic and foreign subsidiaries and as a result we are subject to income taxes in the United States and foreign jurisdictions. Any material changes in tax law and related regulations, tax treaties or their interpretations where we have significant operations could result in a higher effective tax rate on our worldwide earnings and a materially higher tax expense.

 

For example, our North Sea operations based in the U.K. and Norway have special tax incentives for qualified shipping operations, commonly referred to as tonnage tax, which provides for a tax based on the net tonnage capacity of qualified vessels, resulting in significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. There is no guarantee that current tonnage tax regimes will not be changed or modified which could, along with any of the above mentioned factors, materially adversely affect our international operations and, consequently, our business, operating results and financial condition. Our U.K. and Norway tonnage tax companies are subject to specific disqualification triggers, which, if we fail to manage them, could jeopardize our qualified tonnage tax status in those countries. Certain of the disqualification events or actions are coupled with one or more opportunities to cure or otherwise maintain the tonnage tax qualification but not all are curable. Our qualified Singapore-based vessels are exempt from Singapore taxation through December 2017, with extensions available in certain circumstances beyond 2017, but there is no assurance that extensions will be granted. The qualified Singapore vessels are also subject to specific qualification requirements which, if not met, could jeopardize our qualified status in Singapore.

 

In addition, our worldwide operations may change in the future such that the mix of our income and losses recognized in the various jurisdictions could change. Any such changes could reduce our ability to utilize tax benefits, such as foreign tax credits, and could result in an increase in our effective tax rate and tax expense.

 

Our reported tax expense reflects our intention to permanently reinvest earnings from certain of our foreign operations and therefore those earnings are not subject to U.S. taxation. In the future, we may elect to decrease the portion of annual foreign earnings we intend to permanently reinvest, and, if so, this would increase our overall effective tax rate upward toward the U.S. federal statutory rate, which is currently 35%. If we should change our intention with regard to our prior years’ accumulated unremitted foreign earnings, we would recognize a charge to current earnings to reflect the effect of U.S. taxation on those prior years’ unremitted foreign earnings and that charge could be significant and material.

 

Our income tax expense, or benefit, and effective tax rate are impacted by inclusion of related U.S. earnings, or losses, taxed at the combined U.S. federal and state tax rates, which are subject to tax law changes. In addition, our tax returns are subject to examination and review by the tax authorities in the jurisdictions in which we operate.

 

Our international operations and new vessel construction programs are vulnerable to currency exchange rate fluctuations and exchange rate risks.

 

We are exposed to foreign currency exchange rate fluctuations and exchange rate risks as a result of our foreign operations and when we construct vessels abroad. To minimize the financial impact of these risks, we attempt to match the currency of our debt and operating costs with the currency of the revenue streams. We occasionally enter into forward foreign exchange contracts to hedge specific exposures, which include exposures related to firm contractual commitments in the form of future vessel payments, but we do not speculate in foreign currencies. Because we conduct a large portion of our operations in foreign currencies, any increase in the value of the U.S. Dollar in relation to the value of applicable foreign currencies could adversely affect our operating revenue or construction costs when translated into U.S. Dollars.

 

Doing business through joint venture operations may require us to surrender some control over our assets and may lead to disruptions in our operations and business.

 

   We operate in several foreign areas through joint ventures with local companies, in some cases as a result of local laws requiring local company ownership. While the joint venture partner may provide local knowledge and experience, entering into joint ventures often requires us to surrender a measure of control over the assets and operations devoted to the joint venture, and occasions may arise when we do not agree with the business goals and objectives of our joint venture partner, or other factors may arise that make the continuation of the relationship unwise or untenable. Any such disagreements or discontinuation of the relationship could disrupt our operations, put assets dedicated to the joint venture at risk, or adversely affect the continuity of our business. If we are unable to resolve issues with a joint venture partner, we may decide to terminate the joint venture and either locate a different partner and continue to work in the area or seek opportunities for our assets in another market. The unwinding of an existing joint venture could prove to be difficult or time-consuming, and the loss of revenue related to the termination or unwinding of a joint venture and costs related to the sourcing of a new partner or the mobilization of assets to another market could adversely affect our financial condition, results of operations or cash flows.

 

 
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Vessel construction, enhancement, repair and drydock projects are subject to risks, including delays, cost overruns, and ship yard insolvencies which could have an adverse impact on our results of operations.

 

Our vessel construction, enhancement, repair and drydock projects are subject to risks, including delay and cost overruns, inherent in any large construction project, including:

 

 

shortages of equipment;

 

unforeseen engineering problems;

 

work stoppages;

 

lack of shipyard availability;

 

weather interference;

 

unanticipated cost increases;

 

shortages of materials or skilled labor; and

 

insolvency of the ship repairer or ship builder.

 

Significant cost overruns or delays in connection with our vessel construction, enhancement, repair and drydock projects could adversely affect our financial condition and results of operations. Significant delays could also result, under certain circumstances, in penalties under, or the termination of, long-term contracts under which our vessels operate. The demand for vessels we construct may diminish from anticipated levels, or we may experience difficulty in acquiring new vessels or obtaining equipment to fix our older vessels due to high demand, both circumstances which may have a material adverse effect on our revenues and profitability. Recent global economic issues may increase the risk of insolvency of ship builders and ship repairers, which could adversely affect the cost of new construction and the vessel repairs and could result, under certain circumstances, in penalties under, or termination of, long-term contracts relating to vessels under construction.

 

Our industry is highly competitive, which could depress vessel prices and utilization and adversely affect our financial performance.

 

We operate in a competitive industry. The principal competitive factors in the marine support and transportation services industry include:

 

 

price, service and reputation of vessel operations and crews;

 

national flag preference;

 

operating conditions;

 

suitability of vessel types;

 

vessel availability;

 

technical capabilities of equipment and personnel;

 

safety and efficiency;

 

complexity of maintaining logistical support; and

 

cost of moving equipment from one market to another.

 

In addition, an expansion in the supply of vessels in the regions in which we compete, whether through new vessel construction, the refurbishment of older vessels, or the conversion of vessels, could lower charter rates, which could adversely affect our business, financial condition and results of operations. Many of our competitors have substantially greater resources than we have. Competitive bidding and downward pressures on profits and pricing margins could adversely affect our business, financial condition and results of operations.

 

The operations of our fleet may be subject to seasonal factors.

 

Operations in the North Sea are generally at their highest levels during the months from April through August and at their lowest levels from December through February, primarily due to lower construction activity and harsh weather conditions during the winter months affecting the movement of drilling rigs. Vessels operating offshore Southeast Asia are generally at their lowest utilization rates during the monsoon season, which moves across the Asian continent between September and early March. The monsoon season for a specific Southeast Asian location generally lasts about two months. Activity in the U.S. Gulf of Mexico, like the North Sea, is often slower during the winter months when construction projects and other specialized jobs are most difficult, and during the hurricane season from June through November. Operations in any market may be affected by seasonality often related to unusually long or short construction seasons due to, among other things, abnormal weather conditions, as well as market demand associated with changes in drilling and development activities.

 

 
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We are subject to war, sabotage, piracy, cyber-attacks and terrorism risk.

 

War, sabotage, pirate, cyber and terrorist attacks or any similar risk may adversely affect our operations in unpredictable ways, including changes in the insurance markets, disruptions of fuel supplies and markets, particularly oil, and the possibility that infrastructure facilities, including pipelines, production facilities, refineries, electric generation, transmission and distribution facilities, offshore rigs and vessels, and communications infrastructures, could be direct targets of, or indirect casualties of, a cyber-attack or an act of piracy or terror. War or risk of war or any such attack may also have an adverse effect on the economy. Insurance coverage can be difficult to obtain in areas of pirate and terrorist attacks resulting in increased costs that could continue to increase. We periodically evaluate the need to maintain this insurance coverage as it applies to our fleet. Instability in the financial markets as a result of war, sabotage, piracy, cyber-attacks or terrorism could also adversely affect our ability to raise capital and could also adversely affect the oil, natural gas and power industries and restrict their future growth.

 

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may adversely affect our financial results.

 

Our business is dependent upon our operational systems to process a large amount of data and complex transactions.  If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected.  Our financial results could also be adversely affected if an employee or other third party causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems.  In addition, dependence upon automated systems may further increase the risk that operational system flaws, employee or other tampering or manipulation of those systems will result in losses that are difficult to detect.

 

Due to increasing technological advances, we have become more reliant on technology to help increase efficiency in our business.  We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks.  Any cyber security attacks that affect our facilities, our customers or any financial data could have a material adverse effect on our business.  In addition, cyber-attacks on our customer and employee data may result in a financial loss and may negatively impact our reputation.  Third-party systems on which we rely could also suffer operational system failure.  Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our business, operations and financial results.

 

Our U.S. flagged vessels may be requisitioned or purchased by the United States in case of national emergency or a threat to security.

 

We are subject to the Merchant Marine Act of 1936, which provides that, upon proclamation by the President of a national emergency or a threat to the security of the national defense, the Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by United States citizens (which includes United States corporations), including vessels under construction in the United States. If our vessels were purchased or requisitioned by the federal government, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire, but we would not be entitled to be compensated for any consequential damages we suffer. The purchase or the requisition for an extended period of time of one or more of our vessels could adversely affect our results of operations and financial condition.

 

The Maritime Restrictions established to comply with the Jones Act may have an adverse effect on us and our stockholders.

 

Under our certificate of incorporation, our Class A common stock is subject to certain transfer and ownership restrictions designed to protect our eligibility to engage in Coastwise Trade, including restrictions that limit the maximum permitted percentage of outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent, which we refer to collectively as the Maritime Restrictions. These Maritime Restrictions:

 

 

may cause the market price of our Class A common stock to be lower than the market price of our competitors who may not impose similar restrictions;

 

may result in transfers to non-U.S. citizens being void and ineffective and, thus, may impede or limit the ability of our stockholders to transfer or purchase shares of our Class A common stock;

 

provide for the automatic transfer of shares in excess of the maximum permitted percentage, which we refer to as Excess Shares, to a trust for sale and may result in non-U.S. citizens suffering losses from the sale of Excess Shares;

 

permit us to redeem Excess Shares, which may result in stockholders who are non-U.S. citizens being required to sell their Excess Shares of Class A common stock at an undesirable time or price or on unfavorable terms;

 

may adversely affect our financial condition if we must redeem Excess Shares or if we do not have the funds or ability to redeem the Excess Shares; and

 

may impede or discourage efforts by a third party to acquire us, even if doing so would benefit our stockholders.

 

Our business could be adversely affected if we do not comply with the Jones Act.

 

We are subject to the Jones Act, which requires that vessels carrying passengers or cargo between U.S. ports in Coastwise Trade be owned and managed by U.S. citizens, and be built in and registered under the laws of the United States. Violations of the Jones Act would result in our losing eligibility to engage in Coastwise Trade, the imposition of substantial penalties against us, including seizure or forfeiture of our vessels, and/or the inability to register our vessels in the United States, each of which could have a material adverse effect on our financial condition and results of operations. Although we currently believe we meet the requirements to engage in Coastwise Trade, and the Maritime Restrictions were designed to assist us in complying with these requirements, there can be no assurance that we will be in compliance with the Jones Act in the future.

 

 
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Circumvention or repeal of the Jones Act may have an adverse impact on us.

 

The Jones Act’s provisions restricting Coastwise Trade to vessels controlled by U.S. citizens may from time to time be circumvented by foreign interests that seek to engage in trade reserved for vessels controlled by U.S. citizens and otherwise qualifying for Coastwise Trade. Legal challenges against such actions are difficult, costly to pursue and are of uncertain outcome. There have also been attempts to repeal or amend the Jones Act, and these attempts are expected to continue. In addition, the Secretary of Homeland Security may suspend the citizenship requirements of the Jones Act in the interest of national defense. To the extent foreign competition is permitted from vessels built in lower-cost shipyards and crewed by non-U.S. citizens with favorable tax regimes and with lower wages and benefits, such competition could have a material adverse effect on domestic companies in the offshore service vessel industry subject to the Jones Act such as us.

 

We depend on key personnel, and our U.S. citizen requirements may limit our ability to recruit and retain qualified directors and executive officers.

 

We depend to a significant extent upon the efforts and abilities of our executive officers and other key management personnel. There is no assurance that these individuals will continue in such capacity for any particular period of time. The loss of the services of one or more of our executive officers or key management personnel could adversely affect our operations.

 

As long as shares of our Class A common stock remain outstanding, our chairman of the board and chief executive officer, by whatever title, must be U.S. citizens. In addition, our certificate of incorporation and bylaws specify that not more than a minority of directors comprising the minimum number of members of the Board of Directors necessary to constitute a quorum of the Board of Directors (or such other portion as the Board of Directors determines is necessary to comply with applicable law) may be non-U.S. citizens so long as shares of our Class A common stock remain outstanding. Our bylaws provide for similar citizenship requirements with regard to committees of the Board of Directors. As a result, we may be unable to allow a non-U.S. citizen, who would otherwise be qualified, to serve as a director or as our chairman of the board or chief executive officer.

 

Maintaining our current fleet size and configuration and acquiring vessels required for additional future growth require significant capital.

 

Expenditures required for the repair, certification and maintenance of a vessel typically increase with vessel age. These expenditures may increase to a level at which they are not economically justifiable and, therefore, to maintain our current fleet size we may seek to construct or acquire additional vessels. Also, customers may prefer modern vessels over older vessels, especially in weaker markets. The cost of adding a new vessel to our fleet can range from under $10 million to $100 million and potentially higher.

 

While we expect our cash on hand, cash flow from operations and available borrowings under our credit facilities to be adequate to fund our existing commitments, including our new-build vessel construction program, our ability to pay these amounts is dependent upon the success of our operations. To date, we have been able to obtain adequate financing to fund all of our commitments. See “Long-Term Debt” and “Liquidity and Capital Resources” in our Management’s Discussion and Analysis of Financial Condition and Results of Operations included in Part II, Item 7. We can give no assurance that we will have sufficient capital resources to build or acquire the vessels required to expand or to maintain our current fleet size and vessel configuration.

 

Growth through acquisitions and investment could result in operating difficulties, dilution and other harmful consequences that may adversely impact our business and results of operations.

 

We routinely evaluate potential acquisitions of single vessels, vessel fleets and businesses, and we expect to continue to enter into discussions regarding a wide array of potential strategic transactions. The process of integrating an acquisition could create unforeseen operating difficulties and expenditures. The areas where we face risks include:

 

 

diversion of management time and focus away from operating our business to integrating the business;

 

integration of the acquired company’s accounting, human resources and other administrative systems and the coordination of various business functions;

 

implementation of, and changes to, controls, procedures and policies at the acquired company;

 

transition of customers into our operations;

 

in the case of foreign acquisitions, the need to integrate operations across different cultures and languages and to address the particular economic, currency, political and regulatory risks associated with specific countries or regions;

 

cultural challenges associated with integrating employees from the acquired company into our organization, and retention of employees from the businesses we acquire;

 

 
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liability for activities of the acquired company before the acquisition, including violations of laws, commercial disputes, tax liabilities and other known and unknown liabilities; and

 

litigation or other claims in connection with the acquired company, including claims from terminated employees, customers, former stockholders or other third parties.

 

Our failure to address these risks or other problems encountered in connection with our past or future acquisitions or investments could cause us to fail to realize the anticipated benefits of such acquisitions or investments, incur unanticipated liabilities, and harm our business in general.

 

Future acquisitions could also result in dilutive issuances of our equity securities, the incurrence of debt or contingent liabilities, an increase in amortization expenses or write-offs of goodwill, any of which could harm our financial condition.

 

We can give no assurance that we will be able to identify desirable acquisition candidates or that we will have the financial resources necessary to pursue desirable acquisition candidates or be successful in entering into definitive agreements or closing any such acquisition on satisfactory terms. An inability to acquire additional vessels or businesses may limit our growth potential.

 

We may be unable to attract and retain qualified, skilled employees necessary to operate our business.

 

Our success depends in large part on our ability to attract and retain highly skilled and qualified personnel. Our inability to hire, train and retain a sufficient number of qualified employees could impair our ability to manage, maintain and grow our business. In crewing our vessels, we require skilled employees who can perform physically demanding work, often in harsh or challenging environments for extended periods of time. As a result of the volatility of the oil and gas industry and the demanding nature of the work, potential vessel employees may choose to pursue employment in fields that offer a more desirable work environment at wage rates that are competitive with ours. Further, we face strong competition within the broader oilfield industry for potential employees, including competition from drilling rig operators, for our fleet personnel. As vessels under our new vessel construction program are placed in service, we may not be able to hire a sufficient number of employees. It is possible that we will have to raise wage rates to attract workers and to retain our current employees. If we are not able to increase our charges to our customers to compensate for wage increases, our financial condition and results of operations may be adversely affected. If we are unable to recruit qualified personnel we may not be able to operate our vessels at full utilization, which would adversely affect our results of operations.

 

Climate change, climate change regulations and greenhouse gas effects may adversely impact our operations and markets.

 

There is a concern that emissions of greenhouse gases, or GHGs, such as carbon dioxide and methane, alter the composition of the global atmosphere in ways that affect the global climate. Climate change, including the impact of global warming, may create physical and financial risk for organizations whose operations are affected by the climate. Some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our business, financial condition and results of operations.

 

Financial risks relating to climate change are likely to arise from increasing regulation of GHG emissions, as compliance with any new rules could be difficult and costly. For example, from time to time legislation has been proposed in the U.S. Congress to reduce GHG emissions. In addition, in the absence of federal GHG legislation, the EPA has taken steps to regulate GHG emissions. Depending on the outcome of these or other regulatory initiatives, increased energy, environmental and other costs and capital expenditures could be necessary to comply with the relevant limitations. Our vessels also operate in foreign jurisdictions that are addressing climate changes by legislation or regulation. Unless and until legislation or regulations are enacted and their terms are finalized, we cannot reasonably or reliably estimate its impact on our financial condition, operating performance or ability to compete. In addition, any GHG related legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and gas produced by our customers. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

 

Prior events in the U.S. Gulf of Mexico have adversely impacted and are likely to continue to adversely impact our operations and financial condition.

 

In the aftermath of the Macondo Incident, the rig explosion and fire and subsequent oil spill in the Gulf of Mexico in April 2010, regulatory agencies with jurisdiction over oil and gas exploration adopted numerous new regulations and operating procedures.  If the new regulations, operating procedures and possibility of increased legal liability are viewed by our current or future customers as a significant increased financial burden on the drilling projects in the U.S. Gulf of Mexico, drillships and other floating rigs could depart the U.S. Gulf of Mexico for other potentially more profitable regions, which would likely adversely affect the demand for our equipment and services.  In addition, government agencies could issue new safety and environmental guidelines or regulations for drilling in the U.S. Gulf of Mexico that could disrupt or delay drilling operations, increase the cost of drilling operations or reduce the area of operations available for drilling.  All of these uncertainties, including such announced and potential changes in laws and regulations, the cost or availability of insurance and the decisions by customers, governmental agencies or other industry participants could result in a reduced demand for our equipment and services or increase our cost of operations, which could have an adverse effect on our business.  We cannot reasonably or reliably estimate to what extent any of the foregoing changes may occur, when they may occur, or how severely they may impact us.

 

 
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Adverse results of legal proceedings could materially adversely affect us.

 

We are subject to and may in the future be subject to a variety of legal proceedings and claims that arise out of the ordinary conduct of our business. Results of legal proceedings cannot be predicted with certainty. Irrespective of its merits, litigation may be both lengthy and disruptive to our operations and may require significant expenditures and cause diversion of management attention. We may be faced with significant monetary damages or injunctive relief against us that could materially adversely affect a portion of our business operations or materially and adversely affect our financial position and our results of operations should we fail to prevail in such matters.

 

A decrease in our customer base could adversely affect demand for our services and reduce our revenues.

 

We derive a significant amount of our revenue from a small number of offshore energy companies. Our loss of one of these significant customers, if not offset by sales to new or other existing customers, could have a material adverse effect on our business, financial condition and results of operations. In addition, in recent years, oil and natural gas companies, energy companies and drilling contractors have undergone substantial consolidation and additional consolidation is possible. Consolidation results in fewer companies to charter or contract for our services. Also, merger activity among both major and independent oil and natural gas companies affects exploration, development and production activity as the consolidated companies integrate operations to increase efficiency and reduce costs. Less promising exploration and development projects of a combined company may be dropped or delayed. Such activity may result in an exploration and development budget for a combined company that is lower than the total budget of both companies before consolidation, which could adversely affect demand for our vessels and thereby reduce our revenues.

 

Our stock price has been volatile and has declined significantly during the period from the fourth quarter of 2014 through the present, and it could decline again.

 

The securities markets in general and our Class A common stock in particular have experienced significant price and volume volatility in recent years. The market price and trading volume of our Class A common stock may continue to experience significant fluctuations due not only to general stock market conditions but also to a change in our industry conditions and in the price of crude oil.

 

ITEM 1B.  Unresolved Staff Comments

 

NONE

 

ITEM 2Properties

 

Our principal executive offices are leased and located in Houston, Texas. We lease offices and, in most cases, warehouse facilities for our local operations. Offices for our Southeast Asia operating segment are located in Singapore. Offices for our North Sea operating segment are located in Aberdeen, Scotland and Sandnes, Norway. Offices for our Americas operating segment are located in Macae, Brazil; Paraiso, Mexico; Port of Spain, Trinidad; and St. Rose and Youngsville, Louisiana. Our operations generally do not require highly specialized facilities, and suitable facilities are generally available on a lease basis as required.

 

ITEM 3.  Legal Proceedings

 

Various legal proceedings and claims that arise in the ordinary course of business may be instituted or asserted against us. Although the outcome of litigation cannot be predicted with certainty, we believe, based on discussions with legal counsel and in consideration of reserves recorded, that an unfavorable outcome of these legal actions would not have a material adverse effect on our consolidated financial position and results of operations. We cannot predict whether any such claims may be made in the future.

 

ITEM 4.  Mine Safety Disclosures

 

NOT APPLICABLE

 

 
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PART II

 

ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

Our Class A common stock is traded on the New York Stock Exchange (NYSE) under the symbol “GLF”. The following table sets forth the range of high and low sales prices for our common stock and the amount of cash dividends per share declared per share for the periods indicated:

 

   

2015

   

2014

 
   

High

   

Low

   

Dividend

   

High

   

Low

   

Dividend

 

Quarter ended March 31,

  $ 24.80     $ 13.04     $ 0.00     $ 50.31     $ 39.48     $ 0.25  

Quarter ended June 30,

  $ 17.38     $ 11.31     $ 0.00     $ 46.73     $ 42.70     $ 0.25  

Quarter ended September 30,

  $ 10.90     $ 6.09     $ 0.00     $ 44.72     $ 31.35     $ 0.25  

Quarter ended December 31,

  $ 8.79     $ 4.65     $ 0.00     $ 32.84     $ 19.76     $ 0.25  

 

As of February 26, 2016, there were approximately 445 holders of record of our Class A common stock.

 

Issuer Repurchases of Equity Securities

 

In December 2012, our Board approved a stock repurchase program for up to a total of $100.0 million of our issued and outstanding Class A common stock. Under the program, repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, or in privately negotiated transactions, all in accordance with SEC and other applicable legal requirements. In late 2012 and early 2013, we repurchased 373,619 shares of our Class A common stock for $13.3 million. In 2014, we repurchased 1,883,648 shares of our Class A common stock for $57.7 million.

 

We did not repurchase any of our Class A common stock in 2015. We are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement described below in our ability to make certain payments beyond permitted amounts for share repurchases. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt.”

 

Dividend Program 

 

The Board declared the following dividends for the years ended December 31:

 

   

2015

   

2014

 

Dividends Declared (in thousands)

  $ -     $ 26,214  

Dividend per share

  $ -     $ 1.00  

 

Our dividend policy is reviewed by the Board at such times as it deems appropriate in light of operating conditions, dividend restrictions of subsidiaries and investors or lenders, financial requirements, general business conditions and other factors it considers relevant. In each quarter of 2014, we paid a dividend of $0.25 per share of our Class A common stock. In February 2015, the Board suspended dividend payments indefinitely.

 

Pursuant to the terms of the indenture governing our Senior Notes, as further described in Note 5 to our Consolidated Financial Statements in Part II, Item 8, we may be restricted from declaring or paying any future dividends. In addition, we are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement described below in our ability make certain payments beyond permitted amounts for dividends, acquisitions or share repurchases. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Long-Term Debt.”

  

 
31

 

 

Performance Graph

 

The following performance graph and table compare the cumulative return on our Class A common stock to the Dow Jones Total Market Index and the Dow Jones Oilfield Equipment and Services Index for the periods indicated. The graph assumes (i) the reinvestment of dividends, if any, and (ii) that the value of the investment in our Class A common stock and each index was $100 at December 31, 2010.

 

 

2010

 

2011

 

2012

 

2013

 

2014

 

2015

GulfMark Offshore, Inc.

100

 

138

 

110

 

153

 

80

 

19

Dow Jones Total Market Index

100

 

101

 

118

 

157

 

177

 

178

Dow Jones Oilfield Equipment and Services Index

100

 

87

 

88

 

113

 

93

 

72

 

 
32

 

 

ITEM 6. Selected Financial Data

 

The data that follows should be read in conjunction with our Consolidated Financial Statements and the notes thereto included in Part II, Item 8 “Financial Statements and Supplementary Data,” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” included in Part II, Item 7.

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

   

2012

   

2011

 
   

(Amounts in thousands, except per share amounts)

 

Operating Data:

                                       

Revenue

  $ 274,806     $ 495,769     $ 454,604     $ 389,205     $ 381,870  

Direct operating expenses

    169,837       236,244       217,422       198,187       182,585  

Drydock expense

    15,387       24,840       24,094       33,280       15,932  

General and administrative expenses

    47,280       62,728       54,527       54,600       45,495  

Depreciation and amortization

    72,591       75,336       63,955       59,722       59,586  

Impairment charges

    152,103       8,995       -       1,152       1,750  

Gain on sale of assets and other

    1,160       (14,039 )     (5,870 )     (8,741 )     (2,018 )

Operating income (loss)

    (183,552 )     101,665       100,476       51,005       78,540  

Interest expense

    (36,946 )     (29,332 )     (23,821 )     (23,244 )     (22,314 )

Interest income

    260       307       202       338       748  

Gain (loss) on extinguishment of debt

    458       -       -       (4,378 )     -  

Foreign currency loss and other

    (1,088 )     (995 )     (1,289 )     (1,779 )     (2,346 )

Income tax (provision) benefit (a)

    5,633       (9,270 )     (4,962 )     (2,669 )     (4,694 )
                                         
                                         

Net income (loss)

  $ (215,235 )   $ 62,375     $ 70,606     $ 19,273     $ 49,934  

Amounts per common share (basic) (b):

                                       

Net income (loss)

  $ (8.70 )   $ 2.39     $ 2.70     $ 0.73     $ 1.92  

Weighted average common shares (basic)

    24,729       26,097       26,175       26,208       25,828  

Amounts per common share (diluted) (b):

                                       

Net income (loss)

  $ (8.70 )   $ 2.39     $ 2.70     $ 0.73     $ 1.91  

Weighted average common shares (diluted)

    24,729       26,097       26,185       26,228       25,962  

Statement of Cash Flows Data:

                                       

Cash provided by operating activities

  $ 43,357     $ 153,848     $ 126,702     $ 102,736     $ 97,471  

Cash used in investing activities

    (22,835 )     (121,104 )     (210,069 )     (198,764 )     (49,408 )

Cash provided by (used in) financing activities

    (47,281 )     (40,024 )     (39,598 )     150,604       (16,231 )

Effect of exchange rate changes on cash

    (2,087 )     (2,501 )     (1,644 )     1,782       (210 )

Other Data:

                                       

Adjusted EBITDA (c)

  $ 41,142     $ 185,996     $ 164,431     $ 111,879     $ 139,876  

Cash dividends per share (d)

  $ -     $ 1.00     $ 1.00     $ 1.00     $ -  

Total vessels in fleet as of year end (e)

    73       76       79       78       90  

Average number of owned or chartered vessels (f)

    71.4       74.3       70.5       71.0       73.8  

 

   

As of December 31,

 
   

2015

   

2014

   

2013

   

2012

   

2011

 
   

(In thousands)

 

Balance Sheet Data:

                                       

Cash and cash equivalents

  $ 21,939     $ 50,785     $ 60,566     $ 185,175     $ 128,817  

Vessels, equipment and other fixed assets, including construction in progress, net

    1,266,487       1,484,561       1,494,611       1,305,789       1,180,548  

Total assets

    1,370,232       1,716,355       1,773,292       1,745,674       1,499,799  

Long-term debt (g)

    499,607       544,732       500,864       500,999       305,830  

Total stockholders’ equity

    698,725       968,753       1,063,341       1,027,882       996,860  

 

(a)

See Note 6 “Income Taxes” to our Consolidated Financial Statements included in Part II, Item 8.

 

(b)

Earnings per share is based on the weighted-average number of shares of common stock and common stock equivalents outstanding.

 

(c)

EBITDA is defined as net income (loss) before interest expense, interest income, income tax (benefit) provision, and depreciation, amortization and impairment. Adjusted EBITDA is calculated by adjusting EBITDA for certain items that we believe are non-cash or non-operational, consisting of: (i) the cumulative effect of change in accounting principle, (ii) debt refinancing costs, (iii) loss from unconsolidated ventures, (iv) minority interests, and (v) other (income) expense, net. EBITDA and Adjusted EBITDA are not measurements of financial performance under generally accepted accounting principles, or GAAP, and should not be considered as an alternative to cash flow data, a measure of liquidity or an alternative to operating income or net income as indicators of our operating performance or any other measures of performance derived in accordance with GAAP.

  

 
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EBITDA and Adjusted EBITDA are presented because they are widely used by securities analysts, creditors, investors and other interested parties in the evaluation of companies in our industry. This information is a material component of certain financial covenants in our debt obligations. Failure to comply with the financial covenants could result in the imposition of restrictions on our financial flexibility. When viewed with GAAP results and the accompanying reconciliation, we believe the EBITDA and Adjusted EBITDA calculations provide additional information that is useful to gain an understanding of the factors and trends affecting our ability to service debt and meet our ongoing liquidity requirements. EBITDA is also a financial metric used by management as a supplemental internal measure for planning and forecasting overall expectations and for evaluating actual results against such expectations. However, because EBITDA and Adjusted EBITDA are not measurements determined in accordance with GAAP and are thus susceptible to varying calculations, EBITDA and Adjusted EBITDA as presented may not be comparable to other similarly titled measures used by other companies or comparable for other purposes. Also, EBITDA and Adjusted EBITDA, as non-GAAP financial measures, have material limitations as compared to cash flow provided by operating activities. EBITDA does not reflect the future payments for capital expenditures, financing–related charges and deferred income taxes that may be required as part of normal business operations.

 

The following table summarizes the calculation of EBITDA and Adjusted EBITDA for the periods indicated.

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

   

2012

   

2011

 
   

(In thousands)

 

Net income (loss)

  $ (215,235 )   $ 62,375     $ 70,606     $ 19,273     $ 49,934  

Interest expense

    36,946       29,332       23,821       23,244       22,314  

Interest income

    (260 )     (307 )     (202 )     (338 )     (748 )

Income tax provision (benefit)

    (5,633 )     9,270       4,962       2,669       4,694  

Depreciation, amortization and impairment

    224,694       84,331       63,955       60,874       61,336  

EBITDA

    40,512       185,001       163,142       105,722       137,530  

Adjustments:

                    -                  

Other *

    630       995       1,289       6,157       2,346  

Adjusted EBITDA

  $ 41,142     $ 185,996     $ 164,431     $ 111,879     $ 139,876  

 

*     Net amount includes foreign currency transaction adjustments and gain/loss on extinguishment of debt.

 

(d)

In December 2012, our Board declared an annual cash dividend on our Class A common stock of $1.00 per share. In each quarter of 2013 and 2014, our Board declared a quarterly cash dividend of $0.25 per share for a total dividend of $1.00 per share in each of the years 2012, 2013 and 2014. In February 2015, the dividend was suspended and no dividends were declared in 2015.

 

(e)

Includes managed vessels in addition to those that are owned at the end of the applicable period (excludes vessels held for sale). See “Worldwide Fleet” in Part I, Item 1 “Business” for further information concerning our fleet.

 

(f)

Average number of vessels is calculated based on the aggregate number of vessel days available during each period divided by the number of calendar days in such period and is adjusted for additions and dispositions occurring during each period.

 

(g)

Excludes current portion of long-term debt.

 

 
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ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

This information should be read in conjunction with our Consolidated Financial Statements, including the notes thereto, contained in Part II, Item 8 “Financial Statements and Supplementary Data.” See also Part II, Item 6 “Selected Consolidated Financial Data” and “Forward-Looking Statements.”

 

General

 

We provide marine support and transportation services to companies involved in the offshore exploration and production of oil and natural gas. Our vessels transport drilling materials, supplies and personnel to offshore facilities, and also move and position drilling structures. A substantial portion of our operations are international. Our fleet has grown in both size and capability, from 11 vessels in 1990 to our present number of 73 active vessels, through strategic acquisitions and the new construction of technologically advanced vessels, partially offset by dispositions of certain older, less profitable vessels. As of February 29, 2016, our active fleet includes 70 owned vessels, 38 of which are stacked, and three managed vessels, all of which are stacked. In addition, we currently have three vessels under construction that we expect to be delivered during 2016 and 2017.

 

Our results of operations are affected primarily by day rates, fleet utilization and the number and type of vessels in our fleet. Utilization and day rates, in turn, are influenced principally by the demand for vessel services from the offshore exploration and production sectors of the oil and natural gas industry. The supply of vessels to meet this fluctuating demand is related directly to the perception of future activity in both the drilling and production phases of the oil and natural gas industry as well as the availability of capital to build new vessels to meet the changing market requirements. As discussed below, the recent and sustained decline in the price of oil has materially and negatively impacted our results of operations.

 

We also provide management services to other vessel owners for a fee. We do not include charter revenue and vessel expenses of these vessels in our operating results; however, management fees are included in operating revenue. These vessels are excluded for purposes of calculating fleet rates per day worked and utilization in the applicable periods.

 

The operations of our fleet may be subject to seasonal factors. Operations in the North Sea are often at their highest levels from April to August and at their lowest levels from December through February. Operations in our other areas, although involving some seasonal factors, tend to remain more consistent throughout the year. Activity in the U.S. Gulf of Mexico may be slower during the hurricane season from June through November, although following a hurricane, activity may increase as there may be a greater demand for vessel services as repair and remediation activities take place.

 

Our operating costs are primarily a function of fleet configuration. The most significant direct operating cost is wages paid to vessel crews, followed by repairs and maintenance. Generally, fluctuations in vessel utilization have little effect on direct operating costs in the short term and, as a result, direct operating costs as a percentage of revenue may vary substantially due to changes in day rates and utilization.

 

In addition to direct operating costs, we incur fixed charges related to (i) the depreciation of our fleet, (ii) costs for routine drydock inspections, (iii) modifications designed to ensure compliance with applicable regulations, and (iv) maintaining certifications for our vessels with various international classification societies. The number of drydockings and other repairs undertaken in a given period generally determines our repair and maintenance expenses. The demands of the market, the expiration of existing contracts, the start of new contracts, seasonal factors and customer preferences influence the timing of drydocks.

 

Oil Price Impact

 

Beginning in late 2014, the oil and gas industry experienced a significant decline in the price of oil causing an industry-wide downturn which has continued through 2015 and into 2016. During that time, the price of oil declined significantly from over $100 per barrel in July 2014 to below $30 per barrel in February 2016. This downturn has impacted the operational plans for oil companies, resulting in reduced expenditures for exploration and production activities, and consequently has adversely affected the drilling and support service sector. These changes in industry dynamics decreased demand for OSV services and led to an excess number of vessels in all of our operating regions. We experienced a significant negative impact on day rates and utilization in 2015 that is continuing into 2016. In many regions, day rates for OSV services have fallen below the levels needed to sustain our business. See “-Fleet Commitments and Backlog.” Industry analysts predict that the offshore energy exploration and production market will remain depressed with further declines in day rates and utilization in 2016 and 2017. We currently expect that these adverse market conditions will continue for the foreseeable future. The continuation of these conditions could result in more of our vessels being without contracts and/or stacked or scrapped, in which case we may evaluate the vessel for impairment, and could further materially and adversely affect our financial condition, results of operations and cash flows.

 

 
35

 

 

Markets

 

North Sea. As of the date of this report, we continue to expect significant activity in the North Sea region during 2016. We also expect the renewed focus on operator savings, diminishing rig utilization and oversupply of OSVs to adversely impact vessel day rates.

 

Although cost efficiencies are the current priority of operators, we believe the North Sea region remains viable long-term with several large field developments in the United Kingdom, or U.K., and Norwegian sectors forecasted by industry analysis, along with decommissioning work and projects in the renewables sector. We expect these factors, combined with an upturn in drilling in remote northerly areas such as the Barents Sea, Kara Sea and offshore Greenland, to drive demand in the North Sea region in the coming years, although we can provide no assurance as to when these developments may occur.

 

Southeast Asia. The Southeast Asia resource basin consists predominantly of shallow water mature fields where production drilling is expected to continue throughout 2016. It is apparent that operators, both national oil companies and independent operators, are experiencing significant pressure to reduce their costs in light of the depressed oil prices and as a result their capital expenditure budgets continue to fall. As of the date of this report, we generally expect exploration drilling activities to remain at current levels throughout 2016, in the Southeast Asian markets, resulting in a continuation of current market conditions for AHTS support, although further declines in commodity prices or reductions of operators’ capital budgets would result in additional downward pressure on drilling activities in this region, and therefore on market conditions for AHTS support vessels.

 

Americas. During 2015, due to the decline in the commodities market and the resulting negative impact on demand for OSVs, we experienced significant downward pressure on our utilization and day rates in the Americas in all areas in which we operate. We do not expect the market in the Americas operating segment to recover to any great extent in 2016.

 

In December 2013, Mexico’s Congress approved a constitutional reform to allow private investment in Mexico’s energy sector. We anticipate Mexico to be a growing market for expanded deepwater activity when the market conditions improve. We plan to continue to actively bid into the area when opportunities arise.

 

Fleet Commitments and Backlog

 

A portion of our available fleet is committed under contracts of various terms. The following table outlines the percentage of our forward days under contract and revenue backlog as of February 29, 2016 and February 16, 2015:

 

   

As of February 29, 2016

   

As of February 16, 2015

 
   

2016

   

2017

   

2015

   

2016

 
   

Vessel Days

   

Vessel Days

   

Vessel Days

   

Vessel Days

 

North Sea

    41.0 %     18.0 %     53.0 %     25.0 %

Southeast Asia

    23.0 %     17.0 %     37.0 %     13.0 %

Americas

    2.0 %     0.0 %     34.0 %     10.0 %

Overall Fleet

    21.0 %     10.0 %     42.0 %     17.0 %
                                 

Revenue backlog (in thousands)

  $ 143,965             $ 451,186          

   

Our revenue backlog is calculated based on executed contracts with scheduled start dates. International vessel contracts are typically longer in duration and are generally only cancelable for non-performance. Domestic vessel contracts are typically shorter in duration and generally provide for other cancellation provisions, including termination for convenience.

 

Critical Accounting Policies and Estimates

 

The Consolidated Financial Statements, including the notes thereto, contained in Part II, Item 8 “Financial Statements and Supplementary Data,” contain information that is pertinent to management’s discussion and analysis of our financial condition and results of operations. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of any contingent assets and liabilities. Management believes these accounting policies involve judgment due to the sensitivity of the methods, assumptions and estimates necessary in determining the related asset and liability amounts. We believe we have exercised proper judgment in determining these estimates based on the facts and circumstances available to management at the time the estimates were made.

 

 
36

 

 

Income Taxes

 

The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under “tonnage tax” regimes. Our U.K. regime was renewed in November 2010 for another ten years. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017, although there is no assurance that the extensions will be granted. The qualified Singapore vessels are also subject to specific qualification requirements which if not met could jeopardize our qualified status in Singapore. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These foreign tax beneficial systems continued to result in our earnings incurring significantly lower taxes than those that would apply if we were not a qualified shipping company in those jurisdictions. The tonnage tax regimes in the North Sea significantly reduce the cash required for taxes in that region.

 

Our overall effective tax rate is substantially lower than the U.S. federal statutory income tax rate because our Southeast Asia and North Sea operations are tonnage tax qualified shipping activities that are taxed at relatively low rates and our qualified Singapore based vessels are exempt from Singapore taxation through 2017. Should our operational structure change or should the laws that created these shipping tax regimes change, we could be required to provide for taxes at rates much higher than those currently reflected in our consolidated financial statements. In addition, if our pre-tax earnings in higher tax jurisdictions increase, there could be a significant increase in our annual effective tax rate. Any such increase could cause volatility in the comparisons of our effective tax rate from period to period.

 

U.S. foreign tax credits can be carried forward for ten years. We have $17.8 million of such foreign tax credit carry-forwards that begin to expire in 2016. As of December 31, 2015 we have an $11.6 million valuation allowance for certain of our foreign tax credits. We have considered estimated future taxable income in the relevant tax jurisdictions to utilize these tax credits and have considered what we believe to be ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be provided in the period such determination was made.

 

Utilizing a more likely than not, or greater than 50% probability, minimum recognition threshold for measurement of a tax position taken or expected to be taken in a tax return, we evaluate and record in certain circumstances an income tax asset/liability for uncertain income tax positions. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate. We also consider existing accounting guidance on derecognition, measurement, classification, interest and penalties, accounting in interim periods and disclosure. We continue to recognize income tax related penalties and interest in our provision for income taxes and include those interest and penalties and any amounts for uncertain tax positions in the corresponding consolidated balance sheet presentations for accrued income tax assets and liabilities.

 

We reduce the carrying value of certain deferred tax assets by the tax effect of the amount of excess stock compensation income tax deductions until such time as those tax deductions can be realized. This may result in our not recognizing any tax benefits for those excess tax deductions in the period in which they arise. Future recognition will result in a credit to additional paid-in capital rather than a reduction of income tax expense.

 

See also Note 1 and Note 6 to our Consolidated Financial Statements included in Part II, Item 8.

 

Long-Lived Assets, Goodwill and Intangibles

 

Our tangible long-lived assets consist primarily of vessels and construction-in-progress. Our intangible asset is associated with customer relationships in the U.S. Gulf of Mexico acquired in our 2008 acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, LLC. Our goodwill relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. In assessing potential impairment related to our long-lived assets, the carrying values of the assets are compared with undiscounted expected future cash flows. If the carrying value of any long-lived asset is greater than the related undiscounted expected future cash flows, we measure impairment by comparing the fair value of the asset with its carrying value. At least annually, we assess whether goodwill is impaired based on certain qualitative factors. Management’s assumptions are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported.

 

Beginning in late 2014, the oil and gas industry experienced a significant decline in the price of oil causing an industry-wide downturn which continued into 2015. This downturn impacted the operational plans for oil companies, resulting in reduced expenditures for exploration and production activities, and consequently adversely affected the drilling and support service sector. We experienced a significant negative impact on day rates and utilization in 2015.

 

As of December 31, 2014, we performed a full assessment of goodwill that did not indicate impairment. We performed another assessment in the second quarter of 2015 that did not indicate impairment, but the margin of coverage, given our assumptions, had narrowed since December 31, 2014. In the second quarter of 2015, we also performed a Step 1 assessment of our long-lived assets, including the intangible asset, for impairment and concluded that no impairment was indicated. These assessments were performed as a result of the triggering events described in the preceding paragraph.

 

 
37

 

 

Industry conditions continued to deteriorate in the third quarter of 2015 and we again performed full assessments. For the quarter ended September 30, 2015, we recorded in our consolidated statements of operations $152.1 million of impairment charges related to reduction in value of assets due to impairment. See discussions below detailing our impairment analyses and processes for each of our goodwill, long-lived assets, intangible asset and vessel components The components of reduction in value of assets are as follows (in thousands):

 

Goodwill impairment

  $ 22,554  

Long-lived assets impairment

    115,489  

Intangible asset impairment

    13,695  

Vessel component impairment

    365  

Total reduction in value of assets

  $ 152,103  

  

See “- Oil Price Impact.” We performed another assessment as of December 31, 2015 that did not identify any additional triggering events. We will continue to monitor the industry for triggering events that could indicate impairment in 2016.

 

Goodwill Impairment

 

Goodwill is tested for impairment in the third quarter each year or on an interim basis if events or circumstances indicate that the fair value of goodwill has decreased below its carrying value. We completed a qualitative analysis of goodwill in the third quarter of 2015 and determined that further testing was necessary. Our goodwill impairment evaluation indicated that the carrying value of the North Sea segment exceeded its fair value so that goodwill was potentially impaired. We then performed the second step of the goodwill impairment test, which involved calculating the implied fair value of our goodwill by allocating the fair value of the North Sea segment to all of the assets and liabilities (other than goodwill) and comparing it to the carrying amount of goodwill. To estimate the fair value of the reporting unit we used a 50% weighting of the discounted cash flow method and a 50% weighting of the public company guideline method in determining fair value of the North Sea reporting unit.

 

We determined that the implied fair value of our goodwill for the North Sea segment was less than its carrying value and recorded a $22.6 million impairment of the North Sea segment’s goodwill. As a result of this impariment, we no longer have any goodwill.

 

Long-Lived Asset Impairment

 

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of such assets to their fair value. Undiscounted cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of operating performance. If an asset group’s fair value is less than the carrying amount of that asset group, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value. The estimates of fair value of our vessels and intangible asset were obtained from fair value appraisals performed at our request by third party appraisal firms.

 

At September 30, 2015, we recorded $129.2 million in expense in connection with the impairment of our long-lived assets in the U.S. Gulf of Mexico, which is a part of our Americas segment. The impairment consisted of $115.5 million related to our vessels and $13.7 million related to our intangible asset. As a result of this impairment, we no longer have any intangible asset. The impairment in value of long-lived assets in the U.S. Gulf of Mexico was primarily driven by the disproportionally higher decline in day rates and utilization in the U.S. Gulf of Mexico compared to the other areas in which we provide offshore supply vessel services. We will continue to monitor the industry and our asset groups for indications of impairment and will perform additional assessments as conditions and circumstances warrant.

 

Vessel Component Impairment

 

We have certain vessel components in our North Sea region fixed asset base that were intended to be used in our new-build program. In the second quarter of 2014, we evaluated the use of these components and determined that they would not be used in our new-build fleet. We are actively pursuing a sale of the equipment, but there is a limited market. We adjusted the carrying value at June 30, 2014 to reflect the net realizable value. These assets are included in deferred costs and other assets on our balance sheet. The total charge to impairment expense related to these components at June 30, 2014 was $7.0 million. The adjustment value was based on an appraisal prepared by a third party appraisal firm. We obtained an updated appraisal at the end of each quarter since June 30, 2014 with no indications of material additional impairment until the third quarter 2015. We charged an additional $0.4 million to impairment expense as of September 30, 2015 based on the updated appraisal.

  

 
38

 

 

Drydocking, Mobilization and Financing Costs

 

The periodic requirements of the various classification societies require vessels to be placed in drydock twice in a five-year period. Generally, drydocking costs include refurbishment of structural components as well as major overhaul of operating equipment, subject to scrutiny by the relevant classification society. We expense these costs as incurred. As a result of current market conditions, we have taken many of our vessels out of service (stacked) and deferred a number of scheduled drydocks as part of our cost cutting initiatives. Eventually, the drydock will be required before the vessel can return to active service.

 

In connection with new long-term contracts, incremental costs incurred that directly relate to mobilization of a vessel from one region to another are deferred and recognized over the primary contract term. Should the contract be terminated by either party prior to the end of the contract term, the unamortized deferred amount would be immediately expensed. In contrast, costs of relocating vessels from one region to another without a contract are expensed as incurred.

 

Deferred financing costs are capitalized and amortized over the expected term of the related debt. Should the specific debt terminate by means of payment in full, tender offer or lender termination, the associated deferred financing costs would be immediately expensed.

 

Allowance for Doubtful Accounts

 

Our customers are primarily major and independent oil and gas companies, national oil companies and oil service companies. Given our experience where our historical losses have been insignificant and our belief that our related credit risks are minimal, our major and independent oil and gas company and oil service company customers are generally granted credit on customary business terms. Our exposure to foreign government-owned and controlled oil and gas companies, as well as companies that provide logistics, construction or other services to such oil and natural gas companies, may result in longer payment terms; however, we monitor our aged accounts receivable on an ongoing basis and provide an allowance for doubtful accounts in accordance with our written policy. This formalized policy requires a critical review of our aged accounts receivable to evaluate the collectability of our receivables and to establish appropriate allowances for bad debt. This policy states that a reserve for bad debt is to be established if an account receivable is outstanding a year or longer. The amount of such reserve to be established by management is based on the facts and circumstances relating to the particular customer.

 

Historically, we have collected substantially all of our accounts receivable balances. However, we have recently seen an increase in uncollectible amounts from certain customers. At December 31, 2015, 2014 and 2013 we provided an allowance for doubtful accounts of $1.5 million, $2.5 million and $0.4 million, respectively. Additional allowances for doubtful accounts may be necessary as a result of our ongoing assessment of our customers’ ability to pay, particularly in the event of further deteriorating industry conditions. Since amounts due from individual customers can be significant, future adjustments to our allowance for doubtful accounts could be material if one or more individual customer balances are deemed uncollectible. If an account receivable were deemed uncollectible and all reasonable collection efforts were exhausted, the balance would be removed from accounts receivable and the allowance for doubtful accounts.

 

Commitments and Contingencies

 

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims may involve threatened or actual litigation where damages have not been specifically quantified but we have made an assessment of our exposure and recorded a provision in our accounts for the expected loss. Other claims or liabilities, including those related to taxes in foreign jurisdictions, may be estimated based on our experience in these matters and, where appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of the uncertainties surrounding our estimates of contingent liabilities and future claims, our future reported financial results will be impacted by the difference, if any, between our estimates and the actual amounts paid to settle the liabilities. In addition to estimates related to litigation and tax liabilities, other examples of liabilities requiring estimates of future exposure include contingencies arising out of acquisitions and divestitures. Our contingent liabilities are based on the most recent information available to us regarding the nature of the exposure. Such exposures change from period to period based upon updated relevant facts and circumstances, which can cause the estimates to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure.

 

Multi-employer Pension Obligation          

 

Certain of our current and former U.K. subsidiaries are participating in a multi-employer retirement fund known as the Merchant Navy Officers Pension Fund, or MNOPF.  At December 31, 2015, we had $2.6 million accrued related to this liability, which reflects all obligations assessed on us by the fund’s trustee as of such date. We continue to have employees who participate in the MNOPF and will as a result continue to make routine payments to the fund as those employees accrue additional benefits over time.  The status of the fund is calculated by an actuarial firm every three years. The last assessment was completed in March 2015 and resulted in a significantly improved funding position, mainly due to hedging the interest rate and inflation risk.  The reported net deficit of the fund at March 31, 2015 was $7.5 million and, as a result, the MNOPF trustee did not propose to collect any additional deficit contributions related to the new deficit.  The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. In the year ended December 31, 2015 we made contributions to the plan of $0.4 million.  Our contributions do not make up more than five percent of total contributions to the plan.

  

 
39

 

 

In addition, we participate in the Merchant Navy Ratings Pension Fund, or MNRPF, in a capacity similar to our participation in the MNOPF.  Prior to 2013, we were not required to contribute to any deficit in the MNRPF. Due to a change in the plan rules, however, we were advised that we would be required to make contributions beginning in 2013.  An actuarial valuation was completed as of March 31, 2014 and deficit notices were communicated in the third quarter of 2015.  Our share of the deficit was calculated at $2.2 million, of which we paid $1.9 million in October 2015.  During 2015, we accrued amounts in respect of future deficit contributions.  As of December 31, 2015, the amount of this accrual was $0.5 million.

 

Off-Balance Sheet Arrangements

 

At December 31, 2015 and 2014, we had no off-balance sheet debt or other arrangements required to be disclosed in this report.

 

 

Consolidated Results of Operations

 

Comparison of Fiscal Years Ended December 31, 2015 and December 31, 2014

 

Our consolidated revenue decreased from $495.8 million in 2014 to $274.8 million in 2015, a decrease of $221.0 million or 44.6%. For the year ended December 31, 2015, we had a net loss of $215.2 million, or $8.70 per share, compared to net income of $62.4 million, or $2.39 per share for the year ended December 31, 2014.

 

In late 2014, the oil and natural gas industry entered a downturn precipitated by falling oil prices. The oil price decline had a significant negative effect on the demand for offshore supply vessels and, consequently, there has been substantial pressure on day rates and utilization. In 2015, overall fleet utilization decreased by 19.9% or $123.8 million, while day rates decreased by $5,476 per day or $73.2 million. The strength of the U.S. dollar caused a further decrease in revenue of $23.6 million, as a large portion of our revenue is earned in foreign currencies. An additional decrease of $0.4 million resulted from the net effect of a change in capacity as the sale of seven older vessels during 2014 and 2015 was partially offset by the acquisition of one vessel and the delivery of three new-builds. Our total fleet size decreased from an average of 74.3 vessels during 2014 to an average of 71.4 vessels during 2015.

 

   

Year Ended December 31,

 
   

2015

   

2014

   

Increase

(Decrease)

 
   

(Dollars in thousands)

 

Average Rate Per Day Worked (a) (b):

                       

North Sea (c)

  $ 16,991     $ 22,782     $ (5,791 )

Southeast Asia ( c)

    11,471       15,210       (3,739 )

Americas ( c)

    17,128       23,248       (6,120 )

Overall Utilization (a) (b):

                       

North Sea

    80.5 %     89.0 %     (8.5 )%

Southeast Asia

    64.2 %     79.1 %     (14.9 )%

Americas

    52.1 %     85.0 %     (32.9 )%

Average Owned or Chartered Vessels (a) (d):

                       

North Sea

    28.4       30.4       (2.0 )

Southeast Asia

    13.0       15.2       (2.2 )

Americas

    30.0       28.7       1.3  

Total

    71.4       74.3       (2.9 )

  

 

(a)

Owned vessels.

 

 

(b)

Average rate per day worked is defined as total charter revenues divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

 

 

(c)

Revenues for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (U.S. Dollar/GBP, U.S. Dollar/NOK and U.S. Dollar/Euro) for the periods indicated below. Payment for vessels in our Americas fleet can be earned in other currencies, including the Brazilian Reais (or BRL).

  

 
40

 

 

   

Year Ended December 31,

 
   

2015

   

2014

 

$1 US=GBP

    0.654       0.607  

$1 US=NOK

    8.048       6.285  

$1 US=Euro

    0.901       0.753  

$1 US=BRL

    3.277       2.347  

$1 US=SGD

    0.374       1.267  

 

 

(d)

Adjusted for vessel additions and dispositions occurring during each period.

 

In response to the industry pressure on our revenues, we implemented aggressive cost saving initiatives, including stacking vessels. The major cost saving attributable to stacking vessels is the reduction of crew wages and travel expense. In addition, we have deferred drydock costs on these stacked vessels even though these costs will eventually be required to return the vessels to active service. These initiatives have significantly decreased our operating costs. Concurrently, we reduced our onshore staffing levels globally. As a result, direct operating expenses decreased $66.9 million from 2014 to 2015, drydock expense decreased $9.5 million, and general and administrative expenses decreased $15.4 million. Depreciation expense decreased $2.7 million due to the sale of three older vessels during 2015, for which we recognized a loss of $1.2 million. As a result of the ongoing downturn in the industry, during the third quarter of 2015 we recognized impairment charges of $152.1 million related to the write-down of certain assets as described in Note 2 to our Consolidated Financial Statements in Part II, Item 8.

 

Other expenses increased by $7.3 million in 2015 compared to 2014. This increase was primarily due to higher interest expense of $7.6 million year over year related to the decrease in capitalized interest as we wind down our new-build program and acceleration of the amortization of debt issuance costs resulting from the modification of our debt facility agreements during 2015. Other expense increased $0.1 million due largely to an increase in foreign currency losses in 2015. Offsetting these expenses was a gain on extinguishment of debt of $0.5 million recognized during 2015.

 

The income tax benefit for 2015 was $5.6 million, compared to a tax expense of $9.3 million for 2014. The 2015 effective tax rate was a negative (2.6)% and the 2014 effective tax rate was 12.9%. Tax expense from year to year can vary based on the mix of profitability and taxing jurisdictions.

  

Comparison of Fiscal Years Ended December 31, 2014 and December 31, 2013

 

Our consolidated revenue increased from $454.6 million in 2013 to $495.8 million in 2014, an increase of $41.2 million or 9.1%. This increase was primarily due to increased capacity as well as higher day rates in all of our regions. Partially offsetting this increase was lower utilization in the Americas region. For the year ended December 31, 2014, we had net income of $62.4 million, or $2.39 per diluted share, compared to net income of $70.6 million, or $2.70 per diluted share, for the year ended December 31, 2013.

 

The main factor leading to the increase in revenue was an increase in fleet capacity, which is affected by vessel sales, vessel purchases and delivery of new-build vessels. During 2014, we took delivery of three new-build vessels and sold four older vessels. We also acquired a vessel from a third party in the first quarter of 2014. During 2013, we took delivery of five new-build vessels and sold three older vessels. The average number of owned vessels for 2014 was 74.3 compared to 70.5 for 2013. The net change in capacity caused an increase in revenue of $41.6 million. Day rates increased from $20,249 in 2013 to $21,529 in 2014, contributing $9.8 million to the increase in revenue. Fleet utilization decreased from 87.7% in 2013 to 85.5% in 2014, causing a decrease in revenue of $12.9 million. This decrease was mainly due to a decrease in utilization in the Americas region, as we lengthened five vessels under our vessel enhancement program during 2014. In addition, currency movements and other revenue caused an increase in revenue of $3.8 million.

 

 
41

 

 

   

Year Ended December 31,

 
   

2014

   

2013

   

Increase

(Decrease)

 
   

(Dollars in thousands)

 

Average Rate Per Day Worked (a) (b):

                       

North Sea (c)

  $ 22,782     $ 21,533     $ 1,249  

Southeast Asia ( c)

    15,210       14,792       418  

Americas ( c)

    23,248       21,689       1,559  

Overall Utilization (a) (b):

                       

North Sea

    89.0 %     90.1 %     (1.1 )%

Southeast Asia

    79.1 %     77.3 %     1.8 %

Americas

    85.0 %     91.2 %     (6.2 )%

Average Owned or Chartered Vessels (a) (d):

                       

North Sea

    30.4       25.8       4.6  

Southeast Asia

    15.2       16.0       (0.8 )

Americas

    28.7       28.7       0.0  

Total

    74.3       70.5       3.8  

   

 

(a)

Owned vessels.

 

 

(b)

Average rate per day worked is defined as total charter revenues divided by number of days worked. Overall utilization rate is defined as the total number of days worked divided by the total number of days of availability in the period.

 

 

(c)

Revenues for vessels in our North Sea fleet are primarily earned in GBP, NOK and Euros, and have been converted to U.S. Dollars at the average exchange rate (U.S. Dollar/GBP, U.S. Dollar/NOK and U.S. Dollar/Euro) for the periods indicated below. Payment for vessels in our Americas fleet can be earned in other currencies, including the BRL.

  

   

Year Ended December 31,

 
   

2014

   

2013

 

$1 US=GBP

    0.607       0.604  

$1 US=NOK

    6.285       6.072  

$1 US=Euro

    0.753       0.728  

$1 US=BRL

    2.347       2.362  

$1 US=SGD

    1.267       1.263  

 

 

(d)

Adjusted for vessel additions and dispositions occurring during each period.

 

Direct operating expenses increased by $18.9 million during 2014. The main factors related to this increase were an increase in crew salaries and benefits mainly due to the larger fleet size, combined with higher repairs and maintenance expense. Drydock expense increased by $0.7 million year over year. Although we undertook 23 drydocks during both 2013 and 2014, the drydocks that took place during 2014 were larger in scope, and therefore more costly. Depreciation expense increased $11.4 million due to the addition of the new-build and acquired vessels. We recognized an impairment expense during 2014 related to the write-down of equipment. The gain on sale of assets in 2014 was related to the sale of four older vessels, three of which were Southeast Asia based and one North Sea based. The gain on sale of assets in 2013 was related to the sale of two older North Sea vessels and one older vessel located in the Brazil sub-region.

 

Other expenses increased by $5.1 million in 2014 compared to 2013. This increase was primarily due to higher interest expense of $5.5 million year over year due mainly to a higher overall debt balance in 2014, coupled with lower capitalized interest as we wind down our current vessel construction program. Other expense decreased $0.3 million due to a decrease in foreign currency loss in 2014 compared to 2013.

 

The income tax expense for 2014 was $9.3 million, compared to $5.0 million for 2013. The 2014 effective tax rate was 12.9% and the 2013 effective tax rate was 6.6%. Tax expense from year to year can vary based on the mix of profitability and taxing jurisdictions.

 

 
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Segment Results

 

As discussed in “General Business” included in Part I, Item 1 “Business,” we have three operating segments: the North Sea, Southeast Asia and the Americas, each of which is considered a reportable segment under FASB ASC 280. The majority of our revenue is derived from our long-lived assets located in foreign jurisdictions. We had $73.4 million in revenue in 2015 and $431.7 million in long-lived assets as of December 31, 2015 attributed to the United States, our country of domicile.

 

Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally, and since the regions do not manage those items, the gains and losses on foreign currency re-measurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each segment’s operating performance from its continuing operations, because it represents the results of the ownership interest in operations without regard to financing methods or capital structures. Each segment’s operating income is summarized in the following table, and further detailed in the following paragraphs.

 

Operating Income (Loss) by Operating Segment

  

   

Year Ended December 31,

 
   

2015

     

2014

     

2013

 
   

(In thousands)

 

North Sea

  $ (8,774 )     $ 48,062       $ 45,749  

Southeast Asia

    29         29,723         17,972  

Americas

    (147,577 )       54,097         62,802  

Total reportable segment operating income (loss)

    (156,322 )       131,882         126,523  

Other

    (27,230 )       (30,217 )       (26,047 )

Total reportable segment and other operating income (loss)

  $ (183,552 )

 

  $ 101,665  

 

  $ 100,476  

  

North Sea Region: 

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands)

 

Revenue

  $ 142,168     $ 225,253     $ 184,287  

Direct operating expenses

    84,474       113,140       97,293  

Drydock expense

    4,112       9,094       10,058  

General and administrative expense

    9,469       17,226       13,884  

Depreciation and amortization expense

    28,724       32,440       23,410  

Impairment charge

    22,919       8,551       -  

(Gain) loss on sale of assets and other

    1,244       (3,260 )     (6,107 )

Operating income (loss)

  $ (8,774 )   $ 48,062     $ 45,749  

  

Comparison of Fiscal Years Ended December 31, 2015 and December 31, 2014

 

Revenue for the North Sea region decreased $83.1 million, or 36.9%, from $225.3 million in 2014 to $142.2 million in 2015. A decrease in average day rate of $5,791 per day, or $33.4 million was the largest contributor to the decrease. In addition, a decrease in utilization of 8.5% caused a decrease in revenue of $23.7 million. The strength of the U.S. dollar, particularly against the Norwegian Kroner, added $21.5 million to the decrease in revenue. The effect of the sale of four older vessels, offset somewhat by the addition of an acquired vessel and two new-build vessels, reduced revenue an additional $4.5 million. The average fleet size in the region decreased from 30.4 vessels in 2014 to 28.5 vessels in 2015. The operating loss of $8.8 million in 2015 was a decrease of $56.8 million from the 2014 result. This was caused primarily by the decrease in revenue, offset by decreases in direct operating expenses of $28.7 million, drydock expense of $5.0 million, general and administrative expenses of $7.8 million, and depreciation expense of $3.7 million. All these decreases are directly attributable to cost cutting measures implemented during 2015 and the decrease in average fleet size. We recognized an impairment charge of $22.9 million related to goodwill in 2015 and an impairment charge of $8.6 million related to certain equipment in 2014. In addition, during 2015 we recognized a loss on sale of assets of $1.2 million, compared to a gain of $3.3 million during 2014.

 

 
43

 

  

Comparison of Fiscal Years Ended December 31, 2014 and December 31, 2013

 

Revenue for the North Sea region increased $41.0 million, or 22.2%, in 2014 compared to 2013. Increased capacity in the region accounted for $38.8 million of the revenue increase. The average fleet size in the region increased from 25.8 vessels in 2013 to 30.4 vessels in 2014. This increase in capacity was due to the delivery of two new-build vessels and the purchase of one additional vessel from a third party during the first quarter of 2014. In addition, we benefited from the full year effect of the delivery of five new-build vessels during 2013. These additions were partially offset by the sale of two older vessels during 2013 and one late in 2014. Day rates increased from $21,533 in 2013 to $22,782 in 2014, an increase of 5.8%. Also, a currency fluctuation benefit of $4.6 million contributed to the increase. Partially offsetting these increases was a slight decrease in utilization, from 90.1% in 2013 to 89.0% in 2014. Operating income of $48.1 million in 2014 was $2.3 million higher than 2013. The increase in revenue was partially offset by an increase in direct operating expenses of $15.8 million and depreciation expense of $9.0 million, both of which are directly attributable to the increase in fleet size in 2014. We recognized an impairment charge of $8.6 million related to the write-down of equipment during 2014. Additionally, the gain on sale of assets of $3.3 million related to the sale of an older vessel was $2.8 million lower than the gain recognized during 2013 from the sale of two vessels. Partially offsetting these increases was a decrease of $1.0 million in drydock expense as 62 fewer drydock days were utilized in 2014. General and administrative expense increased by $3.3 million mainly due to bad debt expense recorded during 2014.

 

Southeast Asia Region: 

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands)

 

Revenue

  $ 35,524     $ 64,753     $ 64,709  

Direct operating expenses

    16,483       22,831       23,938  

Drydock expense

    4,356       4,400       5,612  

General and administration expense

    4,296       5,387       5,673  

Depreciation and amortization expense

    10,419       11,168       11,432  

Impairment charge

    -       444       -  

(Gain) loss on sale of assets and other

    (59 )     (9,200 )     82  

Operating income

  $ 29     $ 29,723     $ 17,972  

 

Comparison of Fiscal Years Ended December 31, 2015 and December 31, 2014

 

Revenues for the Southeast Asia based fleet decreased by $29.2 million to $35.5 million in 2015. Utilization decreased from 79.1% in 2014 to 64.2% in 2015, decreasing revenue by $17.0 million. Day rates decreased from $15,210 during 2014 to $11,471 for 2015, reducing revenue by $7.9 million. In addition, the effect of capacity changes decreased revenue by $4.3 million resulting from the full year effect of the sale of three older vessels during 2014. Average fleet size decreased by 2.2 vessels, from 15.2 vessels in 2014 to 13.0 vessels in 2015. Operating income decreased by $29.7 million due mainly to the decrease in revenue. Partially offsetting this decrease, cost cutting measures undertaken during 2015 and the decrease in fleet size decreased operating expenses by $6.3 million, general and administrative expenses by $1.1 million, and depreciation and amortization by $0.7 million. Drydock expense remained unchanged at $4.4 million during both years. In 2014, we recorded impairment related to certain equipment. There was no impairment charge in 2015, improving operating results by $0.4 million. The above expense decreases were partially offset by a gain on sale of $0.1 million recognized during 2015.

 

Comparison of Fiscal Years Ended December 31, 2014 and December 31, 2013

 

Revenues for the Southeast Asia based fleet increased by $0.1 million to $64.8 million in 2014. Utilization increased from 77.3% in 2013 to 79.1% in 2014, or $1.5 million, while day rates improved revenue by $0.5 million, increasing from $14,792 in 2013 to $15,210 in 2014. These increases were offset by a decrease in capacity due to the sale of three older vessels during 2014 which reduced revenue by $1.9 million. Operating income increased by $11.8 million due in part to a decrease of $1.1 million in direct operating expenses primarily associated with a decrease in fuel cost, a decrease in drydock expense of $1.2 million due to spending 115 fewer days in drydock in 2014 than in 2013, a decrease of $0.3 million in general and administrative expense and a decrease in depreciation of $0.3 million related to the sale of vessels. A $9.2 million gain on sale was also recognized in connection with the above mentioned vessel sales. Partially offsetting these decreases was an impairment charge of $0.4 million related to the write-down of equipment during 2014.

 

 
44

 

 

Americas Region: 

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands)

 

Revenue

  $ 97,114     $ 205,763     $ 205,608  

Direct operating expenses

    68,880       100,273       96,191  

Drydock expense

    6,919       11,346       8,424  

General and administrative expense

    9,906       12,837       11,415  

Depreciation and amortization expense

    29,827       28,789       26,661  

Impairment charge

    129,184       -       -  

(Gain) loss on sale of assets and other

    (25 )     (1,579 )     115  

Operating income (loss)

  $ (147,577 )   $ 54,097     $ 62,802  

  

Comparison of Fiscal Years Ended December 31, 2015 and December 31, 2014

 

Revenue for the Americas region decreased by $108.6 million in 2015, or 52.8%, to $97.1 million. Utilization for the region decreased from 85.0% in 2014 to 52.1% in 2015, resulting in a decrease in revenue of $83.1 million. Day rates decreased from $23,248 in 2014 to $17,128 in 2015, contributing $31.9 million to the revenue decrease. The strength of the U.S. dollar during 2015 caused a further decrease in revenue of $2.1 million. Partially offsetting these decreases was an increase of $8.5 million related to the full year effect of the delivery of one new-build vessel during 2014 and an additional new-build in early 2015. Average fleet size increased from 28.7 vessels in 2014 to 30.0 vessels in 2015. During 2015 the region had an operating loss of $147.6 million, compared to operating income of $54.1 million during 2014, a decrease of $201.7 million. Included in the 2015 operating loss were impairment charges of $129.2 million related to the write down of U.S. long lived and intangible assets. Excluding these charges, the decrease in operating income was $72.5 million. Partially offsetting the decrease in revenue were decreases in direct operating expenses of $31.4 million, drydock expense of $4.4 million, and general and administrative expenses of $2.9 million. These decreases were the direct result of cost cutting measures undertaken in early 2015. Depreciation and amortization expense increased by $1.0 million due to the addition of the two new-builds mentioned above. In addition, during 2014 we recognized a gain on sale of assets of $1.6 million compared to no gain during 2015.

 

Comparison of Fiscal Years Ended December 31, 2014 and December 31, 2013

 

Revenue for the Americas region increased by $0.2 million year over year. A day rate increase from $21,689 in 2013 to $23,248 in 2014 contributed $8.5 million to revenue. In addition, we took delivery of a new-build vessel during 2014, which was offset by the full year effect of the 2013 sale of an older vessel. The net impact of these two transactions resulted in a positive effect on revenue of $4.6 million. Offsetting these increases was a decrease in utilization from 91.2% in 2013 to 85.0% in 2014, amounting to a $12.9 million decrease in revenue. This decrease was mainly attributable to down time related to the enhancement of five vessels during 2014. Operating income of $54.1 million in 2014 was $8.7 million lower than 2013. Direct operating expenses increased by $4.1 million in 2014 mainly due to the increase in net capacity. Drydock expense increased $2.9 million due to an additional 26 days spent in drydock during 2014 compared to 2013. General and administrative expense increased by $1.4 million due primarily to increased salaries and benefits. Partially offsetting these increases in expenses was a $1.6 million cash recovery from a bankrupt shipyard.

 

Liquidity, Capital Resources and Financial Condition

 

Our ongoing liquidity requirements are generally associated with our need to service debt, fund working capital, maintain our fleet, and, when market conditions are favorable, finance the construction of new vessels and acquire or improve equipment or vessels. Bank financing, proceeds from the issuance of debt and equity, and internally generated funds have historically provided funding for these activities. Internally generated funds are directly related to fleet activity and vessel day rates, which are generally dependent upon the demand for our vessels which is ultimately determined primarily by the supply and demand for offshore drilling for crude oil and natural gas.

 

Industry Conditions

 

The ongoing and sustained decline in the price of oil that began in 2014 has materially and adversely affected our results of operations. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and further sustained low oil and natural gas prices could have a material adverse effect on our liquidity position. This downturn has also impacted the operational plans for the major oil companies, resulting in reduced expenditures for exploration and production activities, and consequently has adversely affected the drilling and support service sector.  As a result, we experienced a significant negative impact on day rates and utilization in 2015 that is continuing into 2016. In response to the downturn and the lower day rates, we have made changes to our cost structure, particularly to our onshore and offshore compensation and staffing.  We are continuing to adjust staffing and compensation levels and more closely control maintenance and outside services costs. We have stacked some vessels, significantly reducing variable costs associated with such vessels. 

 

 
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Due to the reduction in our revenues in 2015, we have determined to repatriate all future foreign earnings and $200.0 million of prior earnings of certain of our non-U.S. subsidiaries, thereby reducing our total permanently reinvested earnings.  This resulted in a non-cash tax charge in 2015 of approximately $70.0 million. We have not provided for U.S. deferred taxes on the remaining permanently reinvested earnings of approximately $850.0 million at December 31, 2015.  If these amounts were repatriated we would owe U.S. income taxes at the U.S. statutory tax rate minus applicable foreign tax credits.  As of December 31, 2015 we had approximately $21.4 million of cash held by our foreign subsidiaries which would be subject to U.S. tax upon repatriation.      

 

We are required to make expenditures for the certification and maintenance of our vessels. We expect to make $5.6 million in drydocking expenditures during 2016.

 

Construction of New Vessels

 

We are currently in the latter stages of a 12 vessel new-build program that we initiated in 2011. Beginning in the second quarter of 2013, we have delivered seven vessels to our North Sea region and two vessels to our Americas region. We currently have two remaining vessels under construction in the U.S. and one vessel, with Arctic capabilities, under construction in Norway. The U.S. vessels are significantly past the delivery date specified in the original contracts. As of the date of this report, we anticipate delivery of these remaining vessels in the third and fourth quarters of 2016, respectively, although additional delays may occur.  Given the significant delays and other technical problems associated with the construction and delivery of these vessels, to preserve our rights, we are currently in arbitration with BAE Systems as provided for under our contracts. The Norway vessel was scheduled to be delivered during the first quarter of 2016; however, in the fourth quarter of 2015, we amended our contract with the shipbuilder to delay delivery of the vessel until January 2017. Concurrently, we agreed to pay installments in the aggregate of 92.2 million NOK (or approximately $10.4 million at December 31, 2015) through May 2016 and a final installment of 195.0 million NOK (or approximately $22.1 million at December 31, 2015) in January 2017. In total, we are contracted to pay approximately $58.4 million through the first quarter of 2017 to complete these new-build vessels.

 

Cash and Working Capital

 

At December 31, 2015, our cash on hand totaled $21.9 million and net working capital was $39.5 million. The following table shows cash from operating, investing and financing activities:

  

   

Year Ended December 31,

 
   

2015

   

2014

 
    (in millions)    

Net cash provided by operating activities

  $ 43.4     $ 153.8  

Net cash used in investing activities

    (22.8 )     (121.1 )

Net cash used in financing activities

    (47.3 )     (40.0 )

Net decrease in cash and cash equivalents

  $ (26.7 )   $ (7.3 )

  

Operating Activities

 

Net cash provided by operating activities for the year ended December 31, 2015 was $43.4 million compared to $153.8 million provided by operating activities for the year ended December 31, 2014. The decrease was due primarily to lower revenue in 2015.

 

Investing Activities

 

Net cash used in investing activities for the year ended December 31, 2015 was $22.8 million compared to $121.1 million used in investing activities for the year ended December 31, 2014. The decrease in cash used in investing activities in 2015 was primarily due to less activity in our new build program. In 2014, we purchased one vessel, delivered three vessels from our new build program and had four vessels under construction that did not deliver in 2014. In 2015, we delivered one vessel early in the year and as of the date of this report have three vessels under construction.

 

Financing Activities

 

Net cash used in financing activities for the year ended December 31, 2015 was $47.3 million compared to $40.0 million used in financing activities for the year ended December 31, 2014. The increase in cash used in financing activities in 2015 was due to greater repayments of borrowings in 2015 than amounts borrowed.

 

 
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Resources and Liquidity

 

At December 31, 2015, we had approximately $21.9 million of cash on hand and $499.0 million outstanding under our Senior Notes described below. As of December 31, 2015 we had an aggregate of approximately $166.1 million of borrowing capacity, net of standby letters of credit, under our recently amended Multicurrency Facility Agreement and Norwegian Facility Agreement described below.

 

We expect cash on hand, future cash flows from operations, access to our revolving credit facilities, assuming no significant changes in the terms of such facilities, and limited vessel sales to be adequate to fund our new-build construction program, to repay our debts due and payable during such period, to complete scheduled drydockings, to make normal recurring capital additions and improvements and to meet our operating and working capital requirements. If operational performance does not improve significantly and oil companies do not increase spending for exploration and production activities, we may need additional sources of liquidity in the future as a result of our inability to generate sufficient cash flow from operations to service our long-term capital needs. If we need to supplement our cash flow or results of operations to continue to comply with the financial covenants under our Multicurrency Facility Agreement and Norwegian Facility Agreement, we may stack additional vessels, reduce the onshore and offshore workforce, or adjust the capital structure through open market purchases of debt at fair value or, if necessary, seek amendments to our Multicurrency Facility Agreement and Norwegian Facility Agreement depending on facts and circumstances at the time. There can be no assurance, however, that we would be able to negotiate acceptable terms for any such amendment.

 

We may, from time to time, issue debt or equity securities, or a combination thereof, to finance capital expenditures, the acquisition of assets and businesses or for general corporate purposes. Our ability to access the capital markets by issuing debt or equity securities will be dependent on our results of operations, our current financial condition, current credit ratings, current market conditions and other factors beyond our control.

 

Long-Term Debt

 

Senior Notes Due 2022

 

On March 12, 2012, we issued $300.0 million aggregate principal amount of 6.375% senior notes due 2022. On December 5, 2012, we issued an additional $200.0 million of senior notes with substantially the same terms as the previous $300.0 million issuance, which we refer to collectively as the Senior Notes. The Senior Notes pay interest semi-annually on March 15 and September 15. Prior to March 15, 2017, we may redeem some or all of the Senior Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The make-whole premium is based on U.S. Treasuries plus 50 basis points. On and after March 15, 2017, we may redeem some or all of the Senior Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.188% for the twelve-month period beginning March 15, 2017, 102.125% for the twelve-month period beginning March 15, 2018, 101.063% for the twelve-month period beginning March 15, 2019 and 100.000% beginning March 15, 2020, plus accrued and unpaid interest to the redemption date. In conjunction with the Senior Notes offering, we incurred $12.7 million in debt issuance costs which are included in our balance sheet under deferred costs and other assets and are being amortized into interest cost over the life of the Senior Notes using the effective interest method. On December 28, 2015, we repurchased in the open market $1.0 million face value of Senior Notes leaving $499.0 million aggregate principal amount of Senior Notes outstanding at December 31, 2015. Depending on market conditions, we may, from time to time, purchase our Senior Notes in the open market or otherwise.

 

Multicurrency Facility Agreement

 

We are party to a senior secured, revolving multicurrency credit facility, or the Multicurrency Facility Agreement, among GulfMark Offshore, Inc., as guarantor, one of our indirect wholly-owned subsidiaries, as the Borrower, a group of financial institutions as the Lenders and the Royal Bank of Scotland PLC as agent for the Lenders. The Multicurrency Facility Agreement has a scheduled maturity date of September 26, 2019 and, as amended, commits the Lenders to provide revolving loans up to $100.0 million at any one time outstanding, subject to certain terms and conditions, and contains sublimits of $25.0 million for swingline loans and $5.0 million for the issuance of letters of credit. Revolving loans and swingline loans under the Multicurrency Facility Agreement accrue interest at LIBOR, plus an applicable margin which may range from 2.75% to 4.00%. The applicable margin is based on our most recent capitalization ratio. The fee for unused commitments is 1.25% per annum. We are subject to certain financial and other covenants under the Multicurrency Facility Agreement, including covenants and restrictions requiring, among other things:

 

 

maintenance of a Capitalization Ratio, as defined, not to exceed 60% at the end of each fiscal quarter;

 

maintenance of a minimum Consolidated Interest Coverage Ratio, as defined, for any period of four consecutive fiscal quarters, of 1.5 to 1.0 beginning at the end of our third fiscal quarter of 2017 and increasing periodically thereafter;

 

maintenance of a minimum Collateral to Debt Ratio, as defined, of 3.0 to 1.0 at the end of each fiscal quarter;

 

maintenance of a minimum Collateral to Commitments Ratio, as defined, of 2.0 to 1.0 at the end of each fiscal quarter;

 

 
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maintenance of minimum Consolidated Adjusted EBITDA, as defined, as of the end of each fiscal quarter, of $5.0 million for the fourth quarter of 2015, $10.0 million for the six months ending March 31, 2016, $15.0 million for the nine months ending June 30, 2016 and $20.0 million for the four-quarter period ending September 30, 2016 and thereafter;

 

minimum liquidity (as determined under the Multicurrency Facility Agreement) at the end of each fiscal quarter of $35.0 million;

 

a mandatory prepayment if loans are outstanding and, on a consolidated basis, we have Cash, as defined, at the end of a fiscal quarter in excess of $35.0 million;

 

a prohibition on loans under the Multicurrency Facility Agreement for purposes of funding payments on our PSV under construction by Simek;

 

restrictions on the amount of cash we may invest for certain capital expenditures, acquisitions, joint ventures, dividends and share repurchases until December 31, 2017;

 

restrictions, subject to exceptions, on certain acquisitions, mergers, consolidations, joint ventures, changes of business, changes of ownership, indebtedness and asset sales; and

 

restrictions, subject to exceptions, on liens on our assets.

 

As of December 31, 2015, we were in compliance with all of the covenants in the Multicurrency Facility Agreement.

 

The Multicurrency Facility Agreement provides for customary events of default and contains cross-default provisions with all other debt instruments for indebtedness of $20.0 million or more in the aggregate (or its equivalent in other currencies). If an event of default occurs and continues, on the terms and subject to the conditions set forth in the Multicurrency Facility Agreement, the lenders may declare all amounts outstanding and accrued and all unpaid interest immediately due and payable, terminate the commitments under the Multicurrency Facility Agreement, and direct the Security Agent, as defined, to exercise any and all of its rights, remedies, powers or discretions under the Finance Documents, as defined.

 

On September 26, 2014, we entered into the Multicurrency Facility Agreement, which originally committed the Lenders to provide revolving loans up to $300.0 million at any one time outstanding, subject to certain terms and conditions.

 

In February 2015, we entered into an amendment to the Multicurrency Facility Agreement that reduced the requirement under the interest coverage ratio covenant. In return for the reduction, the Lenders imposed certain financial restrictions, including limiting our ability make certain payments for dividends, acquisitions or share repurchases. In connection with the amendment, we paid an additional $1.0 million in fees and our unused commitment fee rate increased from 37.5 basis points to 50.0 basis points.

 

In July 2015, we entered into another amendment to the Multicurrency Facility Agreement that, among other changes:

 

 

reduced the interest coverage ratio requirements applicable to certain periods;

 

changed the required collateral to Lenders’ commitments ratio for certain periods;

 

added a new mechanism for curing defaults on financial covenants; and

 

removed a requirement that we take delivery of certain vessels.

 

In return for the amendment, the Lenders required that we agree to certain changes, including

 

 

increasing the commitment fee during certain periods to 75 basis points;

 

reducing total commitments under the facility from $300.0 million to $200.0 million;

 

increasing the rate of interest accruing under the facility to LIBOR plus a margin, which is currently 2.75%;

 

adding a new covenant that liquidity not be less than $50.0 million;

 

reducing the amounts of business acquisitions, collateral dispositions, capital expenditures, joint ventures, distributions to equity holders and indebtedness permitted during certain periods; and

 

subjecting certain of our affiliated parties that are not obligors to the Multicurrency Facility Agreement’s limitations on business acquisitions, capital expenditures and joint ventures during certain periods.

 

In connection with this amendment, we paid an additional $0.9 million in fees, which is being capitalized and amortized over the remaining term of the Multicurrency Facility Agreement. In addition, since we reduced our overall borrowing capacity under the Multicurrency Facility Agreement, we were required to expense a portion of the debt issuance costs that were being deferred on our consolidated balance sheet. We charged $1.8 million to interest expense in the third quarter of 2015 in connection with this amendment.

 

In December 2015, we entered into another amendment to the Multicurrency Facility Agreement that, among other changes:

 

 

removed interest coverage ratio tests for certain periods;

 

increased the permissible capitalization ratio;

 

 
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redefined the Consolidated Adjusted EBITDA calculation to add back certain severance and other costs related to any discontinued operations or vessel redeployment;

 

reduced the threshold in the minimum liquidity covenant from $50.0 million to $35.0 million; and

 

added provisions permitting stacking of vessels if needed.

 

In return for the amendment, the Lenders required that we agree to certain changes, including:

 

 

increasing the pricing for any loans;

 

increasing the commitment fee during certain periods;

 

reducing commitments from $200.0 million to $100.0 million;

 

requiring prepayment of loans if quarter end cash on hand exceeds certain thresholds;

 

increasing collateral to debt ratio and collateral to commitment ratio requirements;

 

providing for additional reporting of financial and other information, including more frequent collateral appraisals;

 

limiting unscheduled capital expenditures or investments; and

 

precluding use of borrowings under the Multicurrency Facility Agreement to acquire the Norwegian Arctic class vessel currently under construction.

 

In connection with this amendment, we paid an additional $1.0 million in fees, which is being capitalized and amortized over the remaining term of the Multicurrency Facility Agreement. In addition, since we reduced our overall borrowing capacity under the Multicurrency Facility Agreement, we were required to expense a portion of the debt issuance costs that were being deferred on our consolidated balance sheet. We charged $2.1 million to interest expense in the fourth quarter of 2015 in connection with this amendment.

 

We have unamortized fees paid to the arrangers, the agent and the security trustee totaling $3.1 million at December 31, 2015, which fees are being amortized into interest cost on a straight-line basis over the life of the Multicurrency Facility Agreement.

 

The Multicurrency Facility Agreement is secured by 24 vessels of the Borrower. The collateral that secures the loans under the Multicurrency Facility Agreement may also secure all of the Borrower’s obligations under any hedging agreements between the Borrower and any Lender or other hedge counterparty to the Multicurrency Facility Agreement.

 

GulfMark Offshore, Inc. unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Multicurrency Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Borrower arising under any hedging arrangements. At December 31 2015, there were no amounts borrowed and outstanding under the Multicurrency Facility Agreement and we were in compliance with all the covenants under the Multicurrency Facility Agreement. The unused borrowing capacity under the Multicurrency Facility Agreement at December 31 2015, after giving effect to standby letters of credit, was $98.2 million. See “– Liquidity, Capital Resources and Financial Condition – Resources and Liquidity.”

 

Norwegian Facility Agreement

 

We are also party to a senior secured revolving credit facility, or the Norwegian Facility Agreement, among GulfMark Offshore, Inc., as guarantor, one of our indirect wholly-owned subsidiaries, as the borrower, which we refer to as the Norwegian Borrower, and a DNB Bank ASA, a Norwegian bank, as lead lender, which we refer to as the Norwegian Lender. The Norwegian Facility Agreement has a scheduled maturity date of September 30, 2019 and commits the Norwegian Lender to provide loans up to an aggregate principal amount of 600.0 million NOK (or approximately $67.9 million at December 31, 2015) at any one time outstanding, subject to certain terms and conditions. Loans under the Norwegian Facility Agreement accrue interest at the Norwegian InterBank Offered Rate, plus an applicable margin, which may range from 2.50% to 4.00%, depending on the interest coverage ratio. The fee for unused commitments is 1.25% per annum. We are subject to certain financial and other covenants under the Norwegian Facility Agreement, including covenants and restrictions requiring, among other things:

 

 

maintenance of a Capitalization Ratio, as defined, not to exceed 60% at the end of each fiscal quarter;

 

maintenance of a minimum ratio of Adjusted EBITDA to Interest Expense, each as defined, of 1.50 to 1.00 beginning at the end of our third fiscal quarter of 2017 and increasing periodically thereafter;

 

maintenance of minimum consolidated Adjusted EBITDA, as defined, as of the end of each fiscal quarter, of $5.0 million for the fourth quarter of 2015, $10.0 million for the six months ending March 31, 2016, $15.0 million for the nine months ending June 30, 2016 and $20.0 million for the four-quarter period ending September 30, 2016 and thereafter;

 

minimum liquidity (as determined under the Norwegian Facility Agreement) at the end of each fiscal quarter of $35.0 million;

 

mandatory prepayments and/or reductions in total commitments if our PSV under construction by Simek is delivered after March 31, 2017, or if the market value of the vessels securing the Norwegian Facility Agreement (as determined under the Norwegian Facility Agreement) is less than 300% of outstanding unpaid loans or less than 200% of total commitments, in each case unless certain additional security is provided;

 

 
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a mandatory prepayment if we have amounts drawn under the Multicurrency Facility Agreement and/or the Norwegian Facility Agreement and, on a consolidated basis, we have Cash, as defined, at the end of a fiscal quarter in excess of $35.0 million;

 

restrictions, subject to exceptions, on certain mergers, consolidations, divestitures, reconstructions and changes of business;

 

restrictions, subject to exceptions, on liens on certain of our assets; and

 

that we remain listed on the New York Stock Exchange or another recognized stock exchange.

 

As of December 31, 2015, we were in compliance with all of the covenants in the Norwegian Facility Agreement.

 

The Norwegian Facility Agreement provides for customary events of default and contains cross-default provisions with all other debt instruments for indebtedness of $20.0 million or more in the aggregate (or its equivalent in other currencies). If an event of default occurs and is continuing, on the terms and subject to the conditions set forth in the Norwegian Facility Agreement, the Norwegian Lender may declare all amounts outstanding and accrued and all unpaid interest immediately due and payable, terminate the commitments under the Norwegian Facility Agreement, enforce all rights under any security agreement, and exercise any rights and remedies under the Finance Documents, as defined.

 

We entered into the Norwegian Facility Agreement on December 27, 2012, and on June 20, 2013, we entered into an amendment to adjust certain covenants and to allow us to begin to draw on available credit. In connection with this amendment, we paid fees to the Norwegian Lender totaling $1.3 million, which are being amortized into interest cost over the life of the Norwegian Facility Agreement using the effective interest method. On October 23, 2014, we entered into another amendment to the Norwegian Facility Agreement which extended the scheduled maturity date from September 30, 2017 to September 30, 2019 and revised certain financial covenants.

 

In February 2015, we entered into an amendment to the Norwegian Facility Agreement that reduced the requirement under the covenant governing the interest coverage ratio. In return for the reduction, the lenders required that we agree to certain financial restrictions, including limiting our ability make certain payments for dividends, acquisitions or share repurchases. We paid an additional $0.2 million in fees in connection with this amendment.

 

In July 2015, we entered into an amendment to the Norwegian Facility Agreement that, among other changes:

 

 

modified the interest coverage ratio requirements applicable to certain periods to conform to the interest coverage ratio requirements applicable to the same periods as set forth in the Multicurrency Facility Agreement, as amended and described above;

 

added a new covenant that liquidity not be less than $50.0 million; and

 

increased the commitment fee from 50.0 basis points to 65.0 basis points per annum.

 

In connection with this amendment, we paid an additional $0.1 million in fees.

 

In January 2016, we entered into an amendment to the Norwegian Facility Agreement that, among other things:

 

 

provided for liens to be granted by the Norwegian Borrower on four vessels as additional collateral;

 

increased the rate of interest;

 

replaced EBITDA measurements with an Adjusted EBITDA measurement that, among other things, includes addbacks for certain costs associated with redeployment of vessels in connection with discontinued operations and certain severance costs;

 

extended the period for delivery of our PSV under construction by Simek until March 31, 2017 without triggering a mandatory prepayment or reduction in commitments;

 

added mandatory prepayment requirements in the event that the market value of the vessels securing the Norwegian Facility Agreement, as determined in accordance with its terms, is less than 300% of outstanding unpaid loans or less than 200% of total commitments, in each case unless certain additional security is provided;

 

added a mandatory prepayment requirement in the event that we, on a consolidated basis, have excess cash, as defined, at the end of a fiscal quarter;

 

provided for certain accelerated or more frequent financial reporting;

 

deferred the applicability of the interest coverage ratio requirement until the third quarter of 2017;

 

increased the permitted Capitalization Ratio, as defined, to 60%;

 

reduced the minimum liquidity requirement from $50 million to $35 million;

 

added a new minimum quarterly Adjusted EBITDA requirement;

 

increased the unused commitment fee rate to 1.25% per annum;

 

eliminated the covenant requiring maintenance of a minimum market value of the vessels securing the Norwegian Facility Agreement; and

 

 
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expressly permitted us to stack or lay up vessels securing the Norwegian Facility Agreement.

 

The Norwegian Facility Agreement is secured by eight vessels of the Norwegian Borrower and our additional North Sea PSV under construction by Simek. The collateral that secures the loans under the Norwegian Facility Agreement may also secure all of the Norwegian Borrower’s obligations under any hedging agreements between the Norwegian Borrower and the Norwegian Lender or other hedge counterparty to the Norwegian Facility Agreement.

 

GulfMark Offshore, Inc. unconditionally guaranteed all existing and future indebtedness and liabilities of the Norwegian Borrower arising under the Norwegian Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Norwegian Borrower arising under any hedging arrangements described above. At December 31 2015, there were no amounts borrowed and outstanding under the Norwegian Facility Agreement and we were in compliance with all the covenants under the Norwegian Facility Agreement. See “– Liquidity, Capital Resources and Financial Condition – Resources and Liquidity.”

 

Stock Repurchases

 

In December 2012, our Board of Directors, or Board, approved a stock repurchase program for up to a total of $100.0 million of our issued and outstanding Class A Common Stock. Under the program, repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, or in privately negotiated transactions, all in accordance with SEC and other applicable legal requirements. In late 2012 and early 2013, we repurchased 373,619 shares of our Class A common stock for $13.3 million. In 2014, we repurchased 1,883,648 shares of our Class A common stock for $57.7 million. We did not repurchase any of our Class A common stock in 2015. We are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement in our ability to make certain payments beyond permitted amounts for share repurchases.

 

Dividends

 

The Board declared the following dividends for the years ended December 31:

  

   

2015

   

2014

 

Dividends Declared (in thousands)

  $ -     $ 26,214  

Dividend per share

  $ -     $ 1.00  

 

Our dividend policy is reviewed by the Board at such times as it deems appropriate in light of operating conditions, dividend restrictions of subsidiaries and investors or lenders, financial requirements, general business conditions and other factors it considers relevant. In each quarter of 2014, we paid a cash dividend of $0.25 per share of our Class A common stock. In February 2015, the Board suspended dividend payments indefinitely.

 

Pursuant to the terms of the indenture governing our Senior Notes, as further described above and in Note 5 to our Consolidated Financial Statements in Part II, Item 8 “Financial Statements and Supplementary Data,” we may be restricted from declaring or paying any future dividends. In addition, we are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement in our ability make certain payments beyond permitted amounts for dividends, acquisitions or share repurchases.

 

Contractual Obligations

 

The following table summarizes our contractual obligations at December 31, 2015, and the effect these obligations are expected to have on liquidity and cash flows in future periods (in millions):

  

    Payments Due By Period  

Contractual Obligations

 

Total

   

Less than

one year

   

One to

three

years

   

Three to

five

years

   

Thereafter

 

Purchase Obligations for New-Build Program

  $ 58.4     $ 36.3     $ 22.1     $ -     $ -  

Repayment of Long-Term Debt

    499.0       -       -       -       499.0  

Interest Payments

    209.8       34.0       68.0       65.3       42.5  

Non-Cancelable Operating Leases

    10.2       2.0       3.0       2.6       2.6  

Other

    3.0       0.6       1.2       1.2       -  

Total

  $ 780.4     $ 72.9     $ 94.3     $ 69.1     $ 544.1  

 

Due to the uncertainty with respect to the timing of future cash payments, if any, associated with our unrecognized tax benefits at December 31, 2015 we are unable to make reasonably reliable estimates of cash settlements with the respective taxing authorities. Therefore, $24.7 million of unrecognized tax benefits have been excluded from the contractual obligations table above.

 

 
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Other Commitments

 

We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. We had $1.8 million in letters of credit outstanding at December 31, 2015. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment is minimal and expect no material cash outlays to occur from these instruments

 

Currency Fluctuations and Inflation

 

A majority of our operations are international; therefore we are exposed to currency fluctuations and exchange rate risks. Charters for vessels in our North Sea fleet are primarily denominated in GBP, with a portion denominated in NOK or Euros. In areas where currency risks are potentially high, we normally accept only a small percentage of charter hire in local currency, with the remainder payable in U.S. Dollars. Operating costs are substantially denominated in the same currency as charter hire in order to reduce the risk of currency fluctuations. The North Sea fleet generated 52% of our total consolidated revenue for the year ended December 31, 2015.

 

In 2015, the exchange rates of GBP, NOK, Euro, BRL, and SGD against the U.S.  Dollar ranged as follows:

 

   

High

   

Low

   

Year

Average

   

As of

February 26, 2016

 

$1 US=GBP

    0.683       0.629       0.654       0.716  

$1 US=NOK

    8.831       7.315       8.070       8.626  

$1 US=Euro

    0.954       0.827       0.902       0.907  

$1 US=BRL

    4.178       2.572       3.340       3.956  

$1 US=SGD

    1.433       1.318       1.375       1.401  

 

Our outstanding debt is denominated in U.S. Dollars, but a substantial portion of our revenue is generated in currencies other than the U.S. Dollar. We have evaluated these conditions and have determined that it is not in our interest to use any financial instruments to hedge this exposure under present conditions. Our strategy is in part based on a number of factors including the following:

 

 

the cost of using hedging instruments in relation to the risks of currency fluctuations;

 

the propensity for adjustments in these foreign currency denominated vessel day rates over time to compensate for changes in the purchasing power of these currencies as measured in U.S. Dollars;

 

the level of U.S. Dollar-denominated borrowings available to us; and

 

the conditions in our U.S. Dollar-generating regional markets.

 

One or more of these factors may change and, in response, we may begin to use financial instruments to hedge risks of currency fluctuations. We will from time to time hedge known liabilities denominated in foreign currencies to reduce the effects of exchange rate fluctuations on our financial results. We do not use foreign currency forward contracts for trading or speculative purposes.

 

Reflected in the accompanying consolidated balance sheet at December 31, 2015, is a $96.2 million loss in accumulated other comprehensive income primarily relating to the lower exchange rates at December 31, 2015 in comparison to the exchange rate when we invested capital in these markets. Accumulated other comprehensive income related to the changes in foreign currency exchange rates was a $30.7 million gain at December 31, 2014. Changes in the accumulated other comprehensive income are non-cash items that are primarily attributable to investments in vessels and U.S. Dollar-based capitalization between our parent company and our foreign subsidiaries. The 2015 activity reflects the changes in the U.S. Dollar compared to the functional currencies of our major operating subsidiaries, particularly in the U.K. and Norway.

 

To date, general inflationary trends have not had a material effect on our operating revenues or expenses.

 

New Accounting Pronouncements

 

Refer to Note 1 “Nature of Operations and Summary of Significant Accounting Policies–New Accounting Pronouncements” to our Consolidated Financial Statements included in Part II, Item 8 “Financial Statements and Supplementary Data”.

 

 
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ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk

 

The information included in this Item 7A is considered to constitute “forward-looking statements” for purposes of the statutory safe harbor provided in Section 27A of the Securities Act and Section 21E of the Exchange Act. See “Forward-Looking Statements.”

 

Financial Instruments 

 

We are subject to financial market risks, including fluctuations in foreign currency exchange rates and interest rates. In order to manage and mitigate our exposure to these risks, we may use derivative financial instruments in accordance with established policies and procedures. At December 31, 2015, we had no outstanding derivative contracts. Refer to Note 1 “Nature of Operations and Summary of Significant Accounting Policies—Fair Value of Financial Instruments” to our Consolidated Financial Statements included in Part II, Item 8 “Financial Statements and Supplementary Data” for additional information on financial instruments.

 

Our measure of market risk exposure represents an estimate of the change in fair value of our financial instruments. Market risk exposure is presented for each class of financial instrument held by us at December 31, 2015 and 2014, assuming immediate adverse market movements of the magnitude described below. We believe that the various rates of adverse market movements represent a measure of exposure to loss under hypothetically assumed adverse conditions. The estimated market risk exposure represents the hypothetical loss to future earnings and does not represent the maximum possible loss or any expected actual loss, even under adverse conditions, because actual adverse fluctuations would likely differ. In addition, since our investment portfolio is subject to change based on our portfolio management strategy as well as in response to changes in the market, these estimates are not necessarily indicative of the actual results that may occur.

 

Foreign Currency Risk

 

The functional currency for the majority of our international operations is that operation’s local currency. Adjustments resulting from the translation of the local functional currency financial statements to the U.S. Dollar, which is based on current exchange rates, are included in the Consolidated Statements of Stockholders’ Equity as a separate component of “Accumulated Other Comprehensive Income (Loss).” Working capital of our international operations may in part be held or denominated in a currency other than the local currency, and gains and losses resulting from holding those balances are included in the Consolidated Statements of Operations in “Other income (expense)” in the current period.

 

We operate in a number of international areas and are involved in transactions denominated in currencies other than U.S. Dollars, which exposes us to foreign currency exchange risk. At various times we may utilize forward exchange contracts, local currency borrowings and the payment structure of customer contracts to selectively hedge exposure to exchange rate fluctuations in connection with monetary assets, liabilities and cash flows denominated in certain foreign currencies. See Part II, Item 7 “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Currency Fluctuations and Inflation.” Other than trade accounts receivable and trade accounts payable, we do not currently have financial instruments that are sensitive to foreign currency exchange rates.

 

We transact business in various foreign currencies which subjects our cash flows and earnings to exposure related to changes in foreign currency exchange rates. We generally attempt to manage this exposure through operational strategies and not through the use of foreign currency forward exchange contracts. We do not engage in hedging activity for speculative or trading purposes.

 

From time to time, however, we may hedge firmly committed, anticipated transactions in the normal course of business and these contracts are designated and qualify as fair value hedges. Changes in the fair value of derivatives that are designated as fair value hedges are deferred in the Consolidated Statements of Stockholders’ Equity as a separate component of “Consolidated Statements of Comprehensive Income” until the underlying transactions occur. At such time, the related deferred hedging gains or losses are recorded on the same line as the hedged item.

 

Net foreign currency losses, including derivative activity, for the years ended December 31, 2015, 2014 and 2013 were $1.1 million, $1.0 million and $1.3 million, respectively.

 

 
53

 

 

Interest Rate Risk

 

We are subject to market risk for changes in interest rates related primarily to our long-term debt. The following table, which presents principal cash flows by expected maturity dates and weighted average interest rates, summarizes our fixed and variable rate debt obligations at December 31, 2015 and 2014 that are sensitive to changes in interest rates. The floating portion of our variable rate debt is based on LIBOR.

 

The following table shows our debt principal obligations as of December 31, 2015 and 2014 and the interest rate exposure in subsequent years of the components of our debt:

 

December 31, 2015

 

2015

   

2016

   

2017

   

2018

   

2019

   

Thereafter

 
   

(Dollar amounts in thousands)

 

Long-term Debt:

                                               

Senior Notes (fixed rate)

  $ 499,000     $ 499,000     $ 499,000     $ 499,000     $ 499,000     $ 499,000  

Average interest rate

    6.375 %     6.375 %     6.375 %     6.375 %     6.375 %     6.375 %
                                                 

Variable rate-Multicurrency Facility Agreement

  $ -     $ -     $ -     $ -     $ -     $ -  

Average interest rate

    0.00 %     0.00 %     0.00 %     0.00 %     0.00 %     0.00 %
                                                 

Variable rate-Norwegian Facility Agreement

  $ -     $ -     $ -     $ -     $ -     $ -  

Average interest rate

    0.00 %     0.00 %     0.00 %     0.00 %     0.00 %     0.00 %

 

December 31, 2014

 

2015

   

2016

   

2017

   

2018

   

2019

   

Thereafter

 
   

(Dollar amounts in thousands)

 

Long-term Debt:

                                               

Senior Notes (fixed rate)

  $ 500,000     $ 500,000     $ 500,000     $ 500,000     $ 500,000     $ 500,000  

Average interest rate

    6.375 %     6.375 %     6.375 %     6.375 %     6.375 %     6.375 %
                                                 

Variable rate-Multicurrency Facility Agreement

  $ 44,000     $ 44,000     $ 44,000     $ 44,000     $ 44,000     $ -  

Average interest rate

    2.26 %     2.26 %     2.26 %     2.26 %     2.26 %     0.00 %
                                                 

Variable rate-Norwegian Facility Agreement

  $ -     $ -     $ -     $ -     $ -     $ -  

Average interest rate

    0.00 %     0.00 %     0.00 %     0.00 %     0.00 %     0.00 %

 

 

 

  

Our fixed rate 6.375 % Senior Notes outstanding at December 31, 2015 subject us to risks related to changes in the fair value of the debt and expose us to potential gains or losses if we were to repay or refinance such debt. In general, the fair value of debt with a fixed interest rate will increase as interest rates fall. Conversely, the fair value of such debt will decrease as interest rates rise. A 1.0% change in market interest rates would increase or decrease the fair value of our fixed rate debt by approximately $35.0 million.

 

The fair value of our 6.375% Senior Notes compared to the carrying value at December 31, 2015 and 2014, was as follows:

 

   

December 31,

 
   

2015

   

2014

 
   

Carrying Value

   

Fair Value

   

Carrying Value

   

Fair Value

 
   

(In millions)

 
                                 

6.375% Senior Notes due 2022

  $ 499.6     $ 254.5     $ 500.7     $ 383.8  

 

 
54

 

  

ITEM 8. Financial Statements and Supplementary Data

  

Report of Independent Registered Public Accounting Firm

 

 

The Board of Directors and Stockholders

GulfMark Offshore, Inc.:

 

 

We have audited the accompanying consolidated balance sheets of GulfMark Offshore, Inc. and consolidated subsidiaries (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

 

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

 

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2015 and 2014, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), GulfMark Offshore, Inc. and its subsidiaries’ internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated February 29, 2016 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

 

KPMG LLP

Houston, Texas

February 29, 2016

 

 
55

 

 

Report of Independent Registered Public Accounting Firm

 

The Board of Directors and Stockholders

GulfMark Offshore, Inc.:

 

We have audited GulfMark Offshore, Inc. and consolidated subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). GulfMark Offshore, Inc. and consolidated subsidiaries’ management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.

 

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

 

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

In our opinion, GulfMark Offshore, Inc. and consolidated subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

 

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of GulfMark Offshore, Inc. and consolidated subsidiaries as of December 31, 2015 and 2014, and the related consolidated statements of operations, comprehensive income, stockholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2015, and our report dated February 29, 2016 expressed an unqualified opinion on those consolidated financial statements.

 

KPMG LLP

Houston, Texas
February 29, 2016

 

 
56

 

 

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

  

   

December 31,

 
   

2015

   

2014

 
   

(In thousands)

 
ASSETS                

Current assets:

               

Cash and cash equivalents

  $ 21,939     $ 50,785  

Trade accounts receivable, net of allowance for doubtful accounts of $1,480 and $2,506, respectively

    40,838       88,721  

Other accounts receivable

    7,571       9,410  

Prepaid expenses and other current assets

    16,649       17,825  

Total current assets

    86,997       166,741  

Vessels, equipment, and other fixed assets at cost, net of accumulated depreciation of $457,670 and $428,538, respectively

    1,195,669       1,356,839  

Construction in progress

    70,817       127,722  

Goodwill

    -       25,010  

Intangibles, net of accumulated amortization of $18,741 in 2014

    -       15,861  

Cash held in escrow

    -       3,683  

Deferred costs and other assets

    16,787       20,499  

Total assets

  $ 1,370,270     $ 1,716,355  
                 

LIABILITIES AND STOCKHOLDERS' EQUITY

               

Current liabilities:

               

Accounts payable

  $ 13,170     $ 22,494  

Income and other taxes payable

    6,485       4,578  

Accrued personnel costs

    12,942       20,403  

Accrued interest expense

    9,620       9,610  

Other accrued liabilities

    5,316       10,338  

Total current liabilities

    47,533       67,423  
                 

Long-term debt

    499,607       544,732  

Long-term income taxes:

               

Deferred income tax liabilities

    99,439       104,346  

Other income taxes payable

    21,351       24,730  

Other liabilities

    4,032       6,371  

Stockholders' equity:

               

Preferred stock, $0.01 par value; 2,000 shares authorized; no shares issued

    -       -  

Class A Common stock, $0.01 par value; 60,000 shares authorized; 27,994 and 27,361 shares issued and 25,792 and 25,114 shares outstanding, respectively; Class B Common Stock $.01 par value; 60,000 shares authorized; no shares issued

    274       271  

Additional paid-in capital

    417,289       410,641  

Retained earnings

    444,181       659,403  

Accumulated other comprehensive income (loss)

    (96,234 )     (30,665 )

Treasury stock, at cost

    (75,922 )     (78,441 )

Deferred compensation

    8,720       7,544  

Total stockholders' equity

    698,308       968,753  

Total liabilities and stockholders' equity

  $ 1,370,270     $ 1,716,355  

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 
57

 

 

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF OPERATIONS

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands, except per share amounts)

 
                         

Revenue

  $ 274,806     $ 495,769     $ 454,604  

Costs and expenses:

                       

Direct operating expenses

    169,837       236,244       217,422  

Drydock expenses

    15,387       24,840       24,094  

General and administrative expenses

    47,280       62,728       54,527  

Depreciation and amortization

    72,591       75,336       63,955  

Impairment charges

    152,103       8,995       -  

(Gain) loss on sale of assets and other

    1,160       (14,039 )     (5,870 )

Total costs and expenses

    458,358       394,104       354,128  

Operating income (loss)

    (183,552 )     101,665       100,476  

Other income (expense):

                       

Interest expense

    (36,946 )     (29,332 )     (23,821 )

Interest income

    260       307       202  

Gain on extinguishment of debt

    458       -       -  

Foreign currency loss and other

    (1,088 )     (995 )     (1,289 )

Total other expense

    (37,316 )     (30,020 )     (24,908 )

Income (loss) before income taxes

    (220,868 )     71,645       75,568  

Income tax benefit (provision)

    5,633       (9,270 )     (4,962 )

Net income (loss)

  $ (215,235 )   $ 62,375     $ 70,606  

Earnings (loss) per share:

                       

Basic

  $ (8.70 )   $ 2.39     $ 2.70  

Diluted

  $ (8.70 )   $ 2.39     $ 2.70  

Weighted average shares outstanding:

                       

Basic

    24,729       26,097       26,175  

Diluted

    24,729       26,097       26,185  

Cash dividends declared per common share

  $ -     $ 1.00     $ 1.00  

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 
58

 

 

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands)

 

Net income (loss)

  $ (215,235 )   $ 62,375     $ 70,606  

Comprehensive income:

                       

Foreign currency and other loss

    (65,569 )     (80,630 )     (9,910 )

Total comprehensive income (loss)

  $ (280,804 )   $ (18,255 )   $ 60,696  

 

The accompanying notes are an integral part of these consolidated financial statements.


 
59

 

 

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

For the Years Ended December 31, 2015, 2014 and 2013

(In thousands)

 

   

Common

                   

Accumulated

                                 
   

Stock at

   

Additional

           

Other

                   

Deferred

   

Total

 
   

$0.01 Par

   

Paid-in

   

Retained

   

Comprehensive

    Treasury            

Compen-

   

Stockholders'

 
   

Value

   

Capital

   

Earnings

   

Income (loss)

   

 Stock

           

sation

   

Equity

 
                                           

Share

                 
                                   

Shares

   

Value

                 
                                                                 

Balance at December 31, 2012

    266       389,881       579,062       59,875       (367 )     (11,533 )     10,331       1,027,882  

Net income

    -       -       70,606       -       -       -       -       70,606  

Issuance of common stock

    3       10,258       -       -       -       -       -       10,261  

Exercise of stock options

    -       282       -       -       -       -       -       282  

Tax benefit on options exercised

    -       1,608       -       -       -       -       -       1,608  

Deferred compensation plan

    -       257       -       -       133       4,041       (4,041 )     257  

Stock repurchases

    -       -       -       -       (315 )     (11,198 )     -       (11,198 )

Cash dividends declared

    -       -       (26,447 )     -       -       -       -       (26,447 )

Translation adjustment

    -       -       -       (9,910 )     -       -       -       (9,910 )

Balance at December 31, 2013

    269       402,286       623,221       49,965       (549 )     (18,690 )     6,290       1,063,341  

Net income

    -       -       62,375       -       -       -       -       62,375  

Issuance of common stock

    2       8,190       -       -       -       -       -       8,192  

Exercise of stock options

    -       -       -       -       -       -       -       -  

Tax benefit on options exercised

    -       -       -       -       -       -       -       -  

Deferred compensation plan

    -       165       -       -       (37 )     (1,254 )     1,254       165  

Stock repurchases

    -       -       -       -       (1,898 )     (58,497 )     -       (58,497 )

Cash dividends declared

    -       -       (26,193 )     -       -       -       -       (26,193 )

Translation adjustment

    -       -       -       (80,630 )     -       -       -       (80,630 )

Balance at December 31, 2014

    271       410,641       659,403       (30,665 )     (2,484 )     (78,441 )     7,544       968,753  

Net loss

    -       -       (215,235 )     -       -       -       -       (215,235 )

Issuance of common stock

    3       9,890       -       -       -       -       -       9,893  

Deferred compensation plan

    -       (3,242 )     -       -       (104 )     (1,176 )     1,176       (3,242 )

Treasury stock activity (net)

    -       -       -       -       45       3,695       -       3,695  

Forfeiture of dividends

    -       -       13       -       -       -       -       13  

Translation adjustment

    -       -       -       (65,569 )     -       -       -       (65,569 )

Balance at December 31, 2015

    274       417,289       444,181       (96,234 )     (2,543 )     (75,922 )     8,720       698,308  

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 
60

 

 

GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

CONSOLIDATED STATEMENTS OF CASH FLOWS

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 
   

(In thousands)

 

Cash flows from operating activities:

                       

Net income (loss)

  $ (215,235 )   $ 62,375     $ 70,606  

Adjustments to reconcile net income (loss) to net cash provided by operating activities:

                       

Depreciation and amortization

    72,591       75,336       63,955  

Amortization of deferred financing costs

    2,394       1,945       1,780  

Amortization of stock-based compensation

    6,735       7,330       9,366  

Provision for doubtful accounts receivable, net of write offs

    (862 )     3,236       (294 )

Deferred income tax provision (benefit)

    (3,784 )     (66 )     21  

(Gain) loss on sale of assets

    1,160       (12,461 )     (5,870 )

Impairment charges

    152,103       8,995       -  

Gain on extinguishment of debt

    (458 )     -       -  

Foreign currency (gain) loss

    (160 )     1,490       573  

Change in operating assets and liabilities —

                       

Accounts receivable

    47,317       5,700       (17,951 )

Prepaids and other

    214       (476 )     7,954  

Accounts payable

    (8,602 )     (3,888 )     (1,681 )

Other accrued liabilities and other

    (10,056 )     4,332       (1,757 )

Net cash provided by operating activities

    43,357       153,848       126,702  

Cash flows from investing activities:

                       

Purchases of vessels, equipment and other fixed assets

    (35,428 )     (158,425 )     (261,867 )

Release of deposits held in escrow

    3,683       5,060       38,286  

Proceeds from disposition of vessels, equipment and other fixed assets

    8,910       32,261       13,512  

Net cash used in investing activities

    (22,835 )     (121,104 )     (210,069 )

Cash flows from financing activities:

                       

Repuchase of 6.375% senior notes

    (542 )     -       -  

Repayment of revolving loan facility

    (91,000 )     -       -  

Borrowings under revolving loan facility, net

    47,000       47,167       -  

Cash dividends

    -       (26,152 )     (26,357 )

Stock repurchases

    -       (57,887 )     (12,740 )

Debt issuance costs

    (3,566 )     (4,198 )     (1,579 )

Proceeds from exercise of stock options

    -       -       282  

Proceeds from issuance of stock

    827       1,046       796  

Net cash used in financing activities

    (47,281 )     (40,024 )     (39,598 )

Effect of exchange rate changes on cash

    (2,087 )     (2,501 )     (1,644 )

Net decrease in cash and cash equivalents

    (28,846 )     (9,781 )     (124,609 )

Cash and cash equivalents at beginning of year

    50,785       60,566       185,175  

Cash and cash equivalents at end of year

  $ 21,939     $ 50,785     $ 60,566  

Supplemental cash flow information:

                       

Interest paid, net of interest capitalized

  $ 29,834     $ 27,067     $ 21,453  

Income taxes paid, net

  $ 2,048     $ 4,454     $ 3,727  

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 
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GULFMARK OFFSHORE, INC. AND SUBSIDIARIES

 

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

 

 

(1) NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 

Nature of Operations

 

GulfMark Offshore, Inc. and its subsidiaries (collectively referred to as “we”, “us”, “our” or the “Company”) own and operate offshore supply vessels, principally in the North Sea, offshore Southeast Asia and offshore the Americas. The vessels provide transportation of materials, supplies and personnel to and from offshore platforms and drilling rigs. Some of these vessels also perform anchor handling and towing services.

 

Principles of Consolidation

 

Our consolidated financial statements include our accounts and those of our majority-owned subsidiaries. All significant inter-company accounts and transactions have been eliminated.

 

Use of Estimates

 

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America, or U.S. GAAP, requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenue and expenses during the reporting period. The accompanying consolidated financial statements include significant estimates for allowance for doubtful accounts receivable, depreciable lives of vessels and equipment, valuation of goodwill, income taxes and commitments and contingencies. While we believe current estimates are reasonable and appropriate, actual results could differ from these estimates.

 

Cash and Cash Equivalents

 

 Our investments, consisting of U.S. Government securities and commercial paper with original maturities of up to three months, are included in cash and cash equivalents in the accompanying consolidated balance sheets and consolidated statements of cash flows.

 

Vessels and Equipment

 

Vessels and equipment are stated at cost, net of accumulated depreciation, which is provided by the straight-line method over their estimated useful life of 25 years for all vessels other than crew boats which are depreciated over 20 years. Interest is capitalized in connection with the construction of vessels. The capitalized interest is included as part of the asset to which it relates and is depreciated over the asset’s estimated useful life. In 2015, 2014, and 2013, interest of $5.0 million, $8.4 million and $12.8 million, respectively, was capitalized. Office equipment, furniture and fixtures, and vehicles are depreciated over two to five years.

 

Major renovation costs and modifications that extend the life or usefulness of the related assets are capitalized and depreciated over the assets’ estimated remaining useful lives. Maintenance and repair costs are expensed as incurred. Included in the consolidated statements of operations for 2015, 2014, and 2013, are $19.3 million, $31.6 million and $27.5 million, respectively, of costs for maintenance and repairs.

 

Goodwill and Intangibles

 

Our goodwill relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. Our intangible asset is associated with customer relationships in the U.S. Gulf of Mexico acquired in our 2008 acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, LLC. The determination of impairment of all long-lived assets, goodwill, and intangibles is conducted when indicators of impairment are present and at least annually for goodwill. Impairment testing for goodwill is performed on a reporting segment basis. In assessing goodwill for impairment, we analyze certain qualitative factors that affect the value, including goodwill of a segment. If those factors indicate that it is more likely than not that impairment of goodwill has occurred, we will proceed to step one of the goodwill impairment process. Our practice is to perform an assessment each year in the third quarter and to perform qualitative analyses at the end of each quarter. See Note 2 for results of our impairment analyses.

 

 
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Impairment of Long-Lived Assets

 

We review long-lived assets for impairment whenever there is evidence that the carrying amount of such assets may not be recoverable. This consists of comparing the carrying amount of the asset with its expected future undiscounted cash flows before tax and interest costs. If the asset’s carrying amount is less than such cash flow estimate, it is written down to its fair value on a discounted cash flow basis. Estimates of expected future cash flows represent management’s best estimate based on currently available information and reasonable and supportable assumptions. Any impairment recognized is permanent and may not be restored. See Note 2 for the results of our impairment analyses.

 

Fair Value of Financial Instruments

 

As of December 31, 2015 and 2014, our financial instruments consist primarily of accounts receivable and payable (which are stated at carrying value which approximates fair value) and long-term debt. Periodically, we enter into forward derivative contracts to hedge our exposure to interest rate or foreign currency fluctuations. In the past we have had open positions in such derivative contracts that are considered financial instruments for which we would disclose certain fair value information. As of December 31, 2015 and 2014, we had no forward derivative open contracts.

 

Deferred Costs and Other Assets

 

Deferred costs and other assets consist primarily of deferred financing costs and deferred vessel mobilization costs. Deferred financing costs are amortized over the expected term of the related debt. Should the debt for which a deferred financing cost has been recorded terminate by means of payment in full, tender offer or lender termination, the associated deferred financing costs would be immediately expensed.

 

In connection with new long-term contracts, costs incurred that directly relate to mobilization of a vessel from one region to another are deferred and recognized over the primary contract term. Should either party terminate the contract prior to the end of the original contract term, the deferred amount would be immediately expensed. Costs of relocating vessels from one region to another without a contract are expensed as incurred.

 

Revenue Recognition

 

Revenue from charters for offshore marine services is recognized as performed based on contractual charter rates and when collectability is reasonably assured. Currently, charter terms range from as short as several days to as long as 10 years in duration. Management services revenue is recognized in the period in which the services are performed.

 

Income Taxes

 

We recognize the amount of current year income taxes payable or refundable and deferred tax assets and liabilities for the expected future tax consequences of events that have been recognized in the financial statements or tax returns previously filed. Under this method, deferred tax assets and liabilities are determined based on the difference between the financial statement carrying amounts and tax bases of assets and liabilities using enacted tax rates and laws in effect for the years in which the differences are expected to reverse. The likelihood and amount of future taxable income and tax planning strategies are included in the criteria used to determine the timing and amount of net deferred tax assets recognized for net operating loss and tax credit carry-forwards in our consolidated financial statements. These deferred tax assets are, when appropriate, reduced by a valuation allowance resulting in net deferred tax assets that are more likely than not to be realized.

 

A significant amount of judgment in our use of assumptions and estimates is required in our methodology for determining and recording income taxes. In some instances we use forecasts of expected operations and related tax implications and we consider the possibility of implementing tax planning strategies. Such variables can result in uncertainty and measurable variation between anticipated and actual results can occur. Changes to these variables as a result of unforeseen events may have a material impact on our income tax accounts.

 

In recent years we have had operations in over 40 countries and are or have been subject to a significant number of taxing jurisdictions. Our income earned in these jurisdictions is taxed on various bases, including actual income earned, deemed profits, and revenue based withholding taxes. Our income tax determinations involve the interpretation of applicable tax laws, tax treaties, and related tax rules and regulations of those jurisdictions. Changes in tax law, currency/repatriation controls and interpretation of local tax laws by the relevant tax authority could impact our income tax liabilities or assets in those jurisdictions.

 

 

In addition, we also account for uncertainty in income taxes by utilizing a more likely than not, or greater than 50% probability, minimum recognition threshold for measurement of a tax position taken or expected to be taken in a tax return that would be sustained upon examination by the relevant tax authorities. We recognize penalties and/or interest related to uncertain tax benefits as a component of income tax expense. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and /or benefits, which may be adjusted periodically and may be resolved differently than we anticipate.

 

 
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We reduce the carrying value of certain deferred tax assets by the tax effect of the amount of excess stock compensation income tax deductions until such time as those tax deductions can be realized. This may result in our not recognizing any tax benefits for those excess tax deductions in the period in which they arise. Future recognition will result in a credit to additional paid in capital rather than a reduction of income tax expense.

 

Foreign Currency Translation

 

The local currencies of the majority of our foreign operations have been determined to be their functional currencies, except for certain foreign operations whose functional currency has been determined to be the U.S. Dollar, based on an assessment of the economic circumstances of the foreign operations. Assets and liabilities of our foreign affiliates are translated at year-end exchange rates, while revenue and expenses are translated at average rates for the period. As a result, amounts related to changes in assets and liabilities reported in the consolidated statements of cash flows will not necessarily agree to changes in the corresponding balances on the consolidated balance sheets. We consider most intercompany loans to be long-term investments; accordingly, the related translation gains and losses are reported as a component of stockholders’ equity. Transaction gains and losses are reported directly in the consolidated statements of operations. During the years ended December 31, 2015, 2014 and 2013, we reported net foreign currency losses in the amounts of $1.2 million, $2.0 million and $1.6 million, respectively.

 

Concentration of Credit Risk

 

We extend credit to various companies in the energy industry that may be affected by changes in economic or other external conditions. Our policy is to manage our exposure to credit risk through credit approvals and limits. Our trade accounts receivable are aged based on contractual payment terms and an allowance for doubtful accounts is established in accordance with our written corporate policy. The age of the trade accounts receivable, customer collection history and management’s judgment as to the customer’s ability to pay are considered in determining whether an allowance is necessary. In 2013, there were no significant write-offs or increases in our allowance for doubtful accounts. In 2014, we reserved $3.2 million related to two North Sea customers. In 2015, there were no significant write-offs or increases in our allowance for doubtful accounts. For the year ended December 31, 2015, we had revenue from one customer in our North Sea region and one customer in our Americas region which each accounted for 10% or more of our total consolidated revenue, totaling $32.4 million and $31.9 million, respectively, or 23.5% of our total consolidated revenue. For the year ended December 31, 2014, we had revenue from one customer in our Americas region and one customer in our North Sea region which each accounted for 10% or more of our total consolidated revenue, totaling $88.7 million and $50.0 million, respectively, or 28.2% of our total consolidated revenue. For the year ended December 31, 2013, we had revenue from one customer in our Americas region and one customer in our North Sea region which each accounted for 10% or more of our total consolidated revenue, totaling $64.6 million and $60.7 million, respectively, or 28.0% of our total consolidated revenue.

 

Stock-Based Compensation

 

We have share-based compensation plans covering officers and other employees as well as our Board of Directors. Stock-based grants made under our stock plans are recorded at fair value on the date of the grant and the cost is recognized ratably over the vesting period for the restricted stock and the stock options. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Restricted stock awards are valued using the market price of our Class A common stock on the grant date. Our stock-based compensation plans are more fully described in Note 8.

 

Our employee stock purchase plan would be considered compensatory whereby it allows all of our U.S. employees and participating subsidiaries to acquire shares of our Class A common stock at 85% of the fair market value of the Class A common stock under a qualified plan as defined by Section 423 of the Internal Revenue Code. The plan has a look-back option that establishes the purchase price as an amount based on the lesser of the Class A common stock’s market price at the grant date or its market price at the exercise date. The total value of the look-back option imbedded in the plan is calculated using the component approach where each award is computed as the sum of 15% of a share of non-vested stock, a call option on 85% of a share of non-vested stock, and a put option on 15% of a share of non-vested stock.

 

 
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Earnings Per Share

 

Basic earnings per share, or EPS, is computed by dividing net income (loss) by the weighted average number of shares of Class A common stock outstanding during the year. Diluted EPS is computed using the treasury stock method for common stock equivalents. The detail of the earnings per share calculations for continuing operations for the years ended December 31, 2015, 2014 and 2013 is as follows (in thousands, except per share amounts):

 

   

Year ended December 31,

 
                         
   

2015

   

2014

   

2013

 
Income:                        

Net income (loss) attributable to common stockholders

  $ (215,235 )   $ 62,375     $ 70,606  

Undistributed income allocated to participating securities

    -       -       (27 )

Basic

    (215,235 )     62,375       70,579  

Undistributed income allocated to participating securities

    -       -       16  

Undistributed income reallocated to participating securities

    -       -       (16 )

Diluted

  $ (215,235 )   $ 62,375     $ 70,579  

Shares:

                       

Basic

                       

Weighted-average common shares outstanding

    24,729       26,097       26,175  

Dilutive effect of stock options and restricted stock awards

    -       -       10  

Diluted

    24,729       26,097       26,185  

Income (loss) per common share:

                       

Basic

  $ (8.70 )   $ 2.39     $ 2.70  

Diluted

  $ (8.70 )   $ 2.39     $ 2.70  

  

Reclassifications

 

Certain reclassifications of previously reported information have been made to conform to the current year presentation.

 

New Accounting Pronouncements 

 

In May 2014, the Financial Accounting Standards Board, or FASB, issued Accounting Standards Update, or ASU, No. 2014-09, “Revenue from Contracts with Customers.” These amendments require an entity to recognize the amount of revenue to which it expects to be entitled for the transfer of promised goods or services to customers. The ASU will replace most existing revenue recognition guidance in U.S. GAAP when it becomes effective. The new standard was to become effective on January 1, 2017, but the issuance in August 2015 of ASU 2015-14 delayed the effective date until January 1, 2018. Early application is permitted only back to the original effective date. The standard permits the use of either the retrospective or cumulative effect transition method. We are evaluating the effect that ASUs 2014-09 and 2015-14 will have on our consolidated financial statements and related disclosures. We have not yet selected a transition method nor have we determined the effect of the standards on our ongoing financial reporting.

 

In April 2015, the FASB issued ASU 2015-03, “Interest – Imputation of Interest.” This ASU requires companies to present debt issuance costs related to a recognized debt liability in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. In August 2015, ASU 2015-15 clarified this standard to state that debt issuance costs of line of credit arrangements would not be required to be reclassified from other assets to liabilities. These ASUs are effective for fiscal years beginning after December 31, 2015 and early adoption is allowed. These standards will not have a material effect on our financial condition or results of operations.

 

In November 2015, the FASB issued ASU 2015-17, “Income Taxes.” Current accounting requires an entity to separate deferred income tax liabilities and assets into current and noncurrent amounts in a classified balance sheet. ASU 2015-17 requires that deferred tax liabilities and assets be classified as noncurrent in a classified balance sheet. The new standard was effective on January 1, 2016. This standard will not have a material effect on our financial condition or results of operations.

 

(2) IMPAIRMENT CHARGES

 

 Reduction in Value of Long-Lived Assets and Goodwill

 

Our tangible long-lived assets consist primarily of vessels and construction-in-progress. Our intangible asset is associated with customer relationships in the U.S. Gulf of Mexico acquired in our 2008 acquisition of Rigdon Marine Corporation and Rigdon Marine Holdings, LLC. Our goodwill relates to the 2001 acquisition of Sea Truck Holding AS and the 1998 acquisition of Brovig Supply AS. In assessing potential impairment related to our long-lived assets, the carrying values of the assets are compared with undiscounted expected future cash flows. If the carrying value of any long-lived asset is greater than the related undiscounted expected future cash flows, we measure impairment by comparing the fair value of the asset with its carrying value. At least annually, we assess whether goodwill is impaired based on certain qualitative factors. Management’s assumptions are an inherent part of our asset impairment evaluation, and the use of different assumptions could produce results that differ from those reported.

  

 
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Beginning in late 2014, the oil and gas industry experienced a significant decline in the price of oil causing an industry-wide downturn which continued into 2015. The oil price recovered to almost $60 per barrel in the second quarter but continued its decline throughout the remainder of 2015. This downturn impacted the operational plans for oil companies and consequently adversely affected the drilling and support service sector. We experienced a significant negative impact on day rates and utilization in 2015.

 

As of December 31, 2014, we performed a full assessment of goodwill that did not indicate impairment. We performed another assessment in the second quarter of 2015 that did not indicate impairment, but the margin of coverage, given our assumptions, had narrowed since December 31, 2014. In the second quarter of 2015, we also performed a Step 1 assessment of our long-lived assets, including the intangible asset, for impairment and concluded that no impairment was indicated. These assessments were performed as a result of the triggering events described in the preceding paragraph.

  

Industry conditions continued to deteriorate in the third quarter and we again performed full assessments. In the third quarter, we recorded in our consolidated statements of operations $152.1 million of impairment charges related to reduction in value of assets due to impairment. See discussions below detailing our impairment analyses and processes for each of our goodwill, long-lived assets, intangible asset and vessel components. The components of reduction in value of assets are as follows (in thousands):

 

Goodwill impairment

  $ 22,554  

Long-lived assets impairment

    115,489  

Intangible asset impairment

    13,695  

Vessel component impairment

    365  

Total reduction in value of assets

  $ 152,103  

  

We performed another assessment as of December 31, 2015 that did not identify any additional triggering events. We will continue to monitor the industry for triggering events that could indicate impairment in 2016.

 

Goodwill Impairment

 

Goodwill is tested for impairment in the third quarter each year or on an interim basis if events or circumstances indicate that the fair value of goodwill has decreased below its carrying value. We completed a qualitative analysis of goodwill in the third quarter of 2015 and determined that further testing was necessary. Our goodwill impairment evaluation indicated that the carrying value of the North Sea segment exceeded its fair value so that goodwill was potentially impaired. We then performed the second step of the goodwill impairment test, which involved calculating the implied fair value of our goodwill by allocating the fair value of the North Sea segment to all of the assets and liabilities (other than goodwill) and comparing it to the carrying amount of goodwill. To estimate the fair value of the reporting unit we used a 50% weighting of the discounted cash flow method and a 50% weighting of the public company guideline method in determining fair value of the North Sea reporting unit.

 

We determined that the implied fair value of our goodwill for the North Sea segment was less than its carrying value and recorded a $22.6 million impairment of the North Sea segment’s goodwill. As a result of this impariment, we no longer have any goodwill.

 

Long-Lived Asset Impairment

 

Long-lived assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is assessed by a comparison of the carrying amount of such assets to their fair value. Undiscounted cash flow estimates are based upon, among other things, historical results adjusted to reflect the best estimate of operating performance. If an asset group’s fair value is less than the carrying amount of that asset group, impairment losses are recorded in the amount by which the carrying amount of such assets exceeds the fair value. The estimates of fair value of our vessels and intangible asset were obtained from fair value appraisals performed at our request by third party appraisal firms.

 

At September 30, 2015, we recorded $129.2 million in expense in connection with the impairment of our long-lived assets in the U.S. Gulf of Mexico, which is a part of our Americas segment. The impairment consisted of $115.5 million related to our vessels and $13.7 million related to our intangible asset. As a result of this impairment, we no longer have any intangible asset. The impairment in value of long-lived assets in the U.S. Gulf of Mexico was primarily driven by the disproportionally higher decline in day rates and utilization in the U.S. Gulf of Mexico compared to the other areas in which we provide offshore supply vessel services. We will continue to monitor the industry and our asset groups for indications of impairment and will perform additional assessments as conditions and circumstances warrant.

  

 
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Vessel Component Impairment

 

We have certain vessel components in our North Sea region fixed asset base that were intended to be used in our new-build program. In the second quarter of 2014, we evaluated the use of these components and determined that they would not be used in our new-build fleet. We are actively pursuing a sale of the equipment, but there is a limited market. We adjusted the carrying value at June 30, 2014 to reflect the net realizable value. These assets are included in deferred costs and other assets on our balance sheet. The total charge to impairment expense related to these components at June 30, 2014 was $7.0 million. The adjustment value was based on an appraisal prepared by a third party appraisal firm. We obtained an updated appraisal at the end of each quarter since June 30, 2014 with no indications of material additional impairment until the third quarter of 2015. We charged an additional $0.4 million to impairment expense in the third quarter of 2015 based on the updated appraisal.

 

Assets Held For Sale

 

At December 31, 2014, we classified an additional North Sea vessel as an asset held for sale and determined that its carrying value was less than our estimate of the amount we would realize in a sale. As a result, we reduced the carrying value by $1.5 million which is included in our results of operations as impairment. The adjusted carrying value of this vessel is based on a purchase and sale agreement. In January 2015, we completed the sale of the asset at its carrying value.

 

(3) VESSEL ACQUISITIONS, DISPOSITIONS AND NEW-BUILD PROGRAM

 

In January 2013, we sold a vessel that was being held for sale that was not included in our fleet numbers. The net proceeds totaled $0.7 million and there was no gain or loss on the sale. In August 2013, we sold two vessels in our North Sea region for total proceeds of $10.8 million and in September 2013 we sold one vessel in our Americas region for $2.1 million. We recognized a combined gain on these 2013 sales of $6.0 million. In February 2014, we acquired for $30.9 million a vessel that we previously managed in the North Sea. Additionally, during 2014 we sold four older vessels, three of which were from our Southeast Asia region and one from our North Sea region, for combined proceeds of $32.3 million. The sale of these vessels, combined, resulted in a gain of $12.5 million.

 

We are currently in the latter stages of a 12 vessel new-build program that began in 2011. We began the program in the North Sea region where we contracted with three shipyards to build a total of six platform supply vessels, or PSVs. In late 2011, we exercised an option with one of the shipyards to build an additional PSV. The original estimated cost of these seven PSVs was $288.0 million. The first four of these vessels were delivered in the third quarter of 2013, a fifth vessel was delivered in the fourth quarter of 2013 and the sixth and seventh vessels were delivered in the first quarter of 2014.

 

In 2012, we entered into separate agreements with two U.S. shipyards, Thoma-Sea and BAE Systems, in each case to build two U.S. flagged PSVs for the U.S. Gulf of Mexico region. The original estimated total cost of these four PSVs was approximately $168.0 million. The Thoma-Sea vessels have been delivered. The first Thoma-Sea vessel was delivered in the second quarter of 2014 and the second Thoma-Sea vessel was delivered in January 2015. Neither of the BAE Systems vessels has been delivered. In addition, both vessels are significantly past the delivery date specified in the original contracts. As of the date of this report, we anticipate delivery of these remaining vessels in the third and fourth quarters of 2016, respectively, although additional delays may occur.  Given the significant delays and other technical problems associated with the construction and delivery of these vessels, to preserve our rights, we have initiated arbitration proceedings with BAE Systems as provided for under our contracts.

 

Also in 2012, we placed $52.4 million in escrow related to the two Thoma-Sea new-builds described above and in the table below. Progress payments were drawn from escrow as they became due. There was $3.7 million remaining in escrow, which was presented in long-term assets in the balance sheet as of December 31, 2014, and which was released to Thoma-Sea upon the delivery of the second vessel in January 2015. Funds in the escrow account were invested in U.S. government securities.

 

In April 2014, we approved the construction of an additional North Sea PSV by Simek, one of the three shipyards in the original program discussed above, with an estimated total cost of 359.0 million NOK (or approximately $40.9 million at December 31, 2015, but which was equivalent to approximately $60.0 million based on exchange rates in effect at the contract date) and an initial expected delivery date in the first quarter of 2016. In the fourth quarter of 2015, we amended our contract with Simek to delay delivery of the vessel until January 2017. Concurrently, we agreed to pay installments in the aggregate of 92.2 million NOK (or approximately $10.4 million at December 31, 2015) through May 2016 and a final installment of 195.0 million NOK (or approximately $22.1 million at December 31, 2015) in January 2017.

 

 
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The following tables illustrate the details of the vessels under construction, the vessels added or acquired and vessels disposed of:

 

Vessels Under Construction as of February 29, 2016

 

Construction Yard

Region

Type(1)

Expected Delivery

 

Length

(feet)

   

BHP(2)

   

DWT(3)

   

Expected

Cost

 
                                 

(millions)

 

BAE Systems

Americas

LgPSV

Q3 2016

    286       10,960       5,300     $ 48.0  

BAE Systems

Americas

LgPSV

Q4 2016

    286       10,960       5,300     $ 48.0  

Simek

N. Sea

LgPSV

Q1 2017

    304       11,935       4,700     $ 60.0  

 

Note: Final cost may differ due to foreign currency fluctuations.

 

Vessel Additions Since December 31, 2014

Vessel

Region

Type(1)

Year

Built

 

Length

(feet)

   

BHP(2)

   

DWT(3)

 

Month

Delivered

                                 

Regulus

Americas

LgPSV

2015

    272       9,849       3,580  

Jan-15

  

Vessels Disposed of Since December 31, 2014

Vessel

Region

Type(1)

Year

Built

 

Length

(feet)

   

BHP(2)

   

DWT(3)

 

Month

Disposed

                                 

North Truck

N. Sea

LgPSV

1983

    265       6,120       3,370  

Jan-15

Highland Trader

N. Sea

LgPSV

1996

    220       5,450       3,115  

Jul-15

Highland Star

N. Sea

LgPSV

1991

    268       6,600       3,075  

Nov-15

 

(1) LgPSV - Large Platform Supply Vessel

(2)BHP - Brake Horsepower

(3)DWT - Deadweight Tons

  

(4) GOODWILL AND INTANGIBLES

 

Changes to goodwill are as follows:

 

   

2015

   

2014

   

2013

 
   

(In thousands)

 

Balance, January 1,

  $ 25,010     $ 30,676     $ 33,438  

Impact of foreign currency translation and adjustment

    (2,456 )     (5,666 )     (2,762

Impairment

    (22,554 )      -        -  

Balance, December 31,

  $ -     $ 25,010     $ 30,676  

 

We recorded impairment equal to 100% of the balance in goodwill as of September 30, 2015. See Note 2.

 

Intangible assets were recorded at cost and are amortized on a straight-line basis over the years expected to be benefited, estimated to be 12 years. Amortization expense related to intangible assets was $2.1 million for the year ended December 31, 2015 and $2.9 million for each of the years ended December 31, 2014 and 2013. We recorded an impairment equal to 100% of the balance in intangible assets as of September 30, 2015. See Note 2.

 

 
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(5) LONG-TERM DEBT

 

Our long-term debt at December 31, 2015 and 2014 consisted of the following:

 

   

December 31,

2015

   

December 31,

2014

 
   

(In thousands)

 

Senior Notes Due 2022

  $ 499,000     $ 500,000  

Multicurrency Facility Agreement

    -       44,000  

Norwegian Facility Agreement

    -       -  
      499,000       544,000  

Debt Premium

    607       732  

Total

  $ 499,607     $ 544,732  

  

The following is a summary of scheduled debt maturities by year:

 

Year

 

Debt Maturity

 
   

(In thousands)

 

2016

    -  

2017

    -  

2018

    -  

2019

       

2020

    -  

Thereafter

    499,000  

Total

  $ 499,000  

 

Senior Notes Due 2022

 

On March 12, 2012, we issued $300.0 million aggregate principal amount of 6.375% senior notes due 2022. On December 5, 2012, we issued an additional $200.0 million of senior notes with substantially the same terms as the previous $300.0 million issuance, which we refer to collectively as the Senior Notes. The Senior Notes pay interest semi-annually on March 15 and September 15. Prior to March 15, 2017, we may redeem some or all of the Senior Notes for cash at a redemption price equal to 100% of their principal amount plus an applicable make-whole premium and accrued and unpaid interest to the redemption date. The make-whole premium is based on U.S. Treasuries plus 50 basis points. On and after March 15, 2017, we may redeem some or all of the Senior Notes at the redemption prices (expressed as percentages of principal amount) equal to 103.188% for the twelve-month period beginning March 15, 2017, 102.125% for the twelve-month period beginning March 15, 2018, 101.063% for the twelve-month period beginning March 15, 2019 and 100.000% beginning March 15, 2020, plus accrued and unpaid interest to the redemption date. In conjunction with the Senior Notes offering, we incurred $12.7 million in debt issuance costs which are included in our balance sheet under deferred costs and other assets and are being amortized into interest cost over the life of the Senior Notes using the effective interest method. On December 28, 2015, we repurchased in the open market $1.0 million face value of Senior Notes leaving $499.0 million aggregate principal amount of Senior Notes outstanding at December 31, 2015. Depending on market conditions, we may, from time to time, purchase our Senior Notes in the open market or otherwise.

 

At December 31, 2015, the fair value of the Senior Notes, based on quoted market prices, was approximately $254.5 million compared to a carrying amount of $499.6 million.

 

Multicurrency Facility Agreement

 

We are party to a senior secured, revolving multicurrency credit facility, or the Multicurrency Facility Agreement, among GulfMark Offshore, Inc., as guarantor, one of our indirect wholly-owned subsidiaries, as the Borrower, a group of financial institutions as the Lenders and the Royal Bank of Scotland PLC as agent for the Lenders. The Multicurrency Facility Agreement has a scheduled maturity date of September 26, 2019 and, as amended, commits the Lenders to provide revolving loans up to $100.0 million at any one time outstanding, subject to certain terms and conditions, and contains sublimits of $25.0 million for swingline loans and $5.0 million for the issuance of letters of credit. Revolving loans and swingline loans under the Multicurrency Facility Agreement accrue interest at LIBOR, plus an applicable margin which may range from 2.75% to 4.00%. The applicable margin is based on our most recent capitalization ratio. The fee for unused commitments is 1.25% per annum. We are subject to certain financial and other covenants under the Multicurrency Facility Agreement, including covenants and restrictions requiring, among other things:

 

 

maintenance of a Capitalization Ratio, as defined, not to exceed 60% at the end of each fiscal quarter;

  

 
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maintenance of a minimum Consolidated Interest Coverage Ratio, as defined, for any period of four consecutive fiscal quarters, of 1.5 to 1.0 beginning at the end of our third fiscal quarter of 2017 and increasing periodically thereafter;

 

maintenance of a minimum Collateral to Debt Ratio, as defined, of 3.0 to 1.0 at the end of each fiscal quarter;

 

maintenance of a minimum Collateral to Commitments Ratio, as defined, of 2.0 to 1.0 at the end of each fiscal quarter;

 

maintenance of minimum Consolidated Adjusted EBITDA, as defined, as of the end of each fiscal quarter, of $5.0 million for the fourth quarter of 2015, $10.0 million for the six months ending March 31, 2016, $15.0 million for the nine months ending June 30, 2016 and $20.0 million for the four-quarter period ending September 30, 2016 and thereafter;

 

minimum liquidity (as determined under the Multicurrency Facility Agreement) at the end of each fiscal quarter of $35.0 million;

 

a mandatory prepayment if loans are outstanding and, on a consolidated basis, we have Cash, as defined, at the end of a fiscal quarter in excess of $35.0 million;

 

a prohibition on loans under the Multicurrency Facility Agreement for purposes of funding payments on our PSV under construction by Simek;

 

restrictions on the amount of cash we may invest for certain capital expenditures, acquisitions, joint ventures, dividends and share repurchases until December 31, 2017;

 

restrictions, subject to exceptions, on certain acquisitions, mergers, consolidations, joint ventures, changes of business, changes of ownership, indebtedness and asset sales; and

 

restrictions, subject to exceptions, on liens on our assets.

 

As of December 31, 2015, we were in compliance with all of the covenants in the Multicurrency Facility Agreement.

 

The Multicurrency Facility Agreement provides for customary events of default and contains cross-default provisions with all other debt instruments for indebtedness of $20.0 million or more in the aggregate (or its equivalent in other currencies). If an event of default occurs and continues, on the terms and subject to the conditions set forth in the Multicurrency Facility Agreement, the lenders may declare all amounts outstanding and accrued and all unpaid interest immediately due and payable, terminate the commitments under the Multicurrency Facility Agreement, and direct the Security Agent, as defined, to exercise any and all of its rights, remedies, powers or discretions under the Finance Documents, as defined.

 

On September 26, 2014, we entered into the Multicurrency Facility Agreement, which originally committed the Lenders to provide revolving loans up to $300.0 million at any one time outstanding, subject to certain terms and conditions.

 

In February 2015, we entered into an amendment to the Multicurrency Facility Agreement that reduced the requirement under the interest coverage ratio covenant. In return for the reduction, the Lenders imposed certain financial restrictions, including limiting our ability make certain payments for dividends, acquisitions or share repurchases. In connection with the amendment, we paid an additional $1.0 million in fees and our unused commitment fee rate increased from 37.5 basis points to 50.0 basis points.

 

In July 2015, we entered into another amendment to the Multicurrency Facility Agreement that, among other changes:

 

 

reduced the interest coverage ratio requirements applicable to certain periods;

 

changed the required collateral to Lenders’ commitments ratio for certain periods;

 

added a new mechanism for curing defaults on financial covenants; and

 

removed a requirement that we take delivery of certain vessels.

 

In return for the amendment, the Lenders required that we agree to certain changes, including

 

 

increasing the commitment fee during certain periods to 75 basis points;

 

reducing total commitments under the facility from $300.0 million to $200.0 million;

 

increasing the rate of interest accruing under the facility to LIBOR plus a margin, which is currently 2.75%;

 

adding a new covenant that liquidity not be less than $50.0 million;

 

reducing the amounts of business acquisitions, collateral dispositions, capital expenditures, joint ventures, distributions to equity holders and indebtedness permitted during certain periods; and

 

subjecting certain of our affiliated parties that are not obligors to the Multicurrency Facility Agreement’s limitations on business acquisitions, capital expenditures and joint ventures during certain periods.

 

In connection with this amendment, we paid an additional $0.9 million in fees, which is being capitalized and amortized over the remaining term of the Multicurrency Facility Agreement. In addition, since we reduced our overall borrowing capacity under the Multicurrency Facility Agreement, we were required to expense a portion of the debt issuance costs that were being deferred on our consolidated balance sheet. We charged $1.8 million to interest expense in the third quarter of 2015 in connection with this amendment.

 

 
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In December 2015, we entered into another amendment to the Multicurrency Facility Agreement that, among other changes:

 

 

removed interest coverage ratio tests for certain periods;

 

increased the permissible capitalization ratio;

 

redefined the Consolidated Adjusted EBITDA calculation to add back certain severance and other costs related to any discontinued operations or vessel redeployment;

 

reduced the threshold in the minimum liquidity covenant from $50.0 million to $35.0 million; and

 

added provisions permitting stacking of vessels if needed.

 

In return for the amendment, the Lenders required that we agree to certain changes, including:

 

 

increasing the pricing for any loans;

 

increasing the commitment fee during certain periods;

 

reducing commitments from $200.0 million to $100.0 million;

 

requiring prepayment of loans if quarter end cash on hand exceeds certain thresholds;

 

increasing collateral to debt ratio and collateral to commitment ratio requirements;

 

providing for additional reporting of financial and other information, including more frequent collateral appraisals;

 

limiting unscheduled capital expenditures or investments; and

 

precluding use of borrowings under the Multicurrency Facility Agreement to acquire the Norwegian Arctic class vessel currently under construction.

 

In connection with this amendment, we paid an additional $1.0 million in fees, which is being capitalized and amortized over the remaining term of the Multicurrency Facility Agreement. In addition, since we reduced our overall borrowing capacity under the Multicurrency Facility Agreement, we were required to expense a portion of the debt issuance costs that were being deferred on our consolidated balance sheet. We charged $2.1 million to interest expense in the fourth quarter of 2015 in connection with this amendment.

 

We have unamortized fees paid to the arrangers, the agent and the security trustee totaling $3.1 million at December 31, 2015, which fees are being amortized into interest cost on a straight-line basis over the life of the Multicurrency Facility Agreement.

 

The Multicurrency Facility Agreement is secured by 24 vessels of the Borrower. The collateral that secures the loans under the Multicurrency Facility Agreement may also secure all of the Borrower’s obligations under any hedging agreements between the Borrower and any Lender or other hedge counterparty to the Multicurrency Facility Agreement.

 

GulfMark Offshore, Inc. unconditionally guaranteed all existing and future indebtedness and liabilities of the Borrower arising under the Multicurrency Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Borrower arising under any hedging arrangements. At December 31 2015, there were no amounts borrowed and outstanding under the Multicurrency Facility Agreement and we were in compliance with all the covenants under the Multicurrency Facility Agreement. The unused borrowing capacity under the Multicurrency Facility Agreement at December 31 2015, after giving effect to standby letters of credit, was $98.2 million.

 

If we need to supplement our cash flow or results of operations to continue to comply with the financial covenants under our Multicurrency Facility Agreement, we may stack additional vessels, reduce the onshore and offshore workforce, or adjust the capital structure through open market purchases of debt at fair value or, if necessary, seek amendments to our Multicurrency Facility Agreement depending on facts and circumstances at the time. There can be no assurance, however, that we would be able to negotiate acceptable terms for any such amendment.

 

 
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Norwegian Facility Agreement

 

We are also party to a senior secured revolving credit facility, or the Norwegian Facility Agreement, among GulfMark Offshore, Inc., as guarantor, one of our indirect wholly-owned subsidiaries, as the borrower, which we refer to as the Norwegian Borrower, and a DNB Bank ASA, a Norwegian bank, as lead lender, which we refer to as the Norwegian Lender. The Norwegian Facility Agreement has a scheduled maturity date of September 30, 2019 and commits the Norwegian Lender to provide loans up to an aggregate principal amount of 600.0 million NOK (or approximately $67.9 million at December 31, 2015) at any one time outstanding, subject to certain terms and conditions. Loans under the Norwegian Facility Agreement accrue interest at the Norwegian InterBank Offered Rate, plus an applicable margin, which may range from 2.50% to 4.00%, depending on the interest coverage ratio. The fee for unused commitments is 1.25% per annum. We are subject to certain financial and other covenants under the Norwegian Facility Agreement, including covenants and restrictions requiring, among other things:

 

 

maintenance of a Capitalization Ratio, as defined, not to exceed 60% at the end of each fiscal quarter;

 

maintenance of a minimum ratio of Adjusted EBITDA to Interest Expense, each as defined, of 1.50 to 1.00 beginning at the end of our third fiscal quarter of 2017 and increasing periodically thereafter;

 

maintenance of minimum consolidated Adjusted EBITDA, as defined, as of the end of each fiscal quarter, of $5.0 million for the fourth quarter of 2015, $10.0 million for the six months ending March 31, 2016, $15.0 million for the nine months ending June 30, 2016 and $20.0 million for the four-quarter period ending September 30, 2016 and thereafter;

 

minimum liquidity (as determined under the Norwegian Facility Agreement) at the end of each fiscal quarter of $35.0 million;

 

mandatory prepayments and/or reductions in total commitments if our PSV under construction by Simek is delivered after March 31, 2017, or if the market value of the vessels securing the Norwegian Facility Agreement (as determined under the Norwegian Facility Agreement) is less than 300% of outstanding unpaid loans or less than 200% of total commitments, in each case unless certain additional security is provided;

 

a mandatory prepayment if we have amounts drawn under the Multicurrency Facility Agreement and/or the Norwegian Facility Agreement and, on a consolidated basis, we have Cash, as defined, at the end of a fiscal quarter in excess of $35.0 million;

 

restrictions, subject to exceptions, on certain mergers, consolidations, divestitures, reconstructions and changes of business;

 

restrictions, subject to exceptions, on liens on certain of our assets; and

 

that we remain listed on the New York Stock Exchange or another recognized stock exchange.

 

As of December 31, 2015, we were in compliance with all of the covenants in the Norwegian Facility Agreement.

 

The Norwegian Facility Agreement provides for customary events of default and contains cross-default provisions with all other debt instruments for indebtedness of $20.0 million or more in the aggregate (or its equivalent in other currencies). If an event of default occurs and is continuing, on the terms and subject to the conditions set forth in the Norwegian Facility Agreement, the Norwegian Lender may declare all amounts outstanding and accrued and all unpaid interest immediately due and payable, terminate the commitments under the Norwegian Facility Agreement, enforce all rights under any security agreement, and exercise any rights and remedies under the Finance Documents, as defined. 

 

We entered into the Norwegian Facility Agreement on December 27, 2012, and on June 20, 2013, we entered into an amendment to adjust certain covenants and to allow us to begin to draw on available credit. In connection with this amendment, we paid fees to the Norwegian Lender totaling $1.3 million, which are being amortized into interest cost over the life of the Norwegian Facility Agreement using the effective interest method. On October 23, 2014, we entered into another amendment to the Norwegian Facility Agreement which extended the scheduled maturity date from September 30, 2017 to September 30, 2019 and revised certain financial covenants.

 

In February 2015, we entered into an amendment to the Norwegian Facility Agreement that reduced the requirement under the covenant governing the interest coverage ratio. In return for the reduction, the lenders required that we agree to certain financial restrictions, including limiting our ability make certain payments for dividends, acquisitions or share repurchases. We paid an additional $0.2 million in fees in connection with this amendment.

 

In July 2015, we entered into an amendment to the Norwegian Facility Agreement that, among other changes:

 

 

modified the interest coverage ratio requirements applicable to certain periods to conform to the interest coverage ratio requirements applicable to the same periods as set forth in the Multicurrency Facility Agreement, as amended and described above;

 

added a new covenant that liquidity not be less than $50.0 million; and

 

increased the commitment fee from 50.0 basis points to 65.0 basis points per annum.

 

In connection with this amendment, we paid an additional $0.1 million in fees.

 

In January 2016, we entered into an amendment to the Norwegian Facility Agreement that, among other things:

 

 

provided for liens to be granted by the Norwegian Borrower on four vessels as additional collateral;

 

increased the rate of interest;

 

replaced EBITDA measurements with an Adjusted EBITDA measurement that, among other things, includes addbacks for certain costs associated with redeployment of vessels in connection with discontinued operations and certain severance costs;

 

extended the period for delivery of our PSV under construction by Simek until March 31, 2017 without triggering a mandatory prepayment or reduction in commitments;

 

 
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added mandatory prepayment requirements in the event that the market value of the vessels securing the Norwegian Facility Agreement, as determined in accordance with its terms, is less than 300% of outstanding unpaid loans or less than 200% of total commitments, in each case unless certain additional security is provided;

 

added a mandatory prepayment requirement in the event that we, on a consolidated basis, have excess cash, as defined, at the end of a fiscal quarter;

 

provided for certain accelerated or more frequent financial reporting;

 

deferred the applicability of the interest coverage ratio requirement until the third quarter of 2017;

 

increased the permitted Capitalization Ratio, as defined, to 60%;

 

reduced the minimum liquidity requirement from $50 million to $35 million;

 

added a new minimum quarterly Adjusted EBITDA requirement;

 

increased the unused commitment fee rate to 1.25% per annum;

 

eliminated the covenant requiring maintenance of a minimum market value of the vessels securing the Norwegian Facility Agreement; and

 

expressly permitted us to stack or lay up vessels securing the Norwegian Facility Agreement.

 

The Norwegian Facility Agreement is secured by eight vessels of the Norwegian Borrower and our additional North Sea PSV under construction by Simek. The collateral that secures the loans under the Norwegian Facility Agreement may also secure all of the Norwegian Borrower’s obligations under any hedging agreements between the Norwegian Borrower and the Norwegian Lender or other hedge counterparty to the Norwegian Facility Agreement.

 

GulfMark Offshore, Inc. unconditionally guaranteed all existing and future indebtedness and liabilities of the Norwegian Borrower arising under the Norwegian Facility Agreement and other related loan documents. Such guarantee may also cover obligations of the Norwegian Borrower arising under any hedging arrangements described above. At December 31 2015, there were no amounts borrowed and outstanding under the Norwegian Facility Agreement and we were in compliance with all the covenants under the Norwegian Facility Agreement.

 

If we need to supplement our cash flow or results of operations to continue to comply with the financial covenants under our Norwegian Facility Agreement, we may stack additional vessels, reduce the onshore and offshore workforce, or adjust the capital structure through open market purchases of debt at fair value or, if necessary, seek amendments to our Norwegian Facility Agreement depending on facts and circumstances at the time. There can be no assurance, however, that we would be able to negotiate acceptable terms for any such amendment.

 

(6) INCOME TAXES

 

The majority of our non-U.S. based operations are subject to foreign tax systems that provide significant incentives to qualified shipping activities. Our U.K. and Norway based vessels are taxed under “tonnage tax” regimes. Our qualified Singapore based vessels are exempt from Singapore taxation through December 2017 with extensions available in certain circumstances beyond 2017. The qualified Singapore vessels are also subject to specific qualification requirements which if not met could jeopardize our qualified status in Singapore. The tonnage tax regimes provide for a tax based on the net tonnage weight of a qualified vessel. These beneficial foreign tax structures continued to result in our earnings incurring significantly lower taxes than those that would apply under the U.S. statutory tax rates or if we were not a qualified shipping company in those foreign jurisdictions.

 

In 2010, Norway made significant changes to its tonnage tax system requiring us to pay tax on our pre-2007 tonnage tax profits. While the tax effect of this change was recorded in 2010, the taxes due were payable in three equal annual installments. We made the final payment of $1.8 million in 2013.

 

Should our operational structure change or should the laws that created these shipping tax regimes change, we could be required to provide for taxes at rates much higher than those currently reflected in our financial statements. Additionally, if our pre-tax earnings in higher tax jurisdictions increase, there could be a significant increase in our annual effective tax rate. Any such increase could cause volatility in the comparisons of our effective tax rate from period to period.

 

U.S. foreign tax credits can be carried forward for ten years. We have $17.8 million of such foreign tax credit carryforwards that begin to expire in 2016. As of December 31, 2015, we had $11.6 million of valuation allowance for these credits. We have considered estimated future taxable income in the relevant tax jurisdictions to utilize these tax credits and have considered what we believe to be ongoing prudent and feasible tax planning strategies in assessing the need for the valuation allowance. This information is based on estimates and assumptions including projected taxable income. If these estimates and related assumptions change in the future, or if we determine that we would not be able to realize other deferred tax assets in the future, an adjustment to the valuation allowance would be recorded in the period such determination was made.

 

For the year ended December 31, 2015, we increased by $2.8 million the U.S. federal income tax provision for the amount of employee stock-based compensation less than book cost. This increase reduces a long term deferred tax asset for the decrease to our federal income tax net operating loss. In the future, we are able to recognize this tax benefit only to the extent that it reduces our income taxes payable as a current year deduction or through utilization of prior years' net operating losses.

  

 
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Income (loss) before income taxes attributable to domestic and foreign operations was (in thousands):

 

   

Year Ended December 31,

 
   

2015

   

2014

   

2013

 

U.S.

  $ (198,175 )   $ 1,189     $ 2,581  

Foreign

    (22,693 )     70,456       72,987  
    $ (220,868 )   $ 71,645     $ 75,568  

   

The components of our tax provision (benefit) attributable to income before income taxes are as follows for the year ended December 31, (in thousands):

 

   

2015

   

2014

   

2013

 
   

Current

   

Deferred

   

Other (a)

   

Total

   

Current

   

Deferred

   

Other (a)

   

Total

   

Current

   

Deferred

   

Other (a)

   

Total

 

U.S & State

  $ (69 )   $ (3,270 )   $ 39     $ (3,300 )   $ 464     $ 80     $ 1,627     $ 2,171     $ 65     $ (709 )   $ 304     $ (340 )

Foreign

    1,130       (553 )     (2,910 )     (2,333 )     5,544       (146 )     1,701       7,099       3,445       730       1,127       5,302  
    $ 1,061     $ (3,823 )   $ (2,871 )   $ (5,633 )   $ 6,008     $ (66 )   $ 3,328     $ 9,270     $ 3,510     $ 21     $ 1,431     $ 4,962  

 

(a)     Includes income tax effects determined under a more likely than not, or greater than 50% probability, threshold and the book deferred tax effect related to intercompany asset sales.

 

The mix of our operations within various taxing jurisdictions affects our overall tax provision. The difference between the provision at the statutory U.S. federal tax rate and the tax provision attributable to income before income taxes in the accompanying consolidated statements of operations is as follows:

  

   

2015

   

2014

   

2013

 

U.S. federal statutory income tax rate

    (35.0

)%

    35.0

%

    35.0

%

Effect of foreign operations

    2.5       (25.2 )     (24.8 )

US state income taxes net of Federal benefit

    (1.7 )     1.4       1.3  

Foreign earnings repatriation

    34.4       -       -  

U.S. foreign tax credit

    (7.8 )     -       -  

Valuation allowance

    5.1       0.5       (1.7 )

Capital restructuring of foreign operations

    -       -       (6.1 )

Other

    (0.1 )     1.2       2.9  

Total

    (2.6

)%

    12.9

%

    6.6

%

 

 
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Deferred income taxes reflect the impact of temporary differences between the amount of assets and liabilities for financial reporting purposes and such amounts as measured by tax laws and regulations. The components of the net deferred tax assets and liabilities at December 31, 2015 and 2014 were as follows:

 

   

December 31,

 
   

2015

   

2014

 
   

(In thousands)

 

Deferred tax assets

               

Net operating loss carryforwards

  $ 49,900     $ 34,107  

Items currently not deductible for tax purposes

    20,753       27,732  

Foreign and other tax credit carryforwards

    27,450       10,099  
      98,103       71,938  

Less valuation allowance

    (23,742 )     (11,477 )

Net deferred tax assets

  $ 74,361     $ 60,461  
                 

Deferred tax liabilities

               

Depreciation

  $ (121,525 )   $ (150,543 )

Other

    (50,889 )     (12,967 )

Total deferred tax liabilities

  $ (172,414 )   $ (163,510 )

Net deferred tax liability

  $ (98,053 )   $ (103,049 )

  

The change in the total valuation allowance for the year ended December 31, 2015 from December 31, 2014 was an increase of $12.3 million. As of December 31, 2015, we had net operating loss carryforwards, or NOLs, for income tax purposes totaling $132.6 million in the U.S., $4.1 million in Mexico, $0.4 million in the U.K., $17.4 million in Brazil, and $4.2 million in Norway that are, subject to certain limitations, available to offset future taxable income. The U.S. NOLs, which we expect to fully utilize, will begin to expire beginning in 2023. It is more likely than not that the Norway NOLs and the Brazilian NOLs will not be utilized and a full valuation allowance has been established for such NOLs. Based on future expected U.S. taxable income, as of December 31, 2015, we have recorded $11.6 million of valuation allowance against U.S. foreign tax credits.

  

Deferred income tax assets and liabilities based on classification as current, or short-term, and long-term are included in our balance sheet as follows:

 

             
   

2015

   

2014

 
   

(In thousands)

 
                 

Prepaid expenses and other current assets

  $ 1,386     $ 1,297  

Total tax assets

    1,386       1,297  
                 
                 

Deferred tax liabilities

    99,439       104,346  

Total tax liabilities

  $ 99,439     $ 104,346  

  

During 2015, we determined to repatriate all future foreign earnings and $200.0 million of prior earnings of certain of our non-U.S. subsidiaries, thereby reducing our total permanently reinvested earnings. The change in our foreign repatriation strategy resulted in a non-cash tax charge in 2015 of approximately $70.0 million. We have not provided for U.S. deferred taxes on the remaining permanently reinvested earnings of approximately $850.0 million at December 31, 2015. If those earnings were repatriated, the incremental U.S. tax would be approximately 35% based on current tax law. In addition, as of December 31, 2015, we had approximately $21.4 million of cash held by our foreign subsidiaries which would be subject to U.S. tax upon repatriation.

 

Based on a more likely than not, or greater than 50% probability, recognition threshold and criteria for measurement of a tax position taken or expected to be taken in a tax return, we evaluate and record in certain circumstances an income tax liability for uncertain income tax positions. Numerous factors contribute to our evaluation and estimation of our tax positions and related tax liabilities and/or benefits, which may be adjusted periodically and may ultimately be resolved differently than we anticipate. We also consider existing accounting guidance on de-recognition, measurement, classification, interest and penalties, accounting in interim periods, disclosure and transition. Accordingly, we continue to recognize income tax related penalties and interest in our provision for income taxes and, to the extent applicable, in the corresponding balance sheet presentations for accrued income tax assets and liabilities, including any amounts for uncertain tax positions included in other income taxes payable in the consolidated balance sheets and which total $24.7 million at December 31, 2015, $24.7 million at December 31, 2014 and $23.7 million at December 31, 2013. In addition, the deferred tax asset was reduced by a $3.3 million unrecognized tax benefit for an uncertain tax position.

 

 
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A reconciliation of the beginning and ending balances of the total amounts of gross unrecognized tax benefits is as follows:

  

   

2015

   

2014

   

2013

 
    (in thousands)  
                         

Unrecognized tax benefits balance at January 1,

  $ 10,659     $ 10,352     $ 10,556  

Gross increases for tax positions taken in prior years

    346       375       319  

Gross decreases for tax positions taken in prior years

    (89 )     (68 )     (523 )

Other

    (17 )     -       -  

Unrecognized tax benefits balance at December 31,

  $ 10,899     $ 10,659     $ 10,352  

 

We accrue interest and penalties related to unrecognized tax benefits in our provision for income taxes. At December 31, 2015, we had accrued interest and penalties related to unrecognized tax benefits of $13.8 million. The amount of interest and penalties recognized in our tax provision for the year ended December 31, 2015 was $1.1 million. The unrecognized tax benefits if recognized would affect the effective tax rate.

 

As of December 31, 2015, we may be subject to examination in the U. S. for years after 2002 and in seven major foreign tax jurisdictions with open years from 2002 to 2014.

 

(7) COMMITMENTS AND CONTINGENCIES

 

At December 31, 2015, we had long-term operating leases for office space, automobiles, temporary residences, and office equipment. Aggregate operating lease expense for the years ended December 31, 2015, 2014 and 2013 was $2.8 million, $3.0 million, and $2.8 million, respectively. Future minimum rental commitments under these leases are as follows (in thousands):

 

Year

 

Minimum Rental

Commitments

 

2016

  $ 2,023  

2017

    1,638  

2018

    1,403  

2019

    1,316  

2020

    1,293  

Thereafter

    2,639  

Total

  $ 10,312  

 

The Highland Rover is subject to a purchase option on the part of the charterer, pursuant to terms of an amendment to the original charter which was executed in late 2007 and amended in 2008. The charterer may purchase the vessel based on a stipulated formula on October 1, 2016, provided 120 days’ notice has been given by the charterer.

 

We execute letters of credit, performance bonds and other guarantees in the normal course of business that ensure our performance or payments to third parties. The aggregate notional value of these instruments was $1.8 million at December 31, 2015, and we had no such instruments at December 31, 2014. In the past, no significant claims have been made against these financial instruments. We believe the likelihood of demand for payment under these instruments is remote and expect no material cash outlays to occur from these instruments.

  

We have contingent liabilities and future claims for which we have made estimates of the amount of the eventual cost to liquidate these liabilities or claims. These liabilities and claims may involve threatened or actual litigation where damages have not been specifically quantified but we have made an assessment of our exposure and recorded a provision in our accounts for the expected loss. We intend to defend these matters vigorously; however, litigation is inherently unpredictable, and the ultimate outcome or effect of such lawsuits and actions cannot be predicted with certainty. As a result, there can be no assurance as to the ultimate outcome of these lawsuits. Any claims against us, whether meritorious or not, could cause us to incur costs and expenses, require significant amounts of management time and result in the diversion of significant operations resources. Other claims or liabilities, including those related to taxes in foreign jurisdictions, may be estimated based on our experience in these matters and, where appropriate, the advice of outside counsel or other outside experts. Upon the ultimate resolution of the uncertainties surrounding our estimates of contingent liabilities and future claims, our future reported financial results will be impacted by the difference, if any, between our estimates and the actual amounts paid to settle the liabilities. In addition to estimates related to litigation and tax liabilities, other examples of liabilities requiring estimates of future exposure include contingencies arising out of acquisitions and divestitures. Our contingent liabilities are based on the most recent information available to us regarding the nature of the exposure. Such exposures may change from period to period based upon updated relevant facts and circumstances, which can cause the estimates to change. In the recent past, our estimates for contingent liabilities have been sufficient to cover the actual amount of our exposure. We do not believe that the outcome of these matters will have a material adverse effect on our business, financial condition, or results of operations.

 

 
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(8)

EQUITY INCENTIVE PLANS

 

Stock Options, Restricted Stock and Stock Option Plans

 

In June 2010, the stockholders approved the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan, or 2010 plan. A total of 1,000,000 shares of common stock were reserved for issuance of stock options, stock appreciation rights, restricted stock, stock units and performance cash awards under this plan. During the restricted period, the recipient has the right to vote on the restricted shares and receive dividends on the unvested restricted shares. Dividends are accrued on these unvested restricted shares and ultimately paid only if the awards vest.

 

In June 2011, the stockholders approved the GulfMark Offshore, Inc. 2011 Non-Employee Director Plan, or 2011 Director Plan, that replaced our 1997 Incentive Equity Plan. The 2011 Director Plan replaced the GulfMark Offshore, Inc. 2005 Non-Employee Director Plan. The terms of our 2011 Director Plan provide that each non-employee director will receive an annual grant of Class A common stock awards. The non-employee director may also be granted an annual stock option to purchase up to 6,000 shares of Class A common stock. The exercise price of options granted under the 2011 Director Plan is fixed at the fair market value of the Class A common stock on the date of grant. The maximum number of shares authorized under the 2011 Director Plan is 150,000.

 

In June 2014, the stockholders approved the GulfMark Offshore, Inc. 2014 Omnibus Equity Incentive Plan, or 2014 plan. The 2014 plan replaced the 2010 plan. Under the 2014 plan a total of 1,000,000 shares of Class A common stock were reserved for issuance of stock options, stock appreciation rights, restricted stock, stock units and performance cash awards under this plan. During the restricted period, the recipient has the right to vote on the restricted shares and receive dividends on the unvested restricted shares. Dividends are accrued on these unvested restricted shares and ultimately paid only if the awards vest.

 

Restricted stock is subject to forfeiture restrictions and cannot be sold, transferred, or disposed of during the restriction period. The holders of restricted stock have the same rights as any stockholder with respect to such shares, including the right to vote and to receive dividends, except that any dividends attributable to restricted stock are accumulated and paid when the underlying stock vests. Restricted stock vests over three years.

 

A summary of the unvested restricted stock awarded pursuant to our incentive equity plans as of December 31, 2015 and changes during 2015 are presented below:

 

   

Shares

   

Weighted

Average

Grant Date

Fair Value

 

Nonvested at December 31, 2014

    291,508     $ 43.35  

Granted

    564,205       13.09  

Vested

    (252,615 )     31.99  

Forfieted

    (56,574 )     19.06  

Nonvested at December 31, 2015

    546,524       27.05  

 

   

2015

   

2014

   

2013

 

Weighted average grant date fair value of restricted stock awards granted

  $ 13.09     $ 44.49     $ 41.64  

Fair value of restricted stock vested (in millions)

  $ 8.1     $ 5.9     $ 9.0  

 

Stock options granted to purchase our shares have an exercise price equal to, or greater than, the fair market value of our Class A common stock on the date of grant. These stock options vest over three years from the date of grant and terminate at the earlier of the date of exercise or seven years from the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. The expected life of an option is estimated based on historical exercise behavior. Volatility assumptions are estimated based on the average of historical volatility over the previous three years measured from the grant date. Risk-free interest rates are based on U.S. Government Zero Coupon Bonds with a maturity corresponding to the Safe Harbor term. The dividend yield is based on the previous four quarters to the date of grant divided by the average stock price for the previous 200 days. Expected forfeiture rates are estimated based on historical forfeiture experience. We used the following weighted-average assumptions to estimate the fair value of stock options granted during 2015 and 2014.

 

   

2015

   

2014

 

Expected option life - years

    4.5       4.5  

Volatility

    41.05 %     40.36 %

Risk-free interest rate

    1.30 %     1.55 %

Dividend yield

    0 %     2.10 %

  

 
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The following table summarizes the stock option activity of our stock incentive plans in the indicated periods:

  

   

2015

   

2014

   

2013

 
   

Shares

   

Weighted

Average

Exercise

Price

   

Shares

   

Weighted

Average

Exercise

Price

   

Shares

   

Weighted

Average

Exercise

Price

 

Outstanding at beginning of year

    140,293     $ 41.68       112,054     $ 41.02       20,000     $ 14.11  

Granted

    165,879       12.45       36,394       44.19       113,462       40.99  

Forfeitures

    (84,153 )     26.89       (8,155 )     42.55       (1,408 )     38.93  

Exercised

    -       -       -       -       (20,000 )     14.11  

Outstanding at end of year

    222,019     $ 27.01       140,293     $ 41.68       112,054     $ 41.02  

Exercisable shares and weighted average exercise price

    57,859     $ 42.05       37,351     $ 41.02       112,054     $ 41.02  
                                                 

Shares available for future grants at December 31:

                                               

2011 Director Plan

    54,537               78,582               93,772          

2010 Plan

    -               -               378,374          

2014 Plan

    360,438               982,548               -          

  

       

Outstanding

   

Exercisable

 
               

Weighted

   

Weighted

           

Weighted

 
               

Average

   

Average

           

Average

 

Range of Exercise Prices

 

Shares

   

Exercise Price

   

Remaining Life

   

Shares

   

Exercise Price

 
$9.19 -

46.57

    220,619     $ 27.01       -       140,293     $ 41.68  
          220,619     $ 27.01               140,293     $ 41.68  

 

The restrictions related to restricted stock awards terminate at the end of three years from the date of grant and the value of the restricted shares is amortized to expense over that period. Total amortization of stock based compensation related to restricted stock was $5.9 million, $6.6 million and $8.9 million for the years ended December 31, 2015, 2014 and 2013, respectively. Total stock based compensation for stock options was $0.6 million, $0.5 million and $0.3 million at December 31, 2015, 2014 and 2013, respectively. As of December 31, 2015, the total unrecognized compensation expense for unvested restricted stock awards was $9.7 million, and for unexercisable stock options was $0.7 million. This expense is expected to be recorded over a weighted-average period of 1.2 years.

 

 
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ESPP

 

We have an employee stock purchase plan, or ESPP, that is available to all of our U.S. employees and certain subsidiaries and is qualified under Section 423 of the Internal Revenue Code. At the end of each fiscal quarter, or Option Period, during the term of the ESPP, the employee contributions are used to acquire shares of our Class A common stock at 85% of the fair market value of the Class A common stock on the first or the last day of the Option Period, whichever is lower. We adopted FASB ASC 718, Stock Compensation, and expense these costs as compensation. Total compensation expense related to the ESPP was $0.2 million, $0.2 million and $0.2 million during the years ended December 31, 2015, 2014 and 2013, respectively. We have authorized the issuance of up to 266,659 shares of Class A common stock through these plans. At December 31, 2015, there were 84,584 shares remaining in reserve for future issuance. See Note 1 “Nature of Operations and Summary of Significant Accounting Policies – Stock-Based Compensation.”

 

U.K. ESPP

 

Certain employees of our U.K. subsidiaries participate in a share incentive plan, which is similar to our ESPP but contains certain provisions designed to meet the requirements of the U.K. tax authorities. The shares purchased by our U.K. employees through the share incentive plan are currently issued through our 2010 Omnibus Equity Incentive Plan, and were previously issued under our 1997 Incentive Equity Plan.

 

Deferred Compensation Plan

 

We maintain a deferred compensation plan, or DC Plan. Under the DC Plan, a portion of the compensation for certain of our key employees, including officers, and non-employee directors can be deferred for payment after retirement or termination of employment. Under the DC Plan, deferred compensation can be used to purchase our Class A common stock or may be retained by us and earn interest at prime plus 2%. The first 7.5% of compensation deferred must be used to purchase our Class A common stock and may be matched by us. At December 31, 2015, a total of $4.4 million had been deferred into the prime plus 2% portion of the plan, which is included in our consolidated balance sheet.

 

We have established a “Rabbi” trust to hold the stock portion of benefits under the DC Plan. The funds provided to the trust are invested by a trustee independent of us in our Class A common stock, which is purchased by the trustee on the open market. The assets of the trust are available to satisfy the claims of all general creditors in the event of bankruptcy or insolvency. Accordingly, the common stock held by the trust and our liabilities under the DC Plan are included in the accompanying consolidated balance sheets as treasury stock and deferred compensation expense. Dividend equivalents are paid on the stock units at the same rate as dividends on our common stock and are re-invested as additional stock units based upon the fair market value of a share of our Class A common stock on the date of payment of the dividend.

 

(9) EMPLOYEE BENEFIT PLANS

 

401(k) 

 

We offer a 401(k) plan to all of our U.S. employees and provide matching contribution to those employees that participate. The matching contributions paid by us totaled $1.0 million, $2.1 million and $2.0 million for the years ended December 31, 2015, 2014 and 2013, respectively. In August 2015, we suspended the matching contribution.

 

Multi-employer Pension Obligation          

 

Certain of our current and former U.K. subsidiaries are participating in a multi-employer retirement fund known as the Merchant Navy Officers Pension Fund, or MNOPF.  At December 31, 2015, we had $2.6 million accrued related to this liability, which reflects all obligations assessed on us by the fund’s trustee as of such date. We continue to have employees who participate in the MNOPF and will as a result continue to make routine payments to the fund as those employees accrue additional benefits over time.  The status of the fund is calculated by an actuarial firm every three years. The last assessment was completed in March 2015 and resulted in a significantly improved funding position, mainly due to hedging the interest rate and inflation risk, to between 65% and 80%.  The reported net deficit of the fund at March 31, 2015 was $7.5 million and, as a result, the MNOPF trustee did not propose to collect any additional deficit contributions related to the new deficit.  The amount and timing of additional potential future obligations relating to underfunding depends on a number of factors, but principally on future fund performance and the underlying actuarial assumptions. Our share of the fund’s deficit is dependent on a number of factors including future actuarial valuations, asset performance, the number of participating employers, and the final method used in allocating the required contribution among participating employers. In addition, our obligation could increase if other employers no longer participated in the plan. In the years ended December 31, 2015, 2014 and 2013 we made contributions to the plan of $0.4 million, $0.7 million and $2.5 million, respectively.  Our contributions do not make up more than five percent of total contributions to the plan.

 

In addition, we participate in the Merchant Navy Ratings Pension Fund, or MNRPF, in a capacity similar to our participation in the MNOPF.  Prior to 2013, we were not required to contribute to any deficit in the MNRPF. Due to a change in the plan rules, however, we were advised that we would be required to make contributions beginning in 2013.  An actuarial valuation was completed as of March 31, 2014 and deficit notices were communicated in the third quarter of 2015.  Our share of the deficit was calculated at $2.2 million, of which we paid $1.9 million in October 2015.  During 2015, we accrued amounts in respect of future deficit contributions.  As of December 31, 2015, the amount of this accrual was $0.5 million.

 

 
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Norwegian Pension Plans

 

The Norwegian benefit pension plans include approximately three of our office employees and 137 seamen and are defined benefit, multiple-employer plans, insured with Nordea Liv. We also instituted a defined contribution plan in 2008 for shore based personnel that existing personnel could elect to participate in while discontinuing any further obligations in the defined benefit plan. All newly hired shore based personnel are required to join the defined contribution plan. Benefits under the defined benefit plans are based primarily on participants’ years of credited service, wage level at age of retirement and the contribution from the Norwegian National Insurance. A December 31, 2015 measurement date is used for the actuarial computation of the defined benefit pension plans.

 

The following tables provide information about changes in the benefit obligation and plan assets and the funded status of the Norwegian defined benefit pension plans (in thousands):

 

   

2015

   

2014

 

Change in Benefit Obligation

               

Benefit obligation at beginning of the year

  $ 8,186     $ 9,176  

Benefit periodic cost

    416       549  

Interest cost

    169       320  

Acquisiton

    (256 )     -  

Benefits paid

    (379 )     (427 )

Actuarial (gain) loss

    (523 )     410  

Translation adjustment

    (1,219 )     (1,842 )

Benefit obligation at year end

  $ 6,394     $ 8,186  

 

   

2015

   

2014

 

Change in Plan Assets

               

Fair value of plan assets at beginning of the year

  $ 6,159     $ 7,088  

Actual return on plan assets

    185       308  

Contributions

    541       622  

Acquisition

    (196 )     -  

Benefits paid

    (250 )     (264 )

Administrative fee

    (61 )     (68 )

Actuarial loss

    55       (136 )

Translation adjustment

    (967 )     (1,391 )

Fair value of plan assets at end of year

  $ 5,466     $ 6,159  

 

   

2015

   

2014

 
                 

Funding status

  $ (928 )   $ (2,028 )

  

Amounts recognized in the balance sheet consist of (in thousands):

 

    December 31,   
   

2015

   

2014

 
                 

Other liabilities

  $ 1,104     $ 2,314  

 

    Year Ended December 31,  
   

2015

   

2014

 

Components of Net Period Benefit Cost

               

Service cost

$ 416     $ 549  

Interest cost

    169       320  

Return on plan assets

    (185 )     (308 )

Payroll tax

    65       89  

Administrative fee

    61       68  

Recognized net actuarial (gain) loss

    (609 )     623  

Net periodic benefit cost

  $ (83 )   $ 1,341  

 
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The vested benefit obligation is calculated as the actuarial present value of the vested benefits to which employees are currently entitled based on the employees’ expected date of separation or retirement.

  

Weighted-average assumptions

 

2015

   

2014

 

Discount rate

    2.7 %     2.3 %

Return on plan assets

    2.2 %     3.2 %

Rate of compensation increase

    1.3 %     2.8 %

 

The weighted average assumptions shown above were used for both the determination of net periodic benefit cost and the determination of benefit obligations as of the measurement date. In determining the weighted average assumptions, the overall market performance and specific historical performance of the investments of the Norwegian pension plan were reviewed. The asset allocations at the measurement date were as follows:

 

   

2015

   

2014

 

Equity securities

    7 %     7 %

Property

    14 %     14 %

Money market

    22 %     23 %

Held-to-Maturity bonds

    35 %     32 %

Bonds

    17 %     15 %

Other

    5 %     9 %

All asset categories

    100 %     100 %

 

The investment strategy focuses on providing a stable return on plan assets using a diversified portfolio of investments.

 

The projected benefit obligation and the fair value of plan assets for the Norwegian pension plan were approximately $6.4 million and $5.5 million, respectively as of December 31, 2015, and $8.2 million and $6.1 million, respectively, as of December 31, 2014. We expect to contribute approximately $0.6 million to the Norwegian pension plan in 2015. No plan assets are expected to be returned to us in 2016.

 

The following benefit payments, which reflect expected future service, as appropriate, are expected to be paid (in thousands):

  

Year ended December 31,

 

Benefit Payments

 

2016

    322  

2017

    332  

2018

    342  

2019

    352  

2020

    362  

Total

  $ 1,710  

 

(10) STOCKHOLDERS’ EQUITY

 

Common Stock

 

We are authorized by our Certificate of Incorporation, as amended, to issue two classes of common stock: Class A and Class B, and authorized 60 million of shares of each class of common stock.  Class A shares contain restrictions that, among other things, limit the maximum permitted percentage of outstanding shares of Class A common stock that may be owned or controlled in the aggregate by non-U.S. citizens to a maximum of 22 percent, collectively, or the Maritime Restrictions. Any purported transfer that would result in more than 22 percent of the outstanding shares of Class A common stock being owned (of record or beneficially) or controlled by non-U.S. citizens will be void and ineffective. In the event such transfers are unable to be voided, shares in excess of the maximum permitted percentage are subject to automatic sale by a trustee appointed by us or, if such sale is ineffective, redemption by us. In any event such non-U.S. citizen will not be entitled to any voting, dividend or distribution rights with respect to the excess shares and may be required to disgorge any profits, dividends or distributions received with respect to the excess shares. The Class B shares do not have the Maritime Restrictions noted above.  Initially, the shares of Class B common stock may only be issued upon conversion of all of the outstanding and treasury shares of our Class A common stock into shares of Class B common stock automatically following a determination by our Board of Directors that either the U.S. ownership requirements of the applicable U.S. maritime and vessel documentation laws are no longer applicable to us (or have been amended so that the Maritime Restrictions are no longer necessary) or that the elimination of such restrictions is in the best interests of our stockholders. Upon conversion of the outstanding and treasury shares of Class A common stock into outstanding or treasury shares of Class B common stock, as the case may be, such shares of Class A common stock will be canceled, will no longer be outstanding and will not be reissued. There are currently no shares of Class B common stock outstanding.

 

 
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Common Stock Issuances

 

During 2015, 101,179 shares were issued through the ESPP, generating approximately $0.7 million in proceeds. During 2014, 32,866 shares were issued, generating approximately $1.0 million in proceeds. The provisions of the ESPP are described above in Note 8 in more detail.

 

A total of 564,205 and 176,653 restricted shares of our Class A common stock were granted to certain officers and key employees in 2015 and 2014, respectively, pursuant to our 2014 and 2010 plans described above in Note 8, with an aggregate market value of $7.4 million and $7.9 million, respectively, on the grant dates.

 

Preferred Stock

 

We are authorized by our Certificate of Incorporation, as amended, to issue up to 2,000,000 shares of preferred stock, $.01 par value per share. No such shares have been issued.

 

Stock Repurchases

 

In December 2012, our Board of Directors (or Board) approved a stock repurchase program for up to a total of $100.0 million of our issued and outstanding Class A common stock. Under the program, repurchases can be made from time to time using a variety of methods, which may include open market purchases or purchases through a Rule 10b5-1 trading plan, or in privately negotiated transactions, all in accordance with SEC and other applicable legal requirements. In late 2012 and early 2013, we repurchased 373,619 shares of our Class A common stock for $13.3 million. In 2014, we repurchased 1,883,648 shares of our Class A common stock for $57.7 million. We did not repurchase any of our Class A common stock in 2015. We are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement in our ability to make certain payments beyond permitted amounts for share repurchases.

 

Dividends

 

The Board declared the following dividends for the years ended December 31:

 

   

2015

   

2014

 

Dividends Declared (in thousands)

  $ -     $ 26,214  

Dividend per share

  $ -     $ 1.00  

  

Our dividend policy is reviewed by the Board at such times as it deems appropriate in light of operating conditions, dividend restrictions of subsidiaries and investors or lenders, financial requirements, general business conditions and other factors it considers relevant. In each quarter of 2014, we paid a quarterly cash dividend of $0.25 per share of our Class A common stock. In February 2015, the Board suspended dividend payments indefinitely.

 

Pursuant to the terms of the indenture governing our Senior Notes, as further described in Note 5, we may be restricted from declaring or paying any future dividends. In addition, we are limited under the terms of our Multicurrency Facility Agreement and our Norwegian Facility Agreement in our ability make certain payments beyond permitted amounts for dividends, acquisitions or share repurchases.

 

(11) FAIR VALUE MEASUREMENTS

 

Each asset and liability required to be carried at fair value is classified under one of the following criteria:

 

Level 1: Quoted market prices in active markets for identical assets or liabilities

Level 2: Observable market based inputs or unobservable inputs that are corroborated by market data

Level 3: Unobservable inputs that are not corroborated by market data

 

Financial Instruments

 

At December 31, 2015 and 2014, we had no open derivative contracts.

 

The following table presents information about our assets (liabilities) measured at fair value on a recurring and non-recurring basis as of December 31, 2014, and indicates the hierarchy we utilized to determine such fair value (in millions).

  

   

Level 1

   

Level 2

   

Level 3

   

Total

 

Asset Held For Sale

  $ -     $ 0.7     $ -     $ 0.7  

 

 

 
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The asset held for sale was included in other current assets on our consolidated balance sheet as of December 31, 2014.

  

(12) OPERATING SEGMENT INFORMATION

 

Business Segments

 

We operate our business based on geographic locations and maintain three operating segments: the North Sea, Southeast Asia and the Americas. Our chief operating decision-maker regularly reviews financial information about each of these operating segments in deciding how to allocate resources and evaluate performance. The business within each of these geographic regions has similar economic characteristics, services, distribution methods and regulatory concerns. All of the operating segments are considered reportable segments under FASB ASC No. 280, “Segment Reporting.

 

Management evaluates segment performance primarily based on operating income. Cash and debt are managed centrally. Because the regions do not manage those items, the gains and losses on foreign currency remeasurements associated with these items are excluded from operating income. Management considers segment operating income to be a good indicator of each segment’s operating performance from its continuing operations, as it represents the results of the ownership interest in operations without regard to financing methods or capital structures. All significant transactions between segments are conducted on an arms-length basis based on prevailing market prices and are accounted for as such.

  

 
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Operating income and other information regularly provided to our chief operating decision-maker is summarized in the following table (all amounts in thousands):

  

   

North

Sea

   

Southeast

Asia

   

Americas

   

Other

   

Total

 

Year Ended December 31, 2015

                                       

Revenue

  $ 142,168     $ 35,524     $ 97,114     $ -     $ 274,806  

Direct operating expenses

    84,474       16,483       68,880       -       169,837  

Drydock expense

    4,112       4,356       6,919       -       15,387  

General and administrative expense

    9,469       4,296       9,906       23,609       47,280  

Depreciation and amortization

    28,724       10,419       29,827       3,621       72,591  

Impairment charge

    22,919       -       129,184       -       152,103  

Gain on sale of assets and other

    1,244       (59 )     (25 )     -       1,160  

Operating income (loss)

  $ (8,774 )   $ 29     $ (147,577 )   $ (27,230 )   $ (183,552 )
                                         

Cash and cash equivalents

  $ 12,930     $ 4,911     $ 1,221     $ 2,877     $ 21,939  

Long-lived assets(a)(b)

    544,904       216,477       499,083       6,023       1,266,487  

Total assets

    589,934       232,356       529,654       19,326       1,370,270  

Capital expenditures

    5,992       253       26,602       2,581       35,428  
                                         

Year Ended December 31, 2014

                                       

Revenue

  $ 225,253     $ 64,753     $ 205,763     $ -     $ 495,769  

Direct operating expenses

    113,140       22,831       100,273       -       236,244  

Drydock expense

    9,094       4,400       11,346       -       24,840  

General and administrative expense

    17,226       5,387       12,837       27,278       62,728  

Depreciation and amortization

    32,440       11,168       28,789       2,939       75,336  

Impairment charge

    8,551       444       -       -       8,995  

Gain on sale of assets and other

    (3,260 )     (9,200 )     (1,579 )     -       (14,039 )

Operating income (loss)

  $ 48,062     $ 29,723     $ 54,097     $ (30,217 )   $ 101,665  
                                         

Cash and cash equivalents

  $ 19,345     $ 15,126     $ 7,959     $ 8,355     $ 50,785  

Long-lived assets(a)(b)

    627,728       226,920       638,706       7,064       1,500,418  

Total assets

    725,078       263,487       700,558       27,232       1,716,355  

Capital expenditures

    109,152       459       45,402       3,413       158,426  
                                         

Year Ended December 31, 2013

                                       

Revenue

  $ 184,287     $ 64,709     $ 205,608     $ -     $ 454,604  

Direct operating expenses

    97,293       23,938       96,191       -       217,422  

Drydock expense

    10,058       5,612       8,424       -       24,094  

General and administrative expense

    13,884       5,673       11,415       23,555       54,527  

Depreciation and amortization

    23,410       11,432       26,661       2,452       63,955  

(Gain) loss on sale of assets

    (6,107 )     82       115       40       (5,870 )

Operating income (loss)

  $ 45,749     $ 17,972     $ 62,802     $ (26,047 )   $ 100,476  
                                         

Cash and cash equivalents

  $ 23,344     $ 13,839     $ 18,018     $ 5,365     $ 60,566  

Long-lived assets(a)(b)

    659,109       253,711       624,386       6,821       1,544,027  

Total assets

    748,248       292,611       716,963       15,470       1,773,292  

Capital expenditures

    153,759       2,102       101,265       4,741       261,867  

  

(a)    Goodwill is included in the North Sea segment.

 

(b)    Vessels under construction are included in other until delivered. Revenue, long-lived assets and capital expenditures presented in the table above are allocated to segments based on the location the vessel is employed, which in some instances differs from the segment that legally owns the vessel. In 2015, we had $73.4 million in revenue and $431.7 million in long-lived assets attributed to the United States, our country of domicile. In 2014, we had $152.0 million in revenue and $519.8 million in long-lived assets attributed to the United States. In 2013, we had $152.8 million in revenue and $497.0 million in long-lived assets attributed to the United States.

 

 
84

 

 

(13) UNAUDITED QUARTERLY FINANCIAL DATA

 

Summarized quarterly financial data for the two years ended December 31, 2015 and 2014 are as follows:

  

   

Quarter

 
   

First

   

Second

   

Third

   

Fourth

 
   

(In thousands, except per share amounts)

 

2015

                               

Revenues

  $ 89,092     $ 74,461     $ 60,668     $ 50,585  

Operating income

    (558 )     (4,207 )     (167,081 )     (11,706 )

Net income

    (5,126 )     (8,245 )     (185,226 )     (16,638 )

Per share (basic)

    (0.21 )     (0.33 )     (7.48 )     (0.67 )

Per share (diluted)

    (0.21 )     (0.33 )     (7.48 )     (0.67 )
                                 

2014

                               

Revenues

  $ 119,600     $ 131,365     $ 128,686     $ 116,118  

Operating income

    23,244       22,890       34,791       20,740  

Net income

    16,557       14,199       24,344       7,275  

Per share (basic)

    0.63       0.54       0.92       0.29  

Per share (diluted)

    0.63       0.54       0.92       0.29  

 

 
85

 

 

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 

NONE

 

ITEM 9A. Controls and Procedures

 

Disclosure Controls and Procedures

 

We maintain disclosure controls and procedures that are designed to provide reasonable assurance that information required to be disclosed in our reports under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to management, including our Principal Executive Officer and Principal Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Principal Executive Officer and Principal Financial Officer, has evaluated the effectiveness of our disclosure controls and procedures as of the end of the fiscal year covered by this Annual Report on Form 10-K. Our Principal Executive Officer and Principal Financial Officer have concluded that, as of the end of the period covered by this Annual Report on Form 10-K, our disclosure controls and procedures were effective at the reasonable assurance level.

 

Management’s Annual Report on Internal Control over Financial Reporting

 

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Exchange Act Rule 13a-15(f). Our internal control over financial reporting is a process designed under the supervision of our Principal Executive Officer and Principal Financial Officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external purposes in accordance with generally accepted accounting principles.

 

Our management assessed the effectiveness of our internal control over financial reporting at December 31, 2015, and in making this assessment, used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control-Integrated Framework (2013). Based on this assessment, management determined that our internal control over financial reporting was effective as of December 31, 2015.

 

KPMG LLP, our independent registered public accounting firm that audited the consolidated financial statements included in this Annual Report on Form 10-K, has issued a report with respect to our internal control over financial reporting as of December 31, 2015.

 

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

 

Changes in Internal Control Over Financial Reporting

 

 There were no changes in our internal control over financial reporting during the quarter ended December 31, 2015 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

 

ITEM 9B. Other Information

 

NONE

 

PART III

 

ITEM 10. Directors, Executive Officers and Corporate Governance(1)

 

ITEM 11. Executive Compensation(1)

 

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters(1)

 

ITEM 13. Certain Relationships and Related Transactions, and Director Independence(1)

 

ITEM 14. Principal Accounting Fees and Services(1)

 

(1) The information required by ITEMS 10, 11, 12, 13 and 14 will be included in our definitive proxy statement to be filed with the Securities and Exchange Commission within 120 days of the close of our fiscal year and is hereby incorporated by reference herein.

 

 
86

 

 

PART IV

 

ITEM 15. Exhibits, Financial Statement Schedules

 

(a)

Exhibits, Financial Statements and Financial Statement Schedules.

 

 

(1)

and (2) Financial Statements and Financial Statement Schedules.

 

Consolidated Financial Statements of the Company are included in Part II, Item 8 “Financial Statements and Supplementary Data.” All schedules have been omitted because the required information is not present or not present in an amount sufficient to require submission of the schedule, or because the information required is included in the Consolidated Financial Statements or the notes thereto.

 

(3) Exhibits

 

See “Exhibit Index” below which is filed as part of this Annual Report on Form 10-K.

 

 
87

 

 

SIGNATURES

 

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned, hereunto duly authorized.

 

 

GulfMark Offshore, Inc.

 

 

 

 

 

 

 

 

 

 

By:

/s/ Quintin V. Kneen

 

 

 

Quintin V. Kneen

 

 

 

Chief Executive Officer, President and Director

 

    (Principal Executive Officer)  

 

Date: February 29, 2016

 

Pursuant to the requirements of the Securities Exchange Act of 1934, this report had been signed below by the following persons on behalf of the Registrant and in the capacities and on the dates indicated:

  

/s/   Quintin V. Kneen

Chief Executive Officer, President and Director

February 29, 2016

Quintin V. Kneen

(Principal Executive Officer)

 
     

/s/   James. M. Mitchell

Executive Vice President and Chief Financial Officer

February 29, 2016

James M. Mitchell

(Principal Financial Officer)

 
     

/s/   Samuel R. Rubio

Senior Vice President, Controller and Chief Accounting Officer

February 29, 2016

Samuel R. Rubio

(Principal Accounting Officer)

 
     

/s/   David J. Butters

Director

February 29, 2016

David J. Butters

   
     

/s/   Peter I. Bijur

Director

February 29, 2016

Peter I. Bijur

   
     

/s/   Brian R. Ford

Director

February 29, 2016

Brian R. Ford

   
     

/s/   Sheldon S. Gordon

Director

February 29, 2016

Sheldon S. Gordon

   
     

/s/   Steven W. Kohlhagen

Director

February 29, 2016

Steven W. Kohlhagen

   
     

/s/   William C. Martin

Director

February 29, 2016

William C. Martin    
     
/s/   Rex C. Ross Director February 29, 2016
Rex C. Ross    
     

/s/   Charles K. Valutas

Director

February 29, 2016

Charles K. Valutas    

 

 
88

 

 

EXHIBIT INDEX

 

 

 

 

Exhibit

 

 

 

 

Description

 

Filed Herewith or

Incorporated by Reference

from the

Following Documents

         

3.1

 

Certificate of Incorporation, as amended

 

Exhibit 3.1 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

       

3.2

 

Bylaws, as amended

 

Exhibit 3.2 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

       

4.1

 

Description of GulfMark Offshore, Inc. Common Stock

 

Exhibit 4.1 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

       

4.2

 

Form of U.S. Citizen Stock Certificate

 

Exhibit 4.2 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

       

4.3

 

Form of Non-U.S. Citizen Stock Certificate

 

Exhibit 4.3 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

4.4

 

Indenture, dated as of March 12, 2012, between GulfMark Offshore, Inc., as issuer, and U.S. Bank National Association, as trustee, including a form of the Company’s 6.375% Senior Notes due 2022

 

Exhibit 4.1 to our current report on Form 8-K filed on March 12, 2012 (SEC File No. 001-33607)

 

 

       

4.5

 

See Exhibit No. 3.1 for provisions of the Certificate of Incorporation and Exhibit 3.2 for provisions of the Bylaws defining the rights of the holders of Common Stock

 

Exhibits 3.1 and 3.2 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

 

       

10.1

 

GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*

 

Exhibit A to our Proxy Statement on Form DEF 14A filed on April 30, 2010 (SEC File No. 001-33607)

 

       

10.2

 

Amendment No. 1 to the GulfMark Offshore, Inc. 2010 Omnibus Equity Incentive Plan*

 

Exhibit 10.2 to our current report on Form 8-K filed on June 11, 2010 (SEC File No. 001-33607)

 

       

10.3

 

Form of Notice of Stock Option Award and Form of Stock Option Agreement (2010 Omnibus Equity Incentive Plan)*

 

Exhibit 10.3 to our current report on Form 8-K filed on June 11, 2010 (SEC File No. 001-33607)

 

       

10.4

 

Form of Notice of Restricted Stock Award and Form of Restricted Stock Agreement (2010 Omnibus Equity Incentive Plan)*

 

Exhibit 10.4 to our current report on Form 8-K filed on June 11, 2010 (SEC File No. 001-33607)

 

       

10.5

 

GulfMark Offshore, Inc. 2014 Omnibus Equity Incentive Plan*

 

Exhibit 10.1 to our current report on Form 8-K filed on June 5, 2014

 

       

10.6

 

Form of Notice of Stock Option Award and Form of Stock Option Agreement (2014 Omnibus Equity Incentive Plan).*

 

Exhibit 10.2 to our current report on Form 8-K filed on June 5, 2014

 

       

10.7

 

Form of Notice of Restricted Stock Option Award and Form of Restricted Stock Option Agreement (2014 Omnibus Equity Incentive Plan).*

 

Exhibit 10.3 to our current report on Form 8-K filed on June 5, 2014

         

10.8

 

GulfMark Offshore, Inc. Deferred Compensation Plan *

 

Appendix C to our Proxy Statement on Form DEF 14A filed on April 29, 2011

 

       

10.9

 

GulfMark Offshore, Inc. 2011 Non-Employee Director Share Incentive Plan *

 

Appendix B of our Proxy Statement on Form DEF 14A filed on April 29, 2011

 

10.10

 

GulfMark Offshore, Inc. 2011 Employee Stock Purchase Plan*

 

Appendix A of our Proxy Statement on Form DEF 14A filed on April 29, 2011

         

10.11

 

Employment Agreement, dated October 14, 2009, between GulfMark Americas, Inc. and Quintin V. Kneen*

 

Exhibit 10.3 to our current report on Form 8-K filed on October 19, 2009 (SEC File No. 001-33607)

         

10.12

 

Employment Agreement, dated May 30, 2013, between James M. Mitchell and GulfMark Offshore, Inc. *

 

Exhibit 10.1 to our current report on Form 8-K filed on June 4, 2013

  

 
89

 

 

10.13

 

Change of Control Agreement, dated May 30, 2013, between James M. Mitchell and GulfMark Offshore, Inc. *

 

Exhibit 10.2 to our current report on Form 8-K filed on June 4, 2013

         

10.14

 

GulfMark Offshore, Inc. Severance Benefits Policy, effective as of August 1, 2001*

 

Exhibit 10.6 to our current report on Form 8-K filed on October 19, 2009 (SEC File No. 001-33607)

         

10.15

 

Amendment to GulfMark Offshore, Inc. Severance Benefits Policy, effective as of October 13, 2009*

 

Exhibit 10.7 to our current report on Form 8-K filed on October 19, 2009 (SEC File No. 001-33607)

         

10.16

 

Form of Indemnification Agreement*

 

Exhibit 10.2 to our current report on Form 8-K filed on February 24, 2010 (SEC File No. 001-33607)

         

10.17

 

Letter agreement between Quintin V. Kneen and GulfMark Offshore, Inc. dated March 23, 2015*

 

Exhibit 10.1 to our current report on Form 8-K filed on March 26, 2015

         

10.18

 

Letter agreement between James M. Mitchell and GulfMark Offshore, Inc. dated March 23, 2015*

 

Exhibit 10.2 to our current report on Form 8-K filed on March 26, 2015

         

10.19

 

Letter Agreement, dated October 23, 2015, between David B. Rosenwasser and GulfMark Offshore, Inc. *

 

Filed herewith

         

10.20

 

$300 Million Multicurrency Facility Agreement, dated September 26, 2014, between Gulfmark Americas, Inc., as original borrower, GulfMark Offshore, Inc., as parent and original guarantor, the Royal Bank of Scotland PLC, Wells Fargo Bank, N.A., JPMorgan Chase Bank, N.A., Bank of America, N.A., Suntrust Robinson Humphrey, Inc. and DBS Bank Ltd. as arrangers, and the Royal Bank of Scotland PLC as agent.

 

Exhibit 10.1 to our current report on Form 8-K filed on October 2, 2014

         

10.21

 

Amendment and Restatement Agreement, dated October 23, 2014, between Gulfmark Rederi AS, as borrower, the financial institutions listed on Schedule 1 thereto, as lenders, with DNB Bank ASA, as arranger, and DNB Bank ASA, as agent

 

Exhibit 10.1 to our current report on Form 8-K filed on October 29, 2014

         

10.22

 

 

NOK 600,000,000 Amended and Restated Multi-Currency Revolving Credit Facility Agreement between GulfMark Rederi AS, DNB Bank ASA and others dated October 23, 2014

 

Exhibit 10.2 to our current report on Form 8-K filed on October 29, 2014

         

10.23

 

Amendment Agreement, dated February 13, 2015, relating to $300,000,000 Multicurrency Facility Agreement originally dated September 26, 2014 between GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, the financial institutions listed in Part 2 of Schedule 1 thereto, as lenders, the arrangers party thereto, and The Royal Bank of Scotland plc, as agent of the finance parties thereto, and as security trustee for the secured parties thereunder

 

Exhibit 10.1 to our current report on Form 8-K filed on February 17, 2015

 

         

10.24

 

Second Amendment Agreement, dated July 2, 2015, relating to $300,000,000 Multicurrency Facility Agreement originally dated September 26, 2014 between GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, the financial institutions listed in Part 2 of Schedule 1 thereto, as lenders, the arrangers party thereto, and The Royal Bank of Scotland plc, as agent of the finance parties thereto, and as security trustee for the secured parties thereunder

 

Exhibit 10.1 to our current report on Form 8-K filed on July 8, 2015

 

         

10.25

 

Third Amendment Agreement, dated December 22, 2015, relating to $300,000,000 Multicurrency Facility Agreement originally dated September 26, 2014 between GulfMark Americas, Inc., as borrower, GulfMark Offshore, Inc., as guarantor, the financial institutions listed in Part 2 of Schedule 1 thereto, as lenders, the arrangers party thereto, and The Royal Bank of Scotland plc, as agent of the finance parties thereto, and as security trustee for the secured parties thereunder.

 

Exhibit 10.1 to our current report on Form 8-K filed on December 23, 2015

 

  

 
90

 

 

10.26

 

Addendum, dated February 13, 2015, to NOK 600,000,000 Multi-Currency Credit Facility Agreement originally dated December 27, 2012, and as amended by an Amendment and Restatement Agreement, dated October 23, 2014, between GulfMark Rederi AS and DNB Bank ASA

 

Exhibit 10.2 to our current report on Form 8-K filed on February 17, 2015

         

10.27

 

Addendum No. 2, dated July 7, 2015, to NOK 600,000,000 Multi-Currency Credit Facility Agreement, originally dated December 27, 2012, and as amended by an Amendment and Restatement Agreement, dated October 23, 2014, between GulfMark Rederi AS and DNB Bank ASA.

 

Exhibit 10.2 to our current report on Form 8-K filed on July 8, 2015

         

10.28

 

Addendum No. 3, dated January 29, 2016, to NOK 600,000,000 Multi-Currency Revolving Credit Facility Agreement, originally dated December 27, 2012 and amended and restated on October 23, 2014, as amended, between GulfMark Rederi AS and DNB Bank ASA.

 

Exhibit 10.1 to our current report on Form 8-K filed on February 4, 2016

         

12.1

 

Computation of Ratio of Earnings to Fixed Charges

 

Filed herewith

         

21.1

 

Subsidiaries of GulfMark Offshore, Inc.

 

Filed herewith

         

23.1

 

Consent of KPMG LLP

 

Filed herewith

         

31.1

 

Section 302 Certification for Q.V. Kneen

 

Filed herewith

         

31.2

 

Section 302 Certification for J.M. Mitchell

 

Filed herewith

         

32.1

 

Section 906 Certification furnished for Q.V. Kneen

 

Filed herewith

         

32.2

 

Section 906 Certification furnished for J.M. Mitchell

 

Filed herewith

         

101

 

The following materials from GulfMark Offshore, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2015, formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Comprehensive Income, (iv) Consolidated Statements of Stockholders’ Equity, (v) Consolidated Statements of Cash Flows and (vi) Notes to Consolidated Financial Statements, tagged as blocks of text.

 

Filed herewith

         
   

* Management contracts or compensatory plans or arrangements.

   

 

 

91